Index to Financial Statements

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20082010

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware  04-3072771
(State or other jurisdiction of  (I.R.S. Employer
incorporation or organization)  Identification Number)

1200 Enclave Parkway,Three Memorial City Plaza 840 Gessner Road, Suite 1400 Houston, Texas 7707777024

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

  

Name of each exchange on which registered

Common Stock, par value $.10 per share

  New York Stock Exchange

Rights to Purchase Preferred Stock

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yesx    No¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes¨    Nox

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.    Yesx    No¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yesx    No¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-Kx.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer    x

  Accelerated filer    ¨

Non-accelerated filer    ¨

  Smaller reporting company    ¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes¨    Nox

The aggregate market value of Common Stock, par value $.10 per share (“Common Stock”), held by non-affiliates as of the last business day of registrant’s most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 30, 2008)2010) was approximately $7.0$3.3 billion.

As of February 19, 2009,18, 2011, there were 103,447,221104,277,128 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 2009May 3, 2011 are incorporated by reference into Part III of this report.

 

 

 


Index to Financial Statements

TABLE OF CONTENTS

 

PART I     PagePAGE
ITEM 1  

Business

  24
ITEM 1A  

Risk Factors

  1920
ITEM 1B  

Unresolved Staff Comments

  2528
ITEM 2  

Properties

  2528
ITEM 3  

Legal Proceedings

  26
ITEM 428  Submission of Matters to a Vote of Security Holders26
  

Executive Officers of the Registrant

  2630
PART II    
ITEM 5  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities  2731
ITEM 6  

Selected Financial Data

  2933
ITEM  7  Management’s Discussion and Analysis of Financial Condition and Results of
Operations
  2933
ITEM 7A  

Quantitative and Qualitative Disclosures about Market Risk

  5251
ITEM 8  

Financial Statements and Supplementary Data

  5654
ITEM 9  Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
  109111
ITEM 9A  

Controls and Procedures

  109111
ITEM 9B  

Other Information

  110111
PART III    
ITEM 10  

Directors, Executive Officers and Corporate Governance

  110112
ITEM 11  

Executive Compensation

  110112
ITEM 12  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters  110112
ITEM 13  

Certain Relationships and Related Transactions, and Director Independence

  110112
ITEM 14  

Principal Accountant Fees and Services

  111112
PART IV    
ITEM 15  

Exhibits and Financial Statement Schedules

  111112


Index to Financial Statements

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives and other factors detailed in this document and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document. See “Forward-Looking Information” for further details.

GLOSSARY OF CERTAIN DEFINITIONSOIL AND GAS TERMS

The following is a listare abbreviations and definitions of certain terms commonly used termsin the oil and their definitionsgas industry and included within this Annual Report on Form 10-K:

Abbreviated TermAbbreviations

Definition
McfThousand cubic feet

Mmcf

Million cubic feet

Bcf

Billion cubic feet

Bbl

Barrel

Mbbls

Thousand barrels

Mcfe

Thousand cubic feet of natural gas equivalents

Mmcfe

Million cubic feet of natural gas equivalents

Bcfe

Billion cubic feet of natural gas equivalents

Mmbtu

Million British thermal units

NGL

Natural gas liquids

IndexBbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to Financial Statements
oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet of natural gas equivalent.

Mbbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet of natural gas equivalent.

Mmbtu. One million British thermal units.

Mmcf. One million cubic feet of natural gas.

Mmcfe. One million cubic feet of natural gas equivalent.

NGL.Natural gas liquids.

NYMEX. New York Mercantile Exchange.

Definitions

Developed reserves.Developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.

- 1 -


Dry Hole.Exploratory or development well that does not produce oil or gas in commercial quantities.

Exploitation activities.The process of the recovery of fluids from reservoirs and drilling and development of oil and gas properties.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, or a service well.

Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geological barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological termsstructural feature andstratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Oil. Crude oil and condensate.

Operator. The individual or company responsible for the exploration and/or production of an oil or gas well or lease.

Proved reserves. Proved reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Recompletion.An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure. The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of future price changes to the extent

- 2 -


provided by contractual arrangements in existence at year-end), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rate with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.

Undeveloped reserves. Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

The terms “developed reserves”, “development well”, “exploratory well”, “extension well”, “field”, “proved reserves”, “reserves”, “reservoir” and “undeveloped reserves” are defined by the SEC.

- 3 -


PART I

 

ITEM 1.BUSINESS

OVERVIEW

Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the development, exploitation and exploration of oil and gas properties located in the United States. In 2009, we restructured our operations by combining our Rocky Mountain and Appalachian areas to form the North America. Our four principal areas of operation areregion and combining the AppalachianAnadarko Basin onshore Gulf Coast, including south and eastwith our Texas and north Louisiana areas to form the Rocky MountainsSouth region. Certain prior period amounts and the Anadarko Basin. We also operate in the deep gas basin of Western Canada.historical descriptions have been reclassified to reflect this reorganization. Operationally, we now have fourtwo primary regional offices located in Houston, Texas; Charleston, West Virginia; Denver, Colorado;Texas and Calgary, Alberta.Pittsburgh, Pennsylvania.

In 2008, energy commodity2010, natural gas prices increased to all-time highdecreased from the price levels for the first half of the year and then quickly declined to 2007 levelsexperienced during the second half of 2008.2009, while crude oil prices increased. Our 20082010 average realized natural gas price was $8.39$5.54 per Mcf, 16% higher26% lower than the 20072009 average realized price of $7.23$7.47 per Mcf. Our 20082010 average realized crude oil price was $89.11$97.91 per Bbl, 33%14% higher than the 20072009 average realized price of $67.16$85.52 per Bbl. These realized prices include realized gains and losses resulting from commodity derivatives (zero-cost collars or swaps).derivatives. For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” section in Item 7 of this Annual Report on Form 10-K.

In 2008, we pursued and completed the largest2010, our investment program in our history, totaling $1,481.0 million. This included our largest producing property acquisition ($625.0 million),totaled $891.5 million, including lease acquisition ($152.7130.7 million) and drilling and facilities ($624.3654.2 million) programs. The producing property and lease acquisition activity were funded by issuances of new long-term debt and common stock during the year. TheOur capital spending (excluding the acquisition activity) was funded largely through cash on hand, operating cash flow, from operations and, to a lesser extent, borrowings on our revolving credit facility.facility, proceeds from our new senior notes offering and select asset sales.

We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure that we have sufficient liquidity, including cash resources and we intend to maintain spending discipline.available credit. We believe these strategies continue to beare appropriate for our portfolio of projects and the current industry environment and will continue to add shareholder value over the long-term.

In December 2010, we believesold our balance sheetexisting Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and availability undertwo compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million and recognized a $49.3 million gain on sale of assets. Under the terms of the purchase and sale agreement, we are obligated to construct pipelines to connect certain of our 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. We expect to complete these obligations in the first half of 2011. We 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 in Susquehanna County, and build two compressor stations in the next two years. Additionally, Williams will connect all of our drilling program wells, which will connect our production to five interstate pipeline delivery options.

In addition, in December 2010 we closed a private placement of $175 million principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 5.58%.

In September 2010, we amended and restated our revolving credit facility to increase the available credit line to $900 million and with an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide sufficient liquiditysuch increased commitment amount. The amended facility provides for a $1.5 billion borrowing base and extends the term of the agreement to pursueSeptember 2015.

- 4 -


In April 2009, we sold substantially all of our 2009 program.Canadian properties to Tourmaline Oil Corporation (Tourmaline) in exchange for cash and common stock shares of Tourmaline. In November 2010, we sold our investment in Tourmaline for $61.3 million and recognized a $40.7 million gain on sale of assets.

In 2010, we sold various other properties for total proceeds of $30.4 million and an aggregate gain of $15.3 million.

In August 2008, we completed the acquisition of producing properties, leasehold acreage and a natural gas gathering infrastructure in east Texas (the “east Texas acquisition”). We paid total net cash consideration of approximately $604.0 million (see Note 2 of the Notes to the Consolidated Financial Statements for further details).million. In order to finance the east Texas acquisition, we completed a public offering of 5,002,500 shares of our common stock in June 2008, receiving net proceeds of $313.5 million, (see Note 9 of the Notes to the Consolidated Financial Statements for further details), and we closed a private placement in July 2008 of $425 million principal amount of 6.51% weighted average senior unsecured fixed rate notes (see Note 4 of the Notes to the Consolidated Financial Statements for further details).notes.

On an equivalent basis, our production level in 20082010 increased by 11%27% from 2007.2009. We produced 95.2130.6 Bcfe, or 260.1357.9 Mmcfe per day, in 2008,2010, as compared to 85.5103.0 Bcfe, or 234.1282.1 Mmcfe per day, in 2007.2009. Natural gas production increased to 90.4125.5 Bcf in 20082010 from 80.597.9 Bcf in 20072009, primarily due to(1) increased natural gas production in the Gulf Coast region due to increased production in the Minden field, largely due toNorth region associated with the properties we acquiredincreased drilling program and the Lathrop compressor station in Susquehanna County, Pennsylvania. The decline in the east Texas acquisitionother areas is related to natural production decline. Oil production decreased by 10 Mbbls from 818 Mbbls in August 2008, and increased drilling2009 to 808 Mbbls in the County Line field,(2) increased2010 due primarily to a decrease in production in the West region associated with an increaseNorth and a decrease in the drilling program, (3) increased production in the East region due to increased drilling activity in West Virginia and northeastern Pennsylvania and(4) increased production in Canada due to the sale of our Canadian properties in April 2009, partially offset by increased drilling activityproduction in the Hinton field. Oil production decreased by 41 Mbbls from 823 Mbbls in 2007 to 782 Mbbls in 2008 due primarily to natural declines inSouth region associated with the Gulf CoastEagle Ford shale and West regions.Pettet formation production.

Index to Financial Statements

For the year ended December 31, 2008,2010, we drilled 432113 gross wells (355(87.1 net) with a success rate of 97%98% compared to 461143 gross wells (391(118.6 net) with a success rate of 96%95% for the prior year. In 2009,2011, we plan to drill approximately 148110 gross wells (122.3(83.1 net). The number of wells we plan to drill in 2009 is down from 2008 primarily due to lower commodity prices resulting from the global decline in economic activity as well as our ongoing strategy of managing our capital investment program within anticipated cash flow. We plan to concentrate, focusing our capital program for 2009 in east Texas andthe Marcellus shale in northeast Pennsylvania where opportunities for growth are currently concentrated.and the Eagle Ford shale in south Texas.

Our 20082010 total capital and exploration spending was $1.5 billion$891.5 million compared to $636.2$640.4 million of total capital and exploration spending in 2007.2009. In both 20082010 and 2007,2009, we allocated our planned program for capital and exploration expenditures among our various operating regions based on return expectations, availability of services and human resources. We plan to continue such method of allocation in 2009.2011. Funding of the program is expected to be provided by operating cash flow, existing cash and, increasedif required, borrowings under our credit facility, if required. We may also reduce our budgeted capital and exploration spending to maintain sufficient liquidity. We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position.facility. For 2009,2011, the Gulf Coast and East regions areNorth region is expected to receive approximately 90%58% of the anticipated capital program, with the majority of the remainderremaining 42% dedicated to the WestSouth region. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long-term. In 2009,2011, we plan to spend approximately $475$600 million on capital and exploration activities.

Our proved reserves totaled approximately 1,9422,701 Bcfe at December 31, 2008,2010, of which 97%98% were natural gas. This reserve level was up by 20%31% from 1,6162,060 Bcfe at December 31, 20072009 on the strength of results from our drilling program,program. In 2010, we had a net upward revision of 136.7 Bcfe, which was primarily due to an upward performance revision of 284.4 Bcfe, primarily in the increaseDimock field in northeast Pennsylvania, and an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe (115.1 Bcfe in the North region and 67.6 Bcfe in the South region) of proved undeveloped reserves that are no longer in our capital spending and the east Texas acquisition.five-year development plan.

- 5 -


The following table presents certain reserve, production and well information as of December 31, 2008.2010.

 

 West 
 East Gulf
Coast
 Rocky
Mountains
 Mid-
Continent
 Total Canada Total   North South Total 

Proved Reserves at Year End(Bcfe)

           

Developed

 613.4  317.3  201.9  178.4  380.3  37.5  1,348.5 

Developed.

   1,251.3    472.9    1,724.2  

Undeveloped

 258.4  237.3  69.5  25.5  95.0  2.8  593.5    755.9    221.0    976.9  
                               

Total

 871.8  554.6  271.4  203.9  475.3  40.3  1,942.0    2,007.2    693.9    2,701.1  

Average Daily Production(Mmcfe per day)

 69.1  104.1  41.3  33.9  75.2  11.7  260.1    223.5    134.4    357.9  

Reserve Life Index(In years)(1)

 34.4  14.6  18.0  16.4  17.3  9.5  20.4    24.6    14.1    20.7  

Gross Wells

 3,382  844  716  844  1,560  43  5,829    4,185    1,769    5,954  

Net Wells(2)

 3,162.6  592.2  329.4  594.5  923.9  16.2  4,694.9    3,588.5    1,231.1    4,819.6  

Percent Wells Operated(Gross)

 96.6% 75.0% 52.0% 78.1% 66.1% 58.1% 85.0%   89.0  76.0  85.1

 

(1)

Reserve Life Index is equal to year-end reserves divided by annual production.

(2)

The term “net” as used in “net acreage” or “net production” throughout this document refers to amounts that include only acreage or production that is owned by us and produced to our interest, less royalties and production due others. “Net wells” represents our working interest share of each well.

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 ten years. These properties are held for longer periods if production is established. We own leasehold rights on approximately 3.02.3 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our ten largest fields,field (Dimock), which are fields with 2.5% or greateris our only field that contains more than 15% of total companyour proved reserves, makeis located in northeast Pennsylvania. This field makes up approximately 53%46% of total companyour proved reserves.

Index to Financial Statements

The following table presents certain information with respect to our principal properties as of and for the year ended December 31, 2008.Dimock field:

 

  Production Volumes        
  Natural
Gas
(Mcf/
Day)
 Oil and
NGLs
(Bbls/
Day)
 Total
(Mcfe/Day)
 Proved Reserves
at Year-End
(Mmcfe)
 Gross
Producing
Wells
 Gross
Wells
Drilled
 Nature of
Interest
(Working/Royalty)

West Virginia

       

Sissonville.

 9,263 4 9,285 138,484 445 61 W/R

Pineville

 11,456 —   11,456 105,466 299 11 W/R

Logan-Holden-Dingess

 7,359 —   7,359 84,507 217 17 W

Big Creek

 4,587 —   4,587 70,956 210 16 W

Hernshaw-Bull Creek

 3,977 —   3,977 54,624 261 14 W/R

Huff Creek

 3,639 —   3,639 51,810 124 25 W

Pensylvania

       

Dimock (Susquehanna area)

 1,653 —   1,653 66,734 22 20 W

Oklahoma

       

Mocane-Laverne

 9,989 —   9,991 64,535 242 2 W/R

East Texas

       

Brachfield Southeast (Minden area)

 23,905 412 26,373 323,886 179 29 W

Angie (County Line area)

 27,900 40 28,138 65,213 48 36 W
   Year Ended
December 31,
 
   2010   2009   2008 

Production:

      

Natural gas (Bcf)

   49.5     36.3     0.6  

Crude oil and condensate (Mbbls)

   —       —       —    

Produced Sales Price:(1)

      

Natural gas ($/Mcf)

  $4.48    $4.19    $7.28  

Crude oil and condensate ($/Bbl)

  $—      $—      $—    

Production Cost ($/Mcfe):

  $0.08    $0.03    $0.01  

(1)

Excludes realized impact of derivative instruments.

EASTNORTH REGION

The North region is comprised of the Appalachian and Rocky Mountains areas. Our East region activities in the Appalachian area are concentrated primarily in northeast Pennsylvania and in West VirginiaVirginia. Our activities in the Rocky Mountains area are concentrated in the Green River and Pennsylvania.Washakie Basins in Wyoming. This region is managed from our office in Charleston, West Virginia.Pittsburgh, Pennsylvania. In this region, our assets include a large acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. In December 2010, we sold our existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations. In July 2010, we sold our properties in the Paradox Basin in Colorado.

Capital and exploration expenditures for 20082010 were $369.6$603.6 million, or 24%68% of our total 20082010 capital and exploration expenditures, compared to $178.6$380.3 million for 2007,2009, or 28%60% of our total 20072009 capital and exploration

- 6 -


expenditures. This increase in spending was substantially driven by a $103.1 million increasean expanded Marcellus horizontal drilling program in lease acquisition costs year-over-year.northeast Pennsylvania to hold acreage. For 2009,2011, we have budgeted approximately $200$350.0 million for capital and exploration expenditures in the region.

At December 31, 2008,2010, we had 3,3824,185 wells (3,162.6(3,588.5 net), of which 3,2683,724 wells are operated by us. There are multiple producing intervals in the Appalachian area that includeincludes the Big Lime, Weir, Berea and Devonian (including Marcellus) Shaleshale formations at depths primarily ranging from 1,100950 to 9,5007,800 feet, with an average depth of approximately 4,1004,050 feet. Average net daily productionIn the Rocky Mountains area, principal producing intervals are in 2008 was 69.1 Mmcfe. the Almond, Frontier and Dakota formations at depths ranging from 8,100 to 14,375 feet, with an average depth of approximately 11,050 feet.

Natural gas production and crude oil/condensate/NGL production for 2008 was 25.2 Bcf and 23 Mbbls, respectively.

While natural gas production volumes from East reservoirsreserves in the North region are relatively low on a per-well basis compared to other areas ofprimarily associated with the United States, the productive life of East region reserves is relatively long.Marcellus shale. At December 31, 2008,2010, we had 871.82,007.2 Bcfe of proved reserves (substantially all natural gas) in the EastNorth region, constituting 45%74% of our total proved reserves. Developed and undeveloped reserves made up 613.41,251.3 Bcfe and 258.4755.9 Bcfe of the total proved reserves for the EastNorth region, respectively. While no properties are individually significant to our company as a whole, the Sissonville, Pineville, Logan-Holden-Dingess, Big Creek, Hernshaw-Bullcreek, and Huff Creek fields in West Virginia and the Dimock field in the Susquehanna area of Pennsylvania are included in our ten largest fields and together contain approximately 30% of our total company proved equivalent reserves.

Index to Financial Statements

In 2008,2010, we drilled 21263 wells (205.4(61.3 net) in the EastNorth region, of which 20862 wells (201.4(60.3 net) were development and extension wells. In 2009,2011, we plan to drill approximately 6354 wells (62.8(54.0 net), primarily in the Dimock field.field in northeast Pennsylvania.

In 2008,2010, we produced and marketed approximately 62221.8 Mmcf per day of natural gas and 272.5 barrels of crude oil/condensate/NGL per day in the EastNorth region at market responsive prices. Average daily production in 2010 was 223.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2010 was 81.0 Bcf and 100 Mbbls, respectively.

Ancillary to our exploration, development and production operations, we operated a number of gas gathering and transmission pipeline systems, made up of approximately 3,2003,148 miles of pipeline with interconnects to three interstate transmission systems and seven local distribution companies and numerous end users as of the end of 2008.2010. 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 in West Virginia 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 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 EastNorth region. The pipeline systems and storage fields are fully integrated with our operations.

The principal markets for our EastNorth region natural gas are in the northeastnortheastern and northwestern 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 70%42% of our natural gas sales volume in the EastNorth region is sold at index-based prices under contracts with a termterms of one year or greater. In addition, spotThe remaining 58% of our natural gas sales volume is sold under contracts with terms less than one year. 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 one percent of East production is sold on fixed price contracts that typically renew annually.

- 7 -


GULF COASTSOUTH REGION

Our development, exploitation, exploration and production activities in the Gulf CoastSouth region are primarily concentrated in east and south Texas and north Louisiana.Oklahoma. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Haynesville, Bossier, and James Lime formations in north Louisiana and east Texas, and the Eagle Ford, Frio, Vicksburg and Wilcox formations in south Texas and the Chase, Morrow and Chester formations in the Anadarko Basin in Oklahoma at measured depths ranging from 2,200approximately 2,500 to 17,40017,700 feet, with an average depth of approximately 10,9008,950 feet. We sold our Woodford shale prospect located in Oklahoma in June 2010 and certain oil and gas properties in the Texas panhandle in November 2010.

Capital and exploration expenditures were $962.0$280.4 million for 2008,2010, or 64%32% of our total 20082010 capital and exploration expenditures, compared to $291.5$237.6 million for 2007,2009, or 46%37% of our total 20072009 capital and exploration expenditures. This increase in capital spending includes the $604.0 million paid for the east Texas acquisition. Of the total company year-over-year increase in capital and exploration expenditures, approximately 79% was attributableis primarily due to an increaselease acquisitions to establish a greater position in the Gulf Coast region spending.oil window of the Eagle Ford shale. For 2009,2011, we have budgeted approximately $230

Index to Financial Statements

$250 million for capital and exploration expenditures in the region. Our 2009 Gulf Coast2011 South region drilling program will emphasize activity primarily in eastthe Eagle Ford shale in south Texas.

We had 8441,769 wells (592.2(1,231.1 net) in the Gulf CoastSouth region as of December 31, 2008,2010, of which 6331,345 wells are operated by us. Average daily production in 20082010 was 104.1134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 20082010 was 34.644.5 Bcf and 585759 Mbbls, respectively.

At December 31, 2008,2010, we had 554.6693.9 Bcfe of proved reserves (93% natural gas) in the Gulf CoastSouth region, which represented 29%26% of our total proved reserves. Developed and undeveloped reserves made up 317.3472.9 Bcfe and 237.3221.0 Bcfe of the total proved reserves for the Gulf CoastSouth region, respectively. While no properties are individually significant to our company as a whole, the Brachfield Southeast field in the Minden area and the Angie field in the County Line area, both in east Texas, are included in our ten largest fields based on percentage of our total company proved equivalent reserves and together contain approximately 20% of our total company proved equivalent reserves.

In 2008,2010, we drilled 9450 wells (63.9(25.8 net) in the Gulf CoastSouth region, of which 8347 wells (57.1(23.3 net) were development and extension wells. In 2009,2011, we plan to drill 6556 wells (47.4(29.1 net), primarily in east Texas, including the Minden and County Line fields.Eagle Ford shale in south Texas.

Our principal markets for Gulf Coastthe South region natural gas are in the industrialized Gulf Coast area and the northeastMidwestern United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 70%83% of our natural gas sales volumes in the Gulf CoastSouth region are sold at index-based prices under contracts with terms of one year or greater. The remaining 30%17% of our natural gas sales volumes are sold at index-based prices under short-term agreements. The Gulf CoastSouth region properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

In 2008,2010, we produced and marketed approximately 1,598122.0 Mmcf per day of natural gas and 2,079.1 barrels of crude oil/condensate/NGL per day in the Gulf CoastSouth 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, 2008, we had 475.3 Bcfe of proved reserves (97% natural gas) in the West region, constituting 24% of our total proved reserves. Developed and undeveloped reserves made up 380.3 Bcfe and 95.0 Bcfe of the total proved reserves for the West region, respectively. While no properties are individually significant to our company as a whole, the Mocane-Laverne field in Oklahoma in the Mid-Continent area is included within our ten largest fields and contains approximately three percent 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 90% 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 nine percent of the natural gas production is sold under short-term arrangements at index-based prices, and the remaining one 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 2008, we produced and marketed approximately 451 barrels of crude oil/condensate/NGL per day in the West region at market responsive prices.

Index to Financial Statements

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, 2008, we had 271.4 Bcfe of proved reserves (96% natural gas) in the Rocky Mountains area, or 14% of our total proved reserves.

Capital and exploration expenditures in the Rocky Mountains were $88.7 million for 2008, or six percent of our total 2008 capital and exploration expenditures, compared to $54.7 million for 2007, or nine percent of our total 2007 capital and exploration expenditures. For 2009, we have budgeted approximately $29 million for capital and exploration expenditures in the area.

We had 716 wells (329.4 net) in the Rocky Mountains area as of December 31, 2008, of which 372 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 4,200 to 14,375 feet, with an average depth of approximately 10,900 feet. Average net daily production in the Rocky Mountains during 20082010 was 41.3134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 20082010 was 14.544.5 Bcf and 95759 Mbbls, respectively.

In 2008, we drilled 49 wells (31.3 net) in the Rocky Mountains, of which 47 wells (30.8 net) were development wells. In 2009, we plan to drill 8 wells (5.9 net), 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, 2008, we had 203.9 Bcfe of proved reserves (98% natural gas) in the Mid-Continent area, or 10% of our total proved reserves.

Capital and exploration expenditures were $60.3 million for 2008, or four percent of our total 2008 capital and exploration expenditures, compared to $54.5 million for 2007, or eight percent of our total 2007 capital and exploration expenditures. For 2009, we have budgeted approximately $10 million for capital and exploration expenditures in the area.

As of December 31, 2008, we had 844 wells (594.5 net) in the Mid-Continent area, of which 659 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 17,450 feet, with an average depth of approximately 7,050 feet. Average net daily production in 2008 was 33.9 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2008 was 12.0 Bcf and 70 Mbbls, respectively.

In 2008, we drilled 71 wells (50.6 net) in the Mid-Continent, all of which were development and extension wells. In 2009, we plan to drill 12 wells (6.1 net), primarily in Oklahoma, including the Gage and Cederdale Northeast fields.

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 Province of Alberta. At December 31, 2008, we had 40.3 Bcfe of proved reserves (97% natural gas) in the Canada region, constituting two percent of our total proved reserves. Developed and undeveloped reserves made up 37.5 Bcfe and 2.8 Bcfe of the total proved reserves for the Canada region, respectively. No properties in the Canada region are individually significant to our company as a whole. The largest field in this region is the Hinton field in Alberta, which is not included in our ten largest fields.

Capital and exploration expenditures in Canada were $25.4 million for 2008, or two percent of our total 2008 capital and exploration expenditures, compared to $55.1 million for 2007, or nine percent of our total 2007

Index to Financial Statements

capital and exploration expenditures. For 2009, we have budgeted approximately $1 million for capital and exploration expenditures in the area.

We had 43 wells (16.2 net) in the Canada region as of December 31, 2008, of which 25 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 8,500 to 14,500 feet, with an average depth of approximately 11,050 feet. Average net daily production in Canada during 2008 was 11.7 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2008 was 4.1 Bcf and 21 Mbbls, respectively.

In 2008, we drilled six wells (3.4 net) in Canada, of which four wells (2.6 net) were development and extension wells. In 2009, we do not plan to drill any wells in Canada.

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 2008, we produced and marketed approximately 59 barrels of crude oil/condensate per day in the Canada region at market responsive prices.

RISK MANAGEMENT

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 20082010 we employed natural gas and crude oil price collar and swap agreements for portions of our 2008 through 2010 production to attempt to manage price risk more effectively. In 2007During 2010, we also entered into crude oil swaps to hedge our price exposure on our 2010 production, natural gas swaps to hedge our price exposure on our 2011 production and 2006, we primarily employedcrude oil price collars to hedge our price exposure on our 2011 production. In addition, we also have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting. In 2009 and 2008, we employed price collars and swaps to hedge our price exposure on our production.

- 8 -


The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place.

For 2008, collars2010, swaps covered 60%29% of natural gas production and had a weighted-average floor of $8.53 per Mcf and a weighted-average ceiling of $10.70 per Mcf. At December 31, 2008, natural gas price collars for the year ending December 31, 2009 will cover 47,253 Mmcf of production at a weighted-average floor of $9.40 per Mcf and a weighted-average ceiling of $12.39 per Mcf. For 2008, collars covered 47%90% of crude oil production and had a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.

For 2008, swaps covered 11% of natural gas production and had a weighted-average price of $10.27 per Mcf. At December 31, 2008, natural gas price swaps for the years ending December 31, 2009 and 2010 will cover 16,079 Mmcf and 19,295 Mmcf of production, respectively, at a weighted-average price of $12.18$9.30 per Mcf and $11.43$104.25 per Mcf,Bbl, respectively. For 2008, a swap covered 12%

As of crude oil production and had a fixed price of $127.15 per Bbl. Crude oil price swaps for the years ending December 31, 2009 and 2010, will cover 365 Mbbls each at a fixed price of $125.25 per Bbl and $125.00 per Bbl, respectively. Our decision to hedge 2009 and 2010 production fits with our risk management strategy and allows us to lock inwe had the benefit of highfollowing outstanding commodity prices on a portion of our anticipated production. During January 2009, we entered into basis swaps in the Gulf Coast region that will cover 16,079 Mmcf of anticipated 2012 natural gas production at fixed basis differentials per Mcf of $(0.26) to $(0.27).derivatives:

Commodity and Derivative Type

Weighted-Average
Contract Price

VolumeContract Period

Derivatives Designated as Hedging Instruments

Natural Gas Swaps

$6.24 per Mcf12,909 MmcfJanuary - December 2011

Crude Oil Collars

$93.25 Ceiling /$80.00 Floor per Bbl365 MbblJanuary - December 2011

Derivatives Not Designated as Hedging Instruments

Natural Gas Basis Swaps

$(0.27) per Mcf16,123 MmcfJanuary - December 2012

We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk” for further discussion concerning our use of derivatives.

Index to Financial Statements

RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2008.2010.

 

  Natural Gas (Mmcf) Liquids(1) (Mbbl) Total(2) (Mmcfe)
  Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total

East

 611,284 258,379 869,663 355 —   355 613,412 258,379 871,791

Gulf Coast

 292,626 223,446 516,072 4,114 2,306 6,420 317,311 237,280 554,591

Rocky Mountains

 194,117 67,817 261,934 1,296 279 1,575 201,893 69,491 271,384

Mid-Continent

 173,726 25,426 199,152 784 5 789 178,426 25,458 203,884

Canada

 36,402 2,770 39,172 179 23 202 37,479 2,908 40,387
                  

Total

 1,308,155 577,838 1,885,993 6,728 2,613 9,341 1,348,521 593,516 1,942,037
                  
   Natural  Gas
(Mmcf)
   Liquids(1)
(Mbbl)
   Total(2)
(Mmcfe)
 

Developed:

      

North

   1,243,051     1,373     1,251,289  

South

   438,400     5,756     472,936  

Undeveloped:

      

North

   755,767     22     755,899  

South

   206,940     2,340     220,978  
               

Total

   2,644,158     9,491     2,701,102  
               

 

(1)

Liquids include crude oil, condensate and natural gas liquids.

(2)

Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.

Our reserve estimates were based on decline curve extrapolations, material balance calculations, analogies, or combinations of these methods for each well.

The proved reserve estimates presented hereherein were prepared by our petroleum engineering staff and reviewedaudited by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents made independent estimates for 100% of the proved reserves estimated by us and concluded the following: In their judgment we have an effective system for gathering data and documenting information required to estimate our proved reserves and

- 9 -


project our future revenues;revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which we used appropriate engineering, geologicrelied were adequate and evaluation principlesof sufficient quality, and techniques in accordance with practices generally accepted in(4) the petroleum industry in makingresults of our estimates and projections and our total proved reserves are, in the aggregate, reasonable. For additional information regarding estimates of proved reserves, the reviewaudit of such estimates by Miller and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the reviewaudit letter by Miller and Lents, Ltd., dated February 1, 2011, has been filed as an exhibit to this Form 10-K. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies. During 2008, we filed estimates of our oil and gas reserves for the year 2007 with the Department of Energy. These estimates differ by five percent or less from the reserve data presented. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on the economic productive life of producing rates.properties. Our reserves are based on 12-month average oil and gas index prices, in effect oncalculated as the lastunweighted arithmetic average for the first day of December 2008.the month price for each month during 2010. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.

Internal Control

Our corporate reservoir engineers report to the Director of Engineering, who maintains oversight and compliance responsibility for the internal reserve estimation process and provides oversight for the annual audit of our year-end reserves by our independent third party engineers, Miller and Lents, Ltd. Our corporate reservoir engineering group consists of two petroleum/chemical engineers, with petroleum/chemical engineering degrees and between 11 and 28 years of industry experience, between four and 28 years of reservoir engineering/management experience, and between three and 12 years managing our reserves. Both are members of the Society of Petroleum Engineers.

Qualifications of Third Party Engineers

The technical person primarily responsible for audit of our reserve estimates at Miller and Lents, Ltd. meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents, Ltd. is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

For additional information about the risks inherent in our estimates of proved reserves, see “Risk Factors—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

Index to Financial Statements

Proved Undeveloped Reserves

At December 31, 2010, we had 976.9 Bcfe of proved undeveloped reserves, which represents an increase of 241.7 Bcfe compared with December 31, 2009. For 2010, total capital related to the development of proved undeveloped reserves was $183.4 million, resulting in the conversion of 216.9 Bcfe of reserves to proved developed. During 2010, we had 391.8 Bcfe of proved undeveloped reserve additions and 249.5 Bcfe of positive proved undeveloped reserve performance revisions, primarily in the Dimock field in northeast Pennsylvania. Lastly, we removed 182.7 Bcfe (115.1 Bcfe in the North region and 67.6 Bcfe in the South region) of proved undeveloped reserves associated with drilling locations no longer anticipated to be developed within the next five years.

- 10 -


Historical Reserves

The following table presents our estimated proved reserves for the periods indicated.

 

  Natural Gas
(Mmcf)
 Oil & Liquids
(Mbbl)
 Total
(Mmcfe)(1)
   Natural  Gas
(Mmcf)
 Oil &  Liquids
(Mbbl)
 Total
(Mmcfe)(1)
 

December 31, 2005

  1,262,096  11,463  1,330,874 

December 31, 2007(5)

   1,559,953    9,328    1,615,919  
                    

Revision of Prior Estimates(2)

  (17,675) 673  (13,640)   (47,745  (1,593  (57,302

Extensions, Discoveries and Other Additions

  246,197  1,066  252,594    297,089    1,134    303,895  

Production

  (79,722) (1,415) (88,212)

Production.

   (90,425  (794  (95,191

Purchases of Reserves in Place

  1,946  38  2,176    167,262    1,268    174,872  

Sales of Reserves in Place

  (44,549) (3,852) (67,663)   (141  (2  (156
                    

December 31, 2006

  1,368,293  7,973  1,416,129 

December 31, 2008(5)

   1,885,993    9,341    1,942,037  
                    

Revision of Prior Estimates(3)

  2,604  771  7,228    (193,767  (1,062  (200,143

Extensions, Discoveries and Other Additions

  265,830  1,381  274,114    459,612    544    462,880  

Production

  (80,475) (830) (85,451)   (97,914  (844  (102,976

Purchases of Reserves in Place

  3,701  33  3,899    9    —      9  

Sales of Reserves in Place

  —    —    —      (40,771  (196  (41,949
                    

December 31, 2007

  1,559,953  9,328  1,615,919 

December 31, 2009

   2,013,162    7,783    2,059,858  
                    

Revision of Prior Estimates(2)

  (47,745) (1,593) (57,302)

Revision of Prior Estimates(4)

   139,016    (379  136,742  

Extensions, Discoveries and Other Additions

  297,089  1,134  303,895    632,980    2,944    650,644  

Production

  (90,425) (794) (95,191)   (125,474  (858  (130,622

Purchases of Reserves in Place

  167,262  1,268  174,872    593    4    617  

Sales of Reserves in Place

  (141) (2) (156)   (16,119  (3  (16,137
                    

December 31, 2008

  1,885,993  9,341  1,942,037 

December 31, 2010

   2,644,158    9,491    2,701,102  
                    

Proved Developed Reserves

        

December 31, 2005

  944,897  9,127  999,661 

December 31, 2006

  996,850  5,895  1,032,222 

December 31, 2007

  1,133,937  7,026  1,176,091    1,133,937    7,026    1,176,091  

December 31, 2008

  1,308,155  6,728  1,348,521    1,308,155    6,728    1,348,521  

December 31, 2009

   1,288,169    6,082    1,324,663  

December 31, 2010

   1,681,451    7,129    1,724,225  

Proved Undeveloped Reserves

    

December 31, 2007

   426,016    2,302    439,828  

December 31, 2008

   577,838    2,613    593,516  

December 31, 2009

   724,993    1,701    735,199  

December 31, 2010

   962,707    2,362    976,877  

 

(1)

Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of naturalgas to 1 Bbl of crude oil, condensate or natural gas liquids.

(2)

The majority of the revisions were the result of the decrease in the natural gas price.

(3)

The net downward revision of 200.1 Bcfe was primarily due to (i) downward revisions of 101.6 Bcfedue to lower 2009 oil and natural gas prices compared to 2008 and (ii) downward revisions of 120.4Bcfe due to the removal of proved undeveloped reserves scheduled for development beyond five yearsprimarily due to the application of the SEC’s oil and gas reserve calculation methodology effectivebeginning in 2009, partially offset by 21.9 Bcfe of positive performance revisions.

(4)

The net upward revision of 136.7 Bcfe was primarily due to (i) an upward performance revision of284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and (ii) an upward revision of 35.0Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of182.7 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

(5)

Prior to 2009, reserve estimates were based on year end prices.

Index to Financial Statements

- 11 -


VolumesProduction and Prices: Production CostsSales

The following table presents regional historical information about our net wellhead sales volume for natural gas and crude oil (including condensate and natural gas liquids), produced natural gas and crude oil realized sales prices, and production costs per equivalent.

 

   Year Ended December 31,
   2008  2007  2006

Net Wellhead Sales Volume

      

Natural Gas(Bcf)

      

East

   25.2   24.4   23.5

Gulf Coast

   34.6   26.8   30.0

West

   26.5   25.4   23.6

Canada

   4.1   3.9   2.6

Crude/Condensate/Ngl(Mbbl)

      

East

   23   26   24

Gulf Coast

   585   606   1,164

West

   165   180   214

Canada

   21   18   13

Produced Natural Gas Sales Price($/Mcf)(1)

      

East

  $8.54  $7.78  $7.99

Gulf Coast

   9.23   8.03   7.37

West

   7.28   6.13   6.05

Canada

   7.62   5.47   6.18

Weighted-Average

   8.39   7.23   7.13

Produced Crude/Condensate Sales Price($/Bbl)(1)

      

East

  $92.07  $66.97  $62.03

Gulf Coast

   87.39   67.17   65.44

West

   95.48   67.86   63.36

Canada

   85.08   59.96   60.55

Weighted-Average

   89.11   67.16   65.03

Production Costs($/Mcfe)(2)

      

East

  $1.61  $1.37  $1.12

Gulf Coast

   1.32   1.44   1.37

West

   1.62   1.27   1.34

Canada

   0.90   0.84   0.84

Weighted-Average

   1.48   1.36   1.31
   Year Ended December 31, 
   2010   2009   2008 

Net Wellhead Sales Volume

      

Natural Gas(Bcf)

      

North

   81.0     48.2     39.7  

South

   44.5     48.8     46.6  

Canada(3)

   —       1.0     4.1  

Crude/Condensate/Ngl(Mbbl)

      

North

   100     118     118  

South

   759     720     655  

Canada(3)

   —       7     21  

Equivalents(Bcfe)

      

North

   81.6     48.9     40.4  

South

   49.1     53.1     50.5  

Canada(3)

   —       1.0     4.3  

Produced Natural Gas Sales Price($/Mcf)(1)

      

North

  $4.59    $6.59    $7.95  

South

   7.26     8.42     8.84  

Canada(3)

   —       3.72     7.62  

Weighted-Average

   5.54     7.47     8.39  

Produced Crude/Condensate Sales Price($/Bbl)(1)

      

North

  $69.31    $54.11    $93.62  

South

   101.65     90.86     88.46  

Canada(3)

   —       33.97     85.08  

Weighted-Average

   97.91     85.52     89.11  

Production Costs($/Mcfe)(2)

      

North

  $0.45    $0.67    $0.80  

South

   0.93     0.78     0.76  

Canada(3)

   —       1.55     0.88  

Weighted-Average

   0.63     0.74     0.78  

 

(1)

Represents the average realized sales price for all production volumes and royalty volumes sold during the periods shown, net of related costs (principally purchased gas royalty, transportation and storage). Includes realized impact of derivative instruments.

(2)

Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), the costs of administration of production offices insurance and property and severance taxes,insurance, but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration and development expenditures.expenditures and taxes other than income.

(3)

In April 2009, we sold substantially all of our Canadian properties.

Index to Financial Statements

- 12 -


Acreage

The following tables summarize our gross and net developed and undeveloped leasehold and mineral fee acreage by region at December 31, 2008.2010. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

 

   Developed  Undeveloped  Total
   Gross  Net  Gross  Net  Gross  Net

Leasehold Acreage by State

            

Alabama

  —    —    5,391  3,965  5,391  3,965

Arkansas

  1,981  425  —    —    1,981  425

Colorado

  16,267  14,053  175,627  119,839  191,894  133,892

Kansas

  29,387  28,065  —    —    29,387  28,065

Louisiana

  7,907  5,750  9,516  9,119  17,423  14,869

Maryland

  —    —    1,662  1,662  1,662  1,662

Mississippi

  —    —    421,639  278,270  421,639  278,270

Montana

  397  210  143,473  107,910  143,870  108,120

New York

  2,378  961  5,321  4,955  7,699  5,916

North Dakota

  —    —    26,533  9,783  26,533  9,783

Ohio

  6,246  2,384  2,403  1,214  8,649  3,598

Oklahoma

  195,598  138,995  45,636  29,912  241,234  168,907

Pennsylvania

  115,019  66,973  157,944  157,496  272,963  224,469

Texas

  139,064  104,871  106,390  77,043  245,454  181,914

Utah

  2,820  1,609  153,322  79,746  156,142  81,355

Virginia

  7,167  5,040  2,508  1,454  9,675  6,494

West Virginia

  602,313  570,282  259,708  228,127  862,021  798,409

Wyoming

  140,143  72,443  151,327  85,102  291,470  157,545
                  

Total

  1,266,687  1,012,061  1,668,400  1,195,597  2,935,087  2,207,658
                  

Mineral Fee Acreage by State

            

Colorado

  —    —    2,899  271  2,899  271

Kansas

  160  128  —    —    160  128

Montana

  —    —    589  75  589  75

New York

  —    —    6,545  1,353  6,545  1,353

Oklahoma

  16,580  13,979  730  179  17,310  14,158

Pennsylvania

  524  524  1,573  502  2,097  1,026

Texas

  207  135  1,012  511  1,219  646

Virginia

  17,817  17,817  100  34  17,917  17,851

West Virginia

  98,162  79,490  50,896  49,669  149,058  129,159
                  

Total

  133,450  112,073  64,344  52,594  197,794  164,667
                  

Aggregate Total

  1,400,137  1,124,134  1,732,744  1,248,191  3,132,881  2,372,325
                  
   Developed  Undeveloped  Total
   Gross  Net  Gross  Net  Gross  Net

Canada Leasehold Acreage by Province

            

Alberta

  16,160  7,669  70,240  24,860  86,400  32,529

British Columbia

  700  280  11,283  2,606  11,983  2,886

Saskatchewan

  —    —    4,549  —    4,549  —  
                  

Total

  16,860  7,949  86,072  27,466  102,932  35,415
                  

Index to Financial Statements

Total Net Leasehold Acreage by Region of Operation

   Developed  Undeveloped  Total

East

  645,640  394,908  1,040,548

Gulf Coast

  83,769  368,269  452,038

West

  282,652  432,420  715,072

Canada

  7,949  27,466  35,415
         

Total

  1,020,010  1,223,063  2,243,073
         
   Developed   Undeveloped   Total 
   Gross   Net   Gross   Net   Gross   Net 

Leasehold Acreage

            

North

   887,288     731,211     763,389     612,178     1,650,677     1,343,389  

South

   389,905     290,436     274,800     205,893     664,705     496,329  
                              

Total

   1,277,193     1,021,647     1,038,189     818,071     2,315,382     1,839,718  
                              

Mineral Fee Acreage

            

North

   116,674     97,992     62,651     51,819     179,325     149,811  

South

   16,947     14,242     1,892     690     18,839     14,932  
                              

Total

   133,621     112,234     64,543     52,509     198,164     164,743  
                              

Aggregate Total

   1,410,814     1,133,881     1,102,732     870,580     2,513,546     2,004,461  
                              

Total Net Undeveloped Acreage Expiration by Region of Operation

The following table presents our net undeveloped acreage expiring over the next three years by operating region as of December 31, 2008.2010. The figures below assume no future successful development or renewal of undeveloped acreage.

 

   2009  2010  2011

East

  44,302  37,148  85,838

Gulf Coast

  69,260  187,803  61,761

West

  63,089  113,296  67,884

Canada

  6,982  898  320
         

Total

  183,633  339,145  215,803
         
   2011   2012   2013 

North

   142,999     121,146     160,554  

South

   89,528     39,621     36,768  
               

Total

   232,527     160,767     197,322  
               

Well Summary

The following table presents our ownership at December 31, 2008, in productive natural gas and oil wells in the Eastby region (consisting primarily of various fields located in West Virginia and Pennsylvania), in the Gulf Coast region (consisting primarily of various fields located in Louisiana and Texas), in the West region (consisting of various fields located in Oklahoma, Kansas, Colorado, Utah and Wyoming) and in the Canada region (consisting of various fields located in the Province of Alberta).at December 31, 2010. This summary includes natural gas and oil wells in which we have a working interest.

 

   Natural Gas  Oil  Total(1)
   Gross  Net  Gross  Net  Gross  Net

East

  3,355  3,149.2  27  13.4  3,382  3,162.6

Gulf Coast

  721  481.2  123  111.0  844  592.2

West

  1,505  890.5  55  33.4  1,560  923.9

Canada

  42  15.6  1  0.6  43  16.2
                  

Total

  5,623  4,536.5  206  158.4  5,829  4,694.9
                  
   Natural Gas   Oil   Total(1) 
   Gross   Net   Gross   Net   Gross   Net 

North

   4,130     3,552.4     36     18.1     4,166     3,570.5  

South

   1,571     1,060.4     162     136.4     1,733     1,196.8  
                              

Total

   5,701     4,612.8     198     154.5     5,899     4,767.3  
                              

 

(1)

Total does not includeexcludes 55 (52.3 net) service wells of 54 (52.2 net).wells.

Index to Financial Statements

- 13 -


Drilling Activity

We drilled wells, participated in the drilling of wells, or acquired wells as indicated in the region tables below.

 

  Year Ended December 31, 2008  Year Ended December 31, 2010 
  East  Gulf Coast  West  Canada  Total  North   South   Total 
  Gross  Net  Gross  Net  Gross  Net  Gross  Net  Gross  Net  Gross   Net   Gross   Net   Gross   Net 

Development Wells

                                

Successful

  203  196.4  78  52.3  114  78.2  3  2.0  398  328.9

Productive

   57     55.3     39     19.0     96     74.3  

Dry

  1  1.0  4  3.8  3  2.5  1  0.6  9  7.9   —       —       1     1.0     1     1.0  

Extension Wells

                                

Successful

  3  3.0  1  1.0  1  0.7  —    —    5  4.7

Productive

   5     5.0     7     3.3     12     8.3  

Dry

  1  1.0  —    —    —    —    —    —    1  1.0   —       —       —       —       —       —    

Exploratory Wells

                                

Successful

  3  3.0  11  6.8  —    —    2  0.8  16  10.6

Productive

   —       —       3     2.5     3     2.5  

Dry

  1  1.0  —    —    2  0.5  —    —    3  1.5   1     1.0     —       —       1     1.0  
                                                      

Total

  212  205.4  94  63.9  120  81.9  6  3.4  432  354.6   63     61.3     50     25.8     113     87.1  
                                                      

Wells Acquired

  —    —    70  68.3  —    —    —    —    70  68.3   —       —       —       —       —       —    

Wells in Progress at End of Year

  5  4.8  6  4.1  4  2.4  —    —    15  11.3   7     6.0     7     4.2     14     10.3  
  Year Ended December 31, 2009 (1) 
  North   South   Total 
  Gross   Net   Gross   Net   Gross   Net 

Development Wells

            

Productive

   53     51.3     71     52.3     124     103.6  

Dry

   1     1.0     4     3.0     5     4.0  

Extension Wells

            

Productive

   7     7.0     —       —       7     7.0  

Dry

   —       —       —       —       —       —    

Exploratory Wells

            

Productive

   1     0.1     4     2.4     5     2.5  

Dry

   —       —       2     1.5     2     1.5  
                        

Total

   62     59.4     81     59.2     143     118.6  
                        

Wells Acquired

   —       —       1     1.0     1     1.0  

 

   Year Ended December 31, 2007
   East  Gulf Coast  West  Canada  Total
   Gross  Net  Gross  Net  Gross  Net  Gross  Net  Gross  Net

Development Wells

                    

Successful

  248  238.8  80  61.0  96  63.1  5  2.8  429  365.7

Dry

  1  1.0  3  2.5  7  5.8  —    —    11  9.3

Extension Wells

                    

Successful

  1  1.0  4  3.0  —    —    3  1.2  8  5.2

Dry

  —    —    —    —    —    —    —    —    —    —  

Exploratory Wells

                    

Successful

  3  2.8  1  0.5  —    —    2  1.2  6  4.5

Dry

  1  1.0  4  4.0  2  1.2  —    —    7  6.2
                              

Total

  254  244.6  92  71.0  105  70.1  10  5.2  461  390.9
                              

Wells Acquired

  —    —    1  0.9  1  1.0  —    —    2  1.9

Wells in Progress at End of Year

  2  2.0  9  5.2  2  1.1  1  0.2  14  8.5
(1)

In April 2009, we sold substantially all of our Canadian properties.

 

  Year Ended December 31, 2006  Year Ended December 31, 2008 
  East  Gulf Coast  West  Canada  Total  North   South   Canada   Total 
  Gross  Net  Gross  Net  Gross  Net  Gross  Net  Gross  Net  Gross   Net   Gross   Net   Gross   Net   Gross   Net 

Development Wells

                                    

Successful

  195  186.0  40  29.8  107  56.0  5  2.7  347  274.5

Productive

   250     227.2     145     99.7     3     2.0     398     328.9  

Dry

  2  2.0  2  1.9  3  2.3  1  0.2  8  6.4   1     1.0     7     6.3     1     0.6     9     7.9  

Extension Wells

                                    

Successful

  —    —    10  9.7  1  0.1  —    —    11  9.8

Productive

   3     3.0     2     1.7     —       —       5     4.7  

Dry

  —    —    —    —    —    —    1  0.7  1  0.7   1     1.0     —       —       —       —       1     1.0  

Exploratory Wells

                                    

Successful

  2  2.0  8  6.2  —    —    2  0.8  12  9.0

Productive

   3     3.0     11     6.8     2     0.8     16     10.6  

Dry

  1  0.7  4  3.2  2  1.7  1  1.0  8  6.6   3     1.5     —       —       —       —       3     1.5  
                                                              

Total

  200  190.7  64  50.8  113  60.1  10  5.4  387  307.0   261     236.7     165     114.5     6     3.4     432     354.6  
                                                              

Wells Acquired

  5  5.0  —    —    —    —    1  0.4  6  5.4   —       —       70     68.3     —       —       70     68.3  

Wells in Progress at End of Year

  —    —    4  3.9  1  0.5  2  1.3  7  5.7

Index to Financial Statements

- 14 -


Competition

Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times and distribution efficiencies, affect competition. We believe that in the EastNorth region our extensive acreage position, existing natural gas gathering and pipeline systems in West Virginia, services and equipment that we have secured for the upcoming yearyears and storage fields in West Virginia enhance our competitive position over other producers who do not have similar systems or facilitiesservices in place. We also actively compete against other companies with substantially larger financial and other resources.

OTHER BUSINESS MATTERS

Major Customer

In 2010, one customer accounted for approximately 11%, of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of our total sales. In 2007 and 2006, no customer accounted for more than 10% of ourthe Company’s total sales.

Seasonality

Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.

Regulation of Oil and Natural Gas Exploration and Production

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

Natural Gas Marketing, Gathering and Transportation

Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the

- 15 -


provisions of the Energy Policy Act of 2005 (2005 Act), the NGA has been amended to prohibit any forms of market

Index to Financial Statements

manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established new regulations that are intended to increase natural gas pricing transparency through, among other things, requiring market participants to report their gas sales transactions annually to the FERC, and new regulations that require certain non-interstate pipelines to post daily scheduled volume information and design capacity for certain points on their systems. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC’s regulations. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties in an effort to add greater fairness, consistency and transparency to its enforcement program.

Our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation, because the prices we receive for our production are affected by the cost of transporting the gas to the consuming market. Through a series of comprehensive rulemakings, beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and most pipelines have also implemented the large-scale divestiture of their gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generally provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. Sellers and buyers of gas have gained direct access to the particular pipeline services they need, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace.

Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT’s final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non-rural gathering pipeline facilities within the next ten years, and at least every seven years thereafter. On March 15, 2006, the DOT revised these regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non-rural areas, and adopt new compliance deadlines. The initial baseline assessments for our pipeline system in West Virginia are 95% completed. Clarification from the DOT published in 2009 brought to light the need for further baseline assessments of cased pipeline crossings covered under our integrity management program. With this exception, reassessment of our West Virginia pipeline system is scheduled to start in 2013 based on the 7 year reassessment requirement. We have completed 100% of the required initial inspection (baseline assessment) under our integrity management program of our pipeline systems in West Virginia. In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections.

- 16 -


On December 3, 2009, the DOT adopted a regulation requiring gas and hazardous liquid pipelines that use supervisory control and data acquisition (SCADA) systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement the procedures by February 1, 2013. In September 2008, as mandated by this statute, DOT issued a Notice of Proposed Rulemaking issued September 17, 2010, the DOT proposed to establish new rules thatexpedite the program implementation deadline to August 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarm management, which would require pipeline operatorshave a program implementation deadline of August 1, 2012. On November 26, 2010, the DOT updated its reporting requirements for natural gas and hazardous liquid pipelines to amend their existing written operations and maintenance procedures, operator qualification programs, and emergency plans, to assure pipeline safety and integrity. We are not able to predict with certainty the final outcome of these rules on our facilities or our business.be effective January 1, 2011.

We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible to predict what

Index to Financial Statements

proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the recent trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted.

Federal Regulation of Petroleum

Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In March 2006,December 2010, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.32.65 percent should be the oil pricing index for the five-year period beginning July 1, 2006.2011. Another FERC matter that may impact our transportation costs relates to a recent policy that allows a pipeline structured as a master limited partnership or similar non-corporate entity to include in its rates a tax allowance with respect to income for which there is an “actual or potential income tax liability,” to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We currently do not transport any of our oil or natural gas liquids on a pipeline structured as a master limited partnership.

We are not able to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or of the application of the FERC’s policy on income tax allowances.

Environmental Regulations

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.

- 17 -


The transition zone and shallow-water areas of the U.S. Gulf Coast are ecologically sensitive. Environmental issues have led to higher drilling costs and a more difficult and lengthy well permitting process. U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.

Solid and Hazardous Waste.Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or

Index to Financial Statements

other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become more strictstricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.

We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.

Superfund.Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

Oil Pollution Act.Act. The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with the Oil Pollution Act and related federal regulations.

Clean Water Act.Act. The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are primarily implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.

Clean Air Act.Act. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally

- 18 -


resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including but not limited to requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, both the State of Pennsylvania and certain local governments in that state have adopted a variety of regulations limiting how and where fracturing can be performed. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

Greenhouse Gas. In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. For example, the 110th session of Congress considered various bills that proposed a “cap and trade” scheme of regulation of greenhouse gas emissions that generally would ban emissions above a defined reducing annual cap. Covered parties would be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved.

Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of oil or natural gas we produce. Although we would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and gas we produce.

Also, in the wake of the U.S. Supreme Court’s decision in April 2007 inMassachusetts v. Environmental Protection Agency, the EPA has begun to regulate carbon dioxide and other greenhouse gas emissions, even though Congress has yet to adopt new legislation specifically addressing emissions of greenhouse gases. In late 2009, the EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule, which was amended in

- 19 -


December 2010, establishing a new comprehensive regulation and reporting scheme for operators of stationary sources emitting certain levels of greenhouse gases, and a Final Rule finding that certain current and projected levels of greenhouse gases in the atmosphere threaten public health and welfare of current and future generations. Most recently, in late 2010, the EPA finalized new greenhouse gas reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s greenhouse gas reporting rule. Please read “Item 1A. Risk Factors—Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for oil and gas.”

Employees

As of December 31, 2008,2010, we had 560409 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our

Index to Financial Statements

employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.

Website Access to Company Reports

We make available free of charge through our website,www.cabotog.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report. In addition, the SEC maintains an Internet site atwww.sec.gov that contains reports, proxy and information statements and other information filed by the Company. The public may read and copy materials that we file with the SEC at the SEC’s Public Reference Room located at 100 F Street, NE, Washington, DC 20549. Information regarding the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330.

Corporate Governance Matters

The Company’s Corporate Governance Guidelines, Corporate Bylaws, Code of Business Conduct, Corporate Governance and Nominations Committee Charter, Compensation Committee Charter and Audit Committee Charter are available on the Company’s website atwww.cabotog.com, under the “Corporate Governance”“Governance” section of “Investor Relations” and a copy will be provided, without charge, to any shareholder upon request.Info.” Requests can also be made in writing to Investor Relations at our corporate headquarters at 1200 Enclave Parkway,Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas, 77077. We have filed the required certifications of our chief executive officer and our chief financial officer under Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits 31.1 and 31.2 to this Form 10-K. In 2008, we submitted to the New York Stock Exchange the chief executive officer certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual.77024.

 

ITEM 1A.RISK FACTORS

Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Natural gas prices have increased from an average price have declined from approximately $13of $3.99 per Mmbtu in July 20082009 to approximately $4.50an average price of $4.39 per Mmbtu as of February 1, 2009.in 2010. Oil prices have declinedincreased from record levels in July 2008an average price of approximately $145$61.80 per barrel in 2009 to approximately $40an average price of $77.32 per barrel as of February 1, 2009.in 2010. Depressed prices in the future would have a negative impact on our future financial results. Because our reserves are predominantly natural gas, changes in natural gas prices have a particularly large impact on our financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

 

the level of consumer product demand;

 

weather conditions;

 

- 20 -


political conditions in natural gas and oil producing regions, including the Middle East;

 

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

Index to Financial Statements

the price of foreign imports;

 

actions of governmental authorities;

 

pipeline availability and capacity constraints;

 

inventory storage levels;

 

domestic and foreign governmental regulations;

 

the price, availability and acceptance of alternative fuels; and

 

overall economic conditions.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

Drilling natural gas and oil wells is a high-risk activity.

Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

 

unexpected drilling conditions, pressure or irregularities in formations;

 

equipment failures or accidents;

 

adverse weather conditions;

 

compliance with governmental requirements; and

 

shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

 

the results of exploration efforts and the acquisition, review and analysis of the seismic data;

 

the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

 

the approval of the prospects by other participants after additional data has been compiled;

 

economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;

 

our financial resources and results; and

 

the availability of leases and permits on reasonable terms for the prospects.

- 21 -


These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.

Index to Financial Statements

Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated.

Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds.

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (FASB) in Statement of Financial Accounting Standards No. 69Codification 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.

In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

Our reserve report estimates that production from our proved developed producing reserves as of December 31, 20082010 will increase at an estimated rate of 30% during 2011 and then decline at estimated rates of 21%22%, 17%, 12%22% and 11%15% during 2009, 2010, 20112012, 2013 and 2012,2014, respectively. Future development of proved undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern fairly typical.

Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.

- 22 -


Acquired properties may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include exploration potential, future natural gas and oil prices, operating costs, and potential

Index to Financial Statements

environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. Often, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. If an acquired property is not performing as originally estimated, we may have an impairment which could have a material adverse effect on our financial position and results of operations.

The integration of the properties we acquire could be difficult, and may divert management’s attention away from our existing operations.

The integration of the properties we acquire could be difficult, and may divert management’s attention and financial resources away from our existing operations. These difficulties include:

 

the challenge of integrating the acquired properties while carrying on the ongoing operations of our business; and

 

the possibility of faulty assumptions underlying our expectations.

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

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;

 

uncontrolled flows of natural gas, oil or well fluids;

 

fires;

 

formations with abnormal pressures;

 

pollution and other environmental risks; and

 

natural disasters.

In addition, we conduct operations in shallow offshore areas (largely coastal waters), which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather. 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, 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

- 23 -


risks. As of December 31, 2008,2010, we owned or operated approximately 3,5003,150 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.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.

IndexBills have recently been introduced in Congress that would subject hydraulic fracturing to Financial Statements
federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, both the State of Pennsylvania and certain local governments in that state have adopted a variety of regulations limiting how and where fracturing can be performed. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

We may not be insured against all of the operating risks to which we are exposed.

We maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, and results of operations.operations and cash flows.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. Non-operated wells represented approximately 15%14.9% of our total owned gross wells, or approximately 4.8%4.6% of our owned net wells, as of December 31, 2008.2010. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Terrorist activities and the potential for military and other actions could adversely affect our business.

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

- 24 -


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.

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. Our failure to obtain these services on acceptable terms could materially harm our business.

Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.

Index to Financial Statements

We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 20082010 we employed natural gas and crude oil price collar and swap agreements coveringfor portions of our 20082010 production and natural gas price swap agreements and crude oil collar agreements for portions of our anticipated 2009 and 20102011 production to attempt to manage price risk more effectively. In addition, we have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting.

The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place. These hedging arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

 

a counterparty is unable to satisfy its obligations;

 

production is less than expected; or

 

there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives.

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or

- 25 -


more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and gas that we produce.

IndexThere is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases. In the United States, climate change action is evolving at state, regional and federal levels. On December 17, 2010, the EPA amended the “Mandatory Reporting of Greenhouse Gases” final rule (“Reporting Rule”) originally issued in September 2009. The Reporting Rule establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent greenhouse gases to Financial Statements
inventory and report their greenhouse gases emissions annually on a facility-by-facility basis. In addition, on December 15, 2009, the EPA published a Final Rule finding that current and projected concentrations of six key greenhouse gases in the atmosphere threaten public health and the welfare of current and future generations. The EPA also found that the combined emissions of these greenhouse gases from new motor vehicles and new motor vehicle engines contribute to pollution that threatens public health and welfare. This Final Rule, also known as the EPA’s Endangerment Finding, does not impose any requirements on industry or other entities directly. However, following issuance of the Endangerment Finding, EPA promulgated final motor vehicle GHG emission standards on April 1, 2010, the effect of which could reduce demand for motor fuels refined from crude oil. Also, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, EPA issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi step process, with the largest sources first subject to permitting. Most recently, on November 8, 2010, EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s GHG Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will now be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012.

However, following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle greenhouse gas emission standards on April 1, 2010, the effect of which could reduce demand for motor fuels refined from crude oil. Also, according to the EPA, the final motor vehicle greenhouse gas standards will trigger

- 26 -


construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, the EPA issued a final rule to address permitting of greenhouse gas emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule tailors the PSD and Title V programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. Most recently, on November 8, 2010, the EPA finalized new greenhouse gas reporting requirements for upstream petroleum and natural gas systems, which will be added to the Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of C02 equivalent per year will now be required to report annual GHG emissions to the EPA, with the first report due on March 31, 2012.

Internationally, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. While it is not possible at this time to predict how regulation that may be enacted to address greenhouse gases emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. To the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make estimating any future financial risk to our operations caused by these potential physical risks of climate change extremely challenging.

The proposed U.S. federal budget for fiscal year 2012 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On February 14, 2011, the Office Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2012, and the Treasury Department released a general explanation of tax related proposals in such budget. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposes new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increase in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and gas companies; and increase in the geological and geophysical amortization period for independent producers. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

Provisions of Delaware law and our bylaws and charter could discourage change in control transactions and prevent stockholders from receiving a premium on their investment.

Our bylaws provide for a classified Board of Directors with staggered terms, and our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit stockholder action by written consent and limit stockholder proposals at meetings of stockholders. We also have adopted a stockholder rights plan. Because of our stockholder rights plan and these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals

- 27 -


may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our certificate of incorporation.charter.

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ duty of care to equitable remedies such as injunction or rescission. Our certificate of incorporationcharter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:

 

for any breach of their duty of loyalty to the company or our stockholders;

 

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

 

under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and

 

for any transaction from which the director derived an improper personal benefit.

This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.

The global financial crisis may have impacts on our business and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us. Additionally, market conditions could have an impact on our commodity hedging arrangements if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to further reduced demand for oil and natural gas, or lower prices for oil and natural gas, or both, which could have a negative impact on our revenues.

 

ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

 

ITEM 2.PROPERTIES

See Item 1. “Business.”

Index to Financial Statements
ITEM 3.LEGAL PROCEEDINGS

We areThe Company is a defendant in various legal proceedings arising in the normal course of our business. When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities are accrued based on management’s best estimatean estimation process that includes the advice of the potential loss.legal counsel and subjective judgment of management. While the outcome and impact of such legal proceedings on usthe Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidatedthe Company’s financial position, results of operations or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.flows.

Commitment and Contingency ReservesEnvironmental Matters

When deemed necessary, we establish reserves for certain legal proceedings.On November 4, 2009, the Company and the Pennsylvania Department of Environmental Protection (PaDEP) entered into a single settlement agreement (Consent Order) covering a number of separate, unrelated environmental issues occurring in 2008 and 2009, including releases of drilling mud and other substances, record keeping violations at various wells and alleged natural gas contamination of 13 water wells in Susquehanna County, Pennsylvania. The establishment of a reserve involvesCompany paid an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur approximately $2.1 million of additional lossaggregate $120,000 civil penalty with respect to all the matters covered by the Consent Order, which were consolidated at the request of the PaDEP.

On April 15, 2010, the Company and PaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, PaDEP and the Company agreed that the

- 28 -


Company will provide a permanent source of potable water to 14 households, most of which the Company has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the households and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company agreed to take certain other actions if requested by PaDEP, which could include the plugging and abandonment of up to 10 additional wells. Under the First Modified Consent Order, the Company paid a $240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

On July 19, 2010, the Company and the PaDEP entered a Second Modification to Consent Order (Second Modified Consent Order) under which the Company and the PaDEP agreed that the Company has satisfactorily plugged and abandoned the three vertical wells and brought the fourth well into compliance. As a result, the Company and the PaDEP agreed that the PaDEP will commence the processing and issuance of new well drilling permits outside the area of concern so long as the Company continues to provide temporary potable water and offers to provide gas/water separators to the 14 households. No penalties were assessed under the Second Modified Consent Order.

As required by the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to the 14 households. As required by the First Modified Consent Order, on August 5, 2010 the Company filed with the PaDEP its report, prepared by its experts, finding that the Company’s well drilling and development activities are not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

Despite the Company’s vigorous efforts to comply with the various consent orders, in a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and determined that the Company’s drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company, in accordance with the First Modified Consent Order, to plug or take other remedial actions at the remaining 10 wells and to contact the PaDEP to discuss connecting the impacted water supplies into a community public water system to permanently eliminate the continuing adverse affect to those matterswater supplies.

The Company believed that it was in full compliance with the various consent orders. In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. It was the Company’s position that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company’s obligations under these consent orders.

On December 15, 2010, the Company entered a global settlement agreement and new consent order with the PaDEP (Global Settlement Agreement), which reservessupersedes the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the Global Settlement Agreement, among other things, the Company agreed to pay $4.2 million into separate escrow accounts for the benefit of each affected household, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, remediate two wells in the affected area, provide pressure, water quality and well headspace data to the PaDEP and offer water treatment to the affected households. The Global Settlement Agreement settles all outstanding issues and claims that are known and that could have been established. Future changesbrought against the Company by the PaDEP relating to the wells in the factsaffected area and circumstances could resultthe Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to begin hydraulic fracturing in the actual liability exceedingaffected areas after providing the estimated ranges of lossPaDEP with well pressure data and amounts accrued.

While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impactedto commence drilling new wells in the reporting periodsaffected area in which such matters are resolved.the second quarter of 2011. Under the Global Settlement Agreement, the Company has no obligation to connect the impacted water supplies to a community public water system.

 

ITEM 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted- 29 -


On January 11, 2011, certain of the affected households appealed the Global Settlement Agreement to the Pennsylvania Environmental Hearing Board. A hearing on the merits of this appeal is not expected to occur until 2012.

As of December 31, 2010, the Company has paid $1.3 million in fines and penalties to the PaDEP, paid $0.6 million to two of the affected households and accrued a vote of security holders during$3.6 million settlement liability related to this matter which is included in Other Liabilities in the fourth quarter of 2008.Consolidated Balance Sheet.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information as of February 15, 200918, 2011 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.

 

Name

  Age  

Position

  Officer
Since
  Age   

Position

  Officer
Since
 

Dan O. Dinges

  55  Chairman, President and Chief Executive Officer  2001   57    

Chairman, President and Chief Executive Officer

   2001  

Michael B. Walen

  60  Senior Vice President, Chief Operating Officer  1998

Scott C. Schroeder

  46  Vice President and Chief Financial Officer  1997   48    

Vice President and Chief Financial Officer and Treasurer

   1997  

J. Scott Arnold

  55  Vice President, Land and General Counsel  1998

G. Kevin Cunningham

   57    

Vice President, General Counsel

   2010  

Robert G. Drake

  61  

Vice President, Information Services and Operational Accounting

  1998   63    

Vice President, Information Services and Operational Accounting

   1998  

Abraham D. Garza

  62  Vice President, Human Resources  1998   64    

Vice President, Human Resources

   1998  

Jeffrey W. Hutton

  53  Vice President, Marketing  1995   55    

Vice President, Marketing

   1995  

Thomas S. Liberatore

  52  Vice President, Regional Manager, East Region  2003

Steven W. Lindeman

   50    

Vice President, Engineering and Technology

   2011  

Lisa A. Machesney

  53  

Vice President, Managing Counsel and Corporate Secretary

  1995   55    

Vice President, Managing Counsel and Corporate Secretary

   1995  

Henry C. Smyth

  62  Vice President, Controller and Treasurer  1998

James M. Reid

   59    

Vice President, Regional Manager South Region

   2009  

Todd M. Roemer

   40    

Controller

   2010  

Phillip L. Stalnaker

   51    

Vice President, Regional Manager North Region

   2009  

All officers are elected annually by our Board of Directors. All of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years.years, except for Mr. G. Kevin Cunningham and Mr. Todd M. Roemer.

Mr. Cunningham joined the Company in November 2009 as Associate General Counsel and was appointed as General Counsel in September 2010 and promoted to Vice President in 2011. Before joining the Company, Kevin was Regional Counsel-Southern Division at Chesapeake Energy from 2006 until November 2009. He is a graduate of the University of Texas School of Law and has worked at Fortune 500 E&P companies in both legal and business positions since 1982.

Mr. Lindeman was promoted to Vice President, Engineering and Technology, in February 2011. He began his career as a Drilling Engineer in Meadville, Pennsylvania with Cabot in 1982, has served in various management positions in many company offices over the years, including Pampa and Midland, Texas, Indiana, Meadville, and Pittsburgh, Pennsylvania, before moving to Houston in 1992, where he most recently served as Director of Engineering. Mr. Lindeman is a graduate of the University of Pittsburgh; he holds a Bachelor of Science degree in Chemical Engineering specializing in Petroleum Engineering. He has been a member of the Society of Petroleum Engineers since 1980.

Mr. Roemer joined the Company in February 2010 after a 14 year career in PricewaterhouseCoopers’ energy practice. He is a graduate of the University of Houston—Clear Lake with a Bachelor of Science degree in Accounting. Mr. Roemer is a Certified Public Accountant.

Index to Financial Statements

- 30 -


PART II

 

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG.” The following table presents the high and low closing sales prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the common stock are also shown. A regular dividend has been declared each quarter since we became a public company in 1990.

On February 23, 2007, our Board of Directors declared a 2-for-1 split of our common stock in the form of a stock distribution. The stock dividend was distributed on March 30, 2007 to stockholders of record on March 16, 2007. All common stock accounts and per share data, including cash dividends per share, have been retroactively adjusted to give effect to the 2-for-1 split of our common stock. After the stock split, the dividend was increased to $0.03 per share per quarter, or a 50% increase from pre-split levels.

  High  Low  Dividends  High   Low   Dividends 

2008

      

2010

      

First Quarter

  $53.41  $37.67  $0.03  $46.23    $36.40    $0.03  

Second Quarter

  $71.11  $51.48  $0.03  $40.51    $30.33    $0.03  

Third Quarter

  $68.58  $33.58  $0.03  $33.61    $26.99    $0.03  

Fourth Quarter

  $33.83  $21.31  $0.03  $37.85    $28.27    $0.03  

2007

      

2009

      

First Quarter

  $35.29  $28.06  $0.02  $30.76    $18.14    $0.03  

Second Quarter

  $41.88  $34.55  $0.03  $36.90    $24.38    $0.03  

Third Quarter

  $38.39  $31.55  $0.03  $39.23    $27.98    $0.03  

Fourth Quarter

  $40.90  $33.59  $0.03  $45.73    $34.14    $0.03  

As of January 31, 2009,February 1, 2011, there were 544496 registered holders of the common stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.

ISSUER PURCHASES OF EQUITY SECURITIES

Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During 2008,2010, we did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of remaining shares that may yet be purchased under the plan as of December 31, 20082010 was 4,795,300.

Index to Financial Statements

- 31 -


PERFORMANCE GRAPH

The following graph compares our common stock performance (“COG”) with the performance of the Standard & Poors’ 500 Stock Index and the Dow Jones US Exploration & Production Index for the period December 20032005 through December 2008.2010. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 20032005 and that all dividends were reinvested.

 

Calculated Values

  2003  2004  2005  2006  2007  2008

CALCULATED VALUES

  2005   2006   2007   2008   2009   2010 

S&P 500

  100.0  110.9  116.3  134.7  142.1  89.5   100.0     115.8     122.2     77.0     97.3     112.0  

COG

  100.0  151.4  232.4  313.5  418.7  270.5   100.0     134.9     180.1     116.4     195.8     170.6  

Dow Jones US Exploration & Production

  100.0  141.9  234.5  247.1  355.1  212.6   100.0     105.4     151.4     90.6     127.4     148.7  

*Year-end closing values.

The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.

Index to Financial Statements

- 32 -


ITEM 6.SELECTED FINANCIAL DATA

The following table summarizes our selected consolidated financial data for the periods indicated. This information should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the Consolidated Financial Statements and related Notes in Item 8.

 

  Year Ended December 31,   Year Ended December 31, 
  2008  2007  2006  2005  2004 
  (In thousands, except per share amounts) 

(In thousands, except per share amounts)

  2010   2009 2008   2007   2006 

Statement of Operations Data

                   

Operating Revenues

  $945,791  $732,170  $761,988  $682,797  $530,408   $884,035    $879,276   $945,791    $732,170    $761,988  

Impairment of Oil & Gas Properties and Other Assets(1)

   35,700   4,614   3,886   —     3,458    40,903     17,622    35,700     4,614     3,886  

Gain / (Loss) on Sale of Assets(2)

   1,143   13,448   232,017   74   (124)   106,294     (3,303  1,143     13,448     232,017  

Gain on Settlement of Dispute(3)

   51,906   —     —     —     —      —       —      51,906     —       —    

Income from Operations

   372,012   274,693   528,946   258,731   160,653    266,439     282,269    372,012     274,693     528,946  

Net Income

   211,290   167,423   321,175   148,445   88,378    103,386     148,343    211,290     167,423     321,175  

Basic Earnings per Share(4)

  $2.10  $1.73  $3.32  $1.52  $0.91   $0.99    $1.43   $2.10    $1.73    $3.32  

Diluted Earnings per Share(4)

  $2.08  $1.71  $3.26  $1.49  $0.90   $0.98    $1.42   $2.08    $1.71    $3.26  

Dividends per Common Share(4)

  $0.120  $0.110  $0.080  $0.074  $0.054   $0.12    $0.12   $0.12    $0.11    $0.08  

Balance Sheet Data

                   

Properties and Equipment, Net

  $3,135,828  $1,908,117  $1,480,201  $1,238,055  $994,081 

Properties and Equipment, Net.

  $3,762,760    $3,358,199   $3,135,828    $1,908,117    $1,480,201  

Total Assets

   3,701,664   2,208,594   1,834,491   1,495,370   1,210,956    4,005,031     3,683,401    3,701,664     2,208,594     1,834,491  

Current Portion of Long-Term Debt

   35,857   20,000   20,000   20,000   20,000    —       —      35,857     20,000     20,000  

Long-Term Debt

   831,143   330,000   220,000   320,000   250,000    975,000     805,000    831,143     330,000     220,000  

Stockholders’ Equity

   1,790,562   1,070,257   945,198   600,211   455,662    1,872,700     1,812,514    1,790,562     1,070,257     945,198  

 

(1)

For discussion of impairment of oil and gas properties and other assets, refer to Note 2 of the Notes to the Consolidated FinancialStatements.

(2)

Gain on Sale of Assets in 2010 includes $40.7 million from the sale of the Company’s investment in Tourmaline, $49.3 million from thesale of our Pennsylvania gathering infrastructure, $10.8 million from the sale of certain oil and gas properties in the Texas Panhandle,a $10.3 million gain on the sale of our Woodford shale properties, and an impairment loss of $5.8 million on certain oil and gasproperties in Colorado. Gain on Sale of Assets for 2007 and 2006 reflects $12.3 million and $231.2 million, respectively, related todisposition of our offshore portfolio and certain south Louisiana properties, (the “2006 south Louisiana and offshore properties sale”), which was substantially completed in the third quarter of 2006.

(3)

Gain on Settlement of Dispute is associated with the Company’s settlement of a dispute in the fourth quarter of 2008. The disputesettlement includes the value of cash and properties received. See Note 78 of the Notes to the Consolidated Financial Statements.

(4)

All Earnings per Share and Dividends per Common Share figures have been retroactively adjusted for the 2-for-1 split of our common stock effective March 31, 2007 as well as the 3-for-2 split of our common stock effective March 31, 2005.2007.

 

ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.

In 2009, we reorganized our operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with our Texas and Louisiana areas to form the South region. Additionally, we exited Canada through the sale of our properties in April 2009. Prior to the third quarter of 2009, we presented our geographic areas as East, Gulf Coast, West and Canada. Certain prior year amounts have been reclassified to reflect changes in presenting the geographic areas in which we conduct our operations.

- 33 -


We operate in one segment, natural gas and oil development, exploitation and exploration, exclusively within the United States.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read “Forward-Looking Information” for further details.

We operate in one segment, natural gas and oil development, exploitation and exploration, exclusively within the United States and Canada.

Index to Financial Statements

OVERVIEW

Cabot Oil & Gas and its subsidiaries areCorporation is a leading independent oil and gas company engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, crude oil and natural gas liquids from its properties in North America.the Continental United States. We also transport, store, gather and produce natural gas for resale. Our exploitation and exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Our program is designed to be disciplined and balanced, with a focus on achieving strong financial returns.

At Cabot, there areWe evaluate three types of investment alternatives that compete for available capital: drilling opportunities, financial opportunities such as debt repayment or repurchase of common stock and acquisition opportunities. Depending on circumstances, we allocate capital among the alternatives based on a rate-of-return approach. Our goal is to invest capital in the highest return opportunities available at any given time. At any one time, one or more of these may not be economically feasible.

Our financial results depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Price volatility in the commodity markets has remained prevalent in the last few years. Throughout 2007 and most of 2008, the futures market reported strong natural gas and crude oil contract prices. During the fourth quarter of 2008, commodity prices experienced a sharp decline. Our realized natural gas and crude oil price was $8.39$5.54 per Mcf and $89.11$97.91 per Bbl, respectively, in 2008. These2010 and were significantly increased by our positions from our derivative instruments, which contributed approximately 22% of our realized prices include the realized impact of derivative instruments.revenues in 2010. In an effort to manage commodity price risk, we enteredopportunistically enter into a series of crude oil and natural gas price swaps and collars. These financial instruments are an important elementa component of our risk management strategy and assisted in the increase in our realized natural gas price from 2007 to 2008.strategy.

Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. See “Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business” and “Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable” in Item 1A.

The tablestable below illustrateillustrates how natural gas prices have fluctuated by month over 20072009 and 2008.2010. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2007”“2009” and “2008”“2010” price is the natural gas price per Mcf realized by us and includes the realized impact of our natural gas price collar and swap arrangements,derivative instruments, as applicable:

 

  Natural Gas Prices by Month - 2008  Natural Gas Prices by Month - 2010 
  Jan  Feb  Mar  Apr  May  Jun  Jul  Aug  Sep  Oct  Nov  Dec  Jan   Feb   Mar   Apr   May   Jun   Jul   Aug   Sep   Oct   Nov   Dec 

Index

  $7.13  $8.01  $8.96  $9.59  $11.29  $11.93  $13.11  $9.23  $8.40  $7.48  $6.47  $6.90  $5.82    $5.28    $4.81    $3.84    $4.27    $4.16    $4.73    $4.78    $3.64    $3.84    $3.29    $4.27  

2008

  $7.46  $7.82  $8.45  $9.03  $9.38  $9.50  $9.36  $8.61  $8.05  $7.89  $7.70  $7.54

2010

  $6.95    $6.47    $6.28    $5.35    $5.49    $5.60    $5.66    $5.64    $4.84    $4.99    $4.66    $5.39  
  Natural Gas Prices by Month - 2007  Natural Gas Prices by Month - 2009 
  Jan  Feb  Mar  Apr  May  Jun  Jul  Aug  Sep  Oct  Nov  Dec  Jan   Feb   Mar   Apr   May   Jun   Jul   Aug   Sep   Oct   Nov   Dec 

Index

  $5.84  $6.93  $7.55  $7.56  $7.51  $7.59  $6.93  $6.11  $5.43  $6.43  $7.27  $7.21  $6.16    $4.49    $4.07    $3.65    $3.33    $3.54    $3.96    $3.37    $2.84    $3.72    $4.28    $4.49  

2007

  $7.05  $7.61  $7.63  $7.04  $7.30  $7.38  $7.05  $6.94  $6.41  $7.06  $7.44  $7.87

2009

  $7.72    $7.32    $7.46    $7.03    $7.28    $7.45    $7.50    $7.45    $7.25    $7.42    $8.03    $7.75  

Index to Financial Statements

Prices for- 34 -


The table below illustrates how crude oil maintained strength in 2007prices have fluctuated by month over 2009 and rose to record high levels in 2008, but experienced significant declines in the fourth quarter of 2008. The tables below contain2010. “Index” represents the NYMEX monthly average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 20072009 and 2008.2010. The “2007”“2009” and “2008”“2010” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative arrangements:instruments:

 

 Crude Oil Prices by Month - 2008 Crude Oil Prices by Month - 2010 
 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

Index

 $92.93 $95.35 $105.42 $112.46 $125.46 $134.02 $133.48 $116.69 $103.76 $76.72 $57.44 $42.04 $72.47   $77.62   $80.16   $81.25   $83.45   $68.01   $77.21   $77.44   $73.46   $73.52   $81.77   $81.51  

2008

 $83.71 $85.02 $90.85 $92.56 $99.79 $103.83 $102.76 $101.16 $93.51 $87.10 $69.16 $62.45

2010

 $101.75   $96.32   $95.25   $97.07   $94.48   $98.82   $99.00   $101.47   $94.95   $101.01   $97.51   $100.24  
 Crude Oil Prices by Month - 2007 Crude Oil Prices by Month - 2009 
 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

Index

 $54.67 $59.39 $60.74 $64.04 $63.53 $67.53 $74.15 $72.36 $79.63 $85.66 $94.63 $91.74 $41.92   $39.26   $48.06   $49.95   $59.21   $69.70   $64.29   $71.14   $69.47   $75.82   $78.15   $74.60  

2007

 $51.59 $53.17��$55.54 $61.31 $63.35 $61.42 $70.68 $70.03 $71.90 $83.97 $84.38 $82.65

2009

 $75.41   $73.98   $76.29   $78.86   $85.94   $86.26   $82.22   $92.16   $87.54   $92.13   $95.35   $95.41  

We reported earnings of $2.10 per share, or $211.3 million, for 2008, an increase from the $1.73 per share, or $167.4 million, reported in 2007. Natural gas revenues increaseddecreased from 20072009 to 20082010 as a result of favorable natural gas hedge settlements, increaseddecreased commodity market prices andpartially offset by increased natural gas production. Crude oil revenues increased slightly from 20072009 to 20082010 primarily due to increased realized prices, partially offset by a reduction indecreased crude oil production. Prices, including the realized impact of derivative instruments, increaseddecreased by 16%26% for natural gas and 33%increased by 14% for oil.

We drilled 432113 gross wells with a success rate of 97%98% in 20082010 compared to 461143 gross wells with a success rate of 96%95% in 2007.2009. Total capital and exploration expenditures increased by $844.8$251.1 million to $1,481.0$891.5 million (including the east Texas acquisition) in 20082010 compared to $636.2$640.4 million in 2007.2009. This increase was due to a $230.6 million increase in the North region substantially driven by an expanded Marcellus horizontal drilling program in northeast Pennsylvania to hold acreage and $42.8 million in the South region due to due to an increase in lease acquisitions to establish a greater position in the oil window of the Eagle Ford shale. We believe our cash on hand and operating cash flow in 20092011 will be sufficient to fund our budgeted capital and exploration spending of approximately $475$600 million. Any additional needs willare expected to be funded by borrowings from our credit facility. We have reduced, and may continue to reduce, our budgeted capital and exploration spending to maintain sufficient liquidity.

Our 20092011 strategy will remain consistent with 2008.2010. We will remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure that we have sufficient liquidity, including cash resources and we intend to maintain spending discipline.available credit. In the current year we have allocated our planned program for capital and exploration expenditures primarily to the EastMarcellus shale in northeast Pennsylvania, and Gulf Coast regions.the Eagle Ford shale in south Texas. We believe these strategies are appropriate for our portfolio of projects and the current industry environment and that this activity will continue to add shareholder value over the long-term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.

FINANCIAL CONDITION

Capital Resources and Liquidity

Our primary sources of cash in 20082010 were from funds generated from the sale of natural gas and crude oil production the private placements of debt completed in July and December 2008, the sale of common stock and, to a lesser extent,(including hedge realizations), borrowings under our revolving credit facility, issuance of private placement debt and asset sales. Cashthe sales of properties and other assets during the year. These cash flows provided by operating activities, borrowings, the sale of common stock and proceeds from asset sales were primarily used to fund our development (including acquisitions) and to a lesser extent, exploratory expenditures, in addition to paying dividendsrepayments for debt and related interest, payments for debt issuance costs.costs, contributions to our pension plan and dividends. See below for additional discussion and analysis of cash flow.

Index to Financial Statements

- 35 -


We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have also influenced prices throughout the recent years. Commodity prices have recently experienced increased volatility due to adverse market conditions in our economy. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales.revenues.

Our working capital is also substantially influenced by variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. The recent financial and credit crisis has reduced credit availability and liquidity for some companies; however, weWe believe we have adequate availability under our credit facility and liquidity available to meet our working capital requirements.

 

  Year Ended December 31,   Year Ended December 31, 
  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Cash Flows Provided by Operating Activities

  $634,447  $462,137  $357,104   $484,911   $614,052   $634,447  

Cash Flows Used in Investing Activities

   (1,452,289)  (589,922)  (187,353)   (613,741  (531,027  (1,452,289

Cash Flows Provided by / (Used in) Financing Activities

   827,445   104,429   (138,523)   144,621    (70,968  827,445  
                    

Net Increase / (Decrease) in Cash and Cash Equivalents

  $9,603  $(23,356) $31,228   $15,791   $12,057   $9,603  
                    

Operating Activities. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities in 2008 increased2010 decreased by $172.3$129.1 million over 2007.2009. This increasedecrease was mainly due to an increasea decrease in net income, the receipt of cash of $20.2 million in 2008 in connection with the settlement of a disputeoil and an increase of $13.7 million in cash received for income tax refunds. In addition, cash flows fromgas revenues and higher operating activities increased as a result of other working capital changes.and interest expense. Average realized natural gas prices increaseddecreased by 16%26% in 2008 over 20072010 compared to 2009 and average realized crude oil prices increased by 33%14% over the same period. Equivalent production volumes increased by 11%27% in 20082010 compared to 2007 as a result of2009 primarily due to higher natural gas production. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Realized prices may continue to decline during 2011.

For 2010, we had natural gas price swaps covering 35.9 Bcf, or 29%, of our 2010 natural gas production at an average price of $9.30 per Mcf. We also had crude oil price swaps covering 730 Mmbl, or 90%, of our 2010 crude oil production at an average price of $104.25 per Bbl. As of December 31, 2010, we have natural gas price swaps covering 12.9 Bcf of our 2011 gas production at an average price of $6.24 per Mcf and crude oil collars covering 365 MBbls of our 2011 crude oil production, with a floor of $80.00 per Bbl and a ceiling of $93.25 per Bbl. Accordingly, based on our current hedge position, we will be more subject to the effects of natural gas and crude oil price volatility in 2011 than in 2010. In addition, given the current market for derivatives, if we were to hedge all our 2011 production, we would expect our realized prices to be lower in 2009.than our 2010 realized prices.

Net cash provided by operating activities in 2007 increased2009 decreased by $105.0$20.4 million over 2006.2008. This increasedecrease was mainly due to a decrease in cash paid for current income taxes from 2006 to 2007 primarily due to the 2006 payment of approximately $102 million related to the 2006 south Louisianaoil and offshore properties sale, as well as our 2007gas revenues, partially offset by lower operating, interest and tax net operating loss position and the receipt in 2007 of $29.6 million in federal tax refunds relating to our 2006 tax return.expense. Average realized natural gas prices increaseddecreased by one percent11% in 2007 over 20062009 compared to 2008 and average realized crude oil prices increaseddecreased by three percent4% over the same period. Equivalent production decreasedvolumes increased by three percent8% in 20072009 compared to 20062008 as a result of a decrease inhigher natural gas and crude oil production, offset in part by an increase in natural gas production.

See “Results of Operations” for a discussion on commodity prices and a review of the impact of prices and volumes on sales revenue.

Investing Activities. The primary uses of cash in investing activities were capital spending (including the east Texas acquisition and new leases in both Pennsylvania and east Texas) and exploration expenses. We established the budget for these amounts based on our current estimate of future commodity prices.prices and cash flows. Due to the volatility of commodity prices and new opportunities which may arise, our capital

- 36 -


expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased by $862.4$82.7 million from 20072009 to 20082010 and increaseddecreased by $402.6$921.3 million from 20062008 to 2007.2009. The increase from 20072009 to 20082010 was due

Index to Financial Statements

to an increase of $866.0$246.4 million in acquisitions and capital and exploration expenditures includingpartially offset by an increase of approximately $601.8$163.3 million primarily due to the $604.0 million east Texas acquisition and an increase of $130.5 million related to unproved leasehold acquisitions primarily in northeast Pennsylvania. In addition, there were $5.0 million of lower proceeds from the sale of assets in 2008 compared to 2007. Partially offsetting these increases to cash used in investing activities were decreased exploration expenditures of $8.6 million in 2008 compared to 2007.assets.

The increase in cash flows used in investing activitiesdecrease from 20062008 to 20072009 was due to a decrease of $322.4$843.2 million in 2007 inacquisitions and capital expenditures and an increase of $78.1 million of proceeds from the sale of assetsassets. In August 2008, we completed the acquisition of producing properties, leasehold acreage and an increasea natural gas gathering infrastructure in east Texas for total net cash consideration of $89.8 million in 2007 in capital expenditures, partially offset by reduced exploration expenses of $9.6approximately $604.0 million.

Financing Activities. Cash flows provided by financing activities increased by $723.0$215.6 million from 20072009 to 2008.2010. This was primarily due to an increase in debt consistingborrowings of our July 2008 and December 2008 private placements$420.0 million, partially offset by an increase in repayments of debt ($492 million) andof $188.0 million, an increase in cash paid for capitalized debt issuance costs by a total of $45$3.4 million and a decrease of $13.7 million in the tax benefit associated with stock-based compensation.

Cash flows provided by financing activities decreased by $898.4 million from 2008 to 2009. This was primarily due to a decrease in borrowings under our revolving credit facility. Additionally,from debt of $787 million, partially offset by a decrease in repayments of debt of $208 million, and a decrease in net proceeds from the sale of common stock increased by $311.1of $316.1 million primarily due to theour June 2008 issuance of common stock. The tax benefitstock in a public offering. Common stock proceeds and debt borrowings in 2008 were largely used to finance the acquisition of east Texas properties and undeveloped acreage. Cash paid for stock-based compensationcapitalized debt issuance costs and dividends increased by $10.7a total of $6.4 million, from 2007 to 2008, but was partially offset by an increase in dividends and capitalized debt issuance costs paid.

Cash flows provided by financing activities increased by $243.0of $3.1 million from 2006 to 2007 primarily due to a $210.0 million increase in debt, principally related to higher borrowings under our revolving credit facility. In addition, $46.5 million of treasury stock was purchased in 2006 compared with none in 2007. Partially offsetting these increases in cash provided by financing activities were a $9.5 million reduction in the tax benefit forassociated with stock-based compensation, lower proceeds from the exercise of stock options and higher dividend payments.compensation.

At December 31, 2008,2010, we had $185$213.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of 3.7%3.1%.

In December 2008, the2010, we completed a private placement of $175.0 million aggregate principal amount of senior unsecured fixed-rate notes with a weighted-average interest rate of 5.58%, consisting of amounts due in January 2021, 2023 and 2026.

In September 2010, we amended and restated our revolving credit facility was amended to extendincrease the commitment period for lenders holding approximately 90% of the aggregate commitments from December 2009available credit line to October 2010. The December amendment added$900 million with an accordion feature allowing us to allow us,increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to increaseprovide such increased commitment amount, and to extend the available credit line from $350 millionterm to $450 million.September 2015. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks’ petroleum engineer)banks based on our reserve reports and engineering reports) and certain other assets.assets and the outstanding principal balance of our senior notes. The amended facility provides for a $1.5 billion borrowing base. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. Management believes thatAs of December 31, 2010, our available credit under our credit facility is $525.0 million.

In June 2010, we haveamended the capacityagreements governing our credit facility and senior notes to financeamend the required asset coverage ratio (the present value of our spending plans and maintain our liquidity. Atproved reserves plus working capital to debt) contained in the same time, we will closely monitoragreements. The amendment also changed the capital markets. As a result of market conditions and our increased level of borrowings, we may experience increased costs associated with future debt.ratio for maximum calculated indebtedness to borrowing base (as defined in the credit facility agreement).

In July 2008, we completed a private placement of $425 million aggregate principal amount of senior unsecured fixed-rate notes with a weighted-average interest rate of 6.51%, consisting of amounts due in July 2018, 2020 and 2023. In December 2008, we completed a private placement of $67 million aggregate principal amount of senior unsecured 9.78% fixed-rate notes due in December 2018. Please refer to Note 4 of the Notes to the Consolidated Financial Statements for further details.

- 37 -


In June 2008, we entered into an underwriting agreement pursuant to which we sold an aggregate of 5,002,500 shares of common stock at a price to us of $62.66 per share. This aggregate share amount included 652,500 shares of common stock that were issued as a result of the exercise of the underwriters’ option to purchase additional shares. We received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used temporarily to reduce outstanding borrowings under our revolving credit facility prior to funding a portion of the purchase price of our east Texas acquisition, which closed in the third quarter of 2008. Immediately prior to (and in connection with) this issuance, we retired 5,002,500 shares of treasury stock, which had a weighted-average purchase price of $16.46.

IndexManagement believes that, with internally generated cash, existing cash and availability under our revolving credit facility, we have the capacity to Financial Statements
finance our spending plans and maintain our strong financial position. At the same time, we will closely monitor the capital markets.

Capitalization

Information about our capitalization is as follows:

 

  December 31,   December 31, 
  2008 2007 
  (Dollars in millions) 

(Dollars in thousands)

  2010 2009 

Debt(1)

  $867.0  $350.0   $975,000   $805,000  

Stockholders’ Equity

   1,790.6   1,070.3   $1,872,700   $1,812,514  
              

Total Capitalization

  $2,657.6  $1,420.3   $2,847,700   $2,617,514  
              

Debt to Capitalization

   33%  25%   34  31

Cash and Cash Equivalents

  $28.1  $18.5   $55,949   $40,158  

 

(1)

Includes $35.9$213.0 million and $20.0 million of current portion of long-term debt at December 31, 2008 and 2007, respectively. Includes $185 million and $140$143.0 million of borrowings outstanding underour revolving credit facility at December 31, 20082010 and 2007,2009, respectively.

For the year ended December 31, 2008,2010, we paid dividends of $12.1$12.5 million ($0.12 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990. After the March 2007 2-for-1 stock split, the dividend was increased to $0.03 per share per quarter, or a 50% increase from pre-split levels.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding any significant oil and gas property acquisitions, with cash generated from operations and, when necessary, borrowings under our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.

The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2008.2010.

 

  2008  2007  2006
  (In millions)

(In thousands)

  2010   2009   2008 

Capital Expenditures

            

Drilling and Facilities(1)

  $624.3  $539.7  $405.5  $654,153    $401,143    $624,344  

Leasehold Acquisitions

   152.7   22.2   42.6   130,675     145,681     152,666  

Acquisitions

   625.0   4.0   6.7   801     394     624,975  

Pipeline and Gathering

   36.9   28.2   24.2   54,811     32,861     36,900  

Other

   10.9   2.3   9.1   8,368     9,506     10,855  
                     
   1,449.8   596.4   488.1   848,808     589,585     1,449,740  

Exploration Expense

   31.2   39.8   49.4   42,725     50,784     31,200  
                     

Total

  $1,481.0  $636.2  $537.5  $891,533    $640,369    $1,480,940  
                     

 

(1)

Includes Canadian currency translation effects of $4.6 million and $(27.7) million $15.0 million in 2009and $(1.4) million2008, respectively. There was no impact from Canadian currency translation in 2008, 2007 and 2006, respectively.2010.

- 38 -


We plan to drill approximately 148110 gross wells (122.3(83.1 net) in 20092011 compared with 432113 gross wells (355(87.1 net) drilled in 2008. The number of wells we plan to drill in 2009 is down from 2008 in each of our operating regions due to the underlying economic fundamentals, which have significantly reduced commodity prices.2010. This 20092011 drilling program includes approximately $475$600 million in total capital and exploration expenditures, down from $1,481$891.5 million in 2008.2010.This decline is primarily due to the lower well count together with lower projected lease acquisition expenditures as the result of our reduced program spending due to lower commodity prices and reduced infrastructure investments. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease the capital and exploration expenditures accordingly.

Index to Financial Statements

There are many factors that impact our depreciation, depletion and amortization (DD&A) rate. These include reserve additions and revisions, development costs, impairments and changes in anticipated production in future periods. In 2009,2011, management expects an increasea small decrease in our DD&A rate primarily due to higher capital costs, partially as a result of inflationary cost pressuresincreased production and reserve additions in the industry over the last four years. This change is currently estimated to be approximately 13% greater than 2008 levels. This increase willMarcellus shale. Such changes in our DD&A rate and related expense do not have an impact on our cash flows.

Contractual Obligations

Our known material contractual obligations include long-term debt, interest on long-term debt, firm gas transportation agreements, drilling rig commitments and operating leases. We have no off-balance sheet debt or other similar unrecorded obligations.

A summary of our contractual obligations as of December 31, 20082010 are set forth in the following table:

 

  Total  Payments Due by Year      Payments Due by Year 
  2009  2010 to
2011
  2012 to
2013
  2014 &
Beyond
  (In thousands)

(In thousands)

  Total   2011   2012 to
2013
   2014 to
2015
   2016 &
Beyond
 

Long-Term Debt(1)

  $867,000  $35,857  $244,143  $75,000  $512,000  $975,000    $—      $75,000    $—      $900,000  

Interest on Long-Term Debt(2)

   460,624   63,124   99,602   82,469   215,429   448,894     59,140     112,780     99,098     177,876  

Firm Gas Transportation Agreements(3)

   94,670   13,218   23,935   13,374   44,143   485,619     32,504     64,040     56,712     332,363  

Drilling Rig Commitments(3)

   44,271   42,021   2,250   —     —  

Operating Leases(3)

   28,686   6,335   9,028   7,397   5,926   22,158     5,414     9,902     6,842     —    
                                   

Total Contractual Cash Obligations

  $1,495,251  $160,555  $378,958  $178,240  $777,498  $1,931,671    $97,058    $261,722    $162,652    $1,410,239  
                                   

 

(1)

Including current portion. At December 31, 2008,2010, we had $185$213.0 million of debt outstanding under our revolving credit facility. See Note 45 of the Notes tothe Consolidated Financial Statements for details of long-term debt.

(2)

Interest payments have been calculated utilizing the fixed rates of our $682$762.0 million long-term debt outstanding at December 31, 2008.2010. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2008 long-term2010 outstandingbalance of $169.1$213.0 million will be outstanding through the October 2010September 2015 maturity date and that the short-term outstanding balance of $15.9 million will be outstanding through December 2009.date. A constant interest rate of 4.8%3.8% wasassumed, which was the 20082010 weighted-average interest rate. Actual results will likely differ from these estimates and assumptions.

(3)

For further information on our obligations under firm gas transportation agreements drilling rig commitments and operating leases, see Note 78 of the Notes to the Consolidated Financial Statements.

Amounts related to our asset retirement obligations are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 20082010 was $28.0$72.3 million, up from $24.7$29.7 million at December 31, 2007,2009, primarily due to $1.2$40.4 million in revisions of previous estimates due to increased plugging and abandonment costs and $1.9 million in accretion expense during 2008 as well as $2.2 million2010. See Note 9 of drilling additions.the Notes to the Consolidated Financial Statements for further details.

Potential Impact of Our Critical Accounting Policies

Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. TheOur most significant policies are discussed below.

- 39 -


Successful Efforts Method of Accounting

We follow the successful efforts method of accounting for our oil and gas producing activities. Acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole costs are expensed. Development costs, including costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Oil and Gas Reserves

The process of estimating quantities of proved reserves is inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic,

Index to Financial Statements

geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds.

Since 1990, 100% Any significant variance in the interpretations or assumptions could materially affect the estimated quantity and value of our reserves.

Our reserves have been reviewedprepared by our petroleum engineering staff and audited by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm,petroleum engineers, who in their opinion determined the estimates presented to be reasonable in the aggregate. We have not been required to record a significant reserve revision in the past three years. For more information regarding reserve estimation, including historical reserve revisions, refer to the “Supplemental Oil and Gas Information.”

Our rate of recording DD&A expense is dependent upon our estimate of proved and proved developed reserves, which isare utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it non-economicuneconomic to drill for and produce higher cost fields. A five percent positive or negative revision to proved reserves throughout the Company would decrease or increase the DD&A rate by approximately $0.09($0.10) to $0.10$0.12 per Mcfe. Revisions in significant fields may individually affect our DD&A rate. It is estimated that a positive or negative reserve revision of 10% in one of our most productive fields would have a $0.05($0.06) to $0.06$0.07 per Mcfe impact on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to our DD&A rate.

In addition, a decline in proved reserve estimates may impact the outcome of our impairment test under Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.Codification (ASC) 360, “Property, Plant, and Equipment.” Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.

Carrying Value of Oil and Gas Properties

We evaluate the impairment of our oil and gas properties on a lease-by-leasefield-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used (13% at December 31, 2008) is based on management’s belief that this rate is commensurate with the risks inherent in the development and production of the underlying natural gas and oil. In 2008, 2007 and 2006, there were no unusual or unexpected occurrences that caused significant revisions in estimated cash flows which were utilized in our impairment test. In the event that commodity prices remain low or continue to decline, there could be a significant revision in the future. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.

- 40 -


Costs attributable to our unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property lives. Average property lives are determined on a regionalgeographical basis and based on the estimated life of unproved property leasehold rights. Historically, the average property life in each of the regions has not significantly changed. During the last six months of 2008,The commodity prices declined at a significant rate as the global economy struggled with a worldwide recession. This price environment has resulted in reducedmay impact the capital available for exploration projects as well as development drilling. We have considered these impacts discussed above when assessingdetermining the impairmentamortization rate of our undeveloped acreage, especially in exploratory areas. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $13.3$17.3 million or decrease by approximately $10.7$12.3 million, respectively per year.

Index to Financial Statements

In the past, based on the customary terms of the leases, the average leasehold life in the Gulf CoastSouth region has been shorter than the average life in the East and West regions.North region. Average property lives in the East, Gulf CoastNorth and WestSouth regions have been five four and seventhree years, respectively. Average property lives in Canada are estimated to be five years. As these properties are developed and reserves are proven, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration and development program.

Asset Retirement Obligation

The majority of our asset retirement obligation relates to the plugging and abandonment of oil and gas wells and to a lesser extent meter stations, pipelines, processing plants and compressors. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. The recognition of an asset retirement obligation requires management to make assumptions that include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rate. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life, while increases in the discounted ARO liability resulting from the passage of time (accretion expense) is reflected as depreciation, depletion and amortization expense.

Accounting for Derivative Instruments and Hedging Activities

We follow the accounting prescribed in SFAS No. 133.ASC 815. Under SFAS No. 133,ASC 815, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Accumulated Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is designated as a hedge and is effective. Under SFAS No. 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated, and 100% effective, if the underlying gas were sold at the Henry Hub index. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives not qualifying as hedges, is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue as appropriate in the Consolidated Statement of Operations.

Fair Value Measurements

Effective January 1, 2008, we adopted those provisions of SFAS No. 157, “Fair Value Measurements,” that were required to be adopted. This adoption did not have a material impact on any of our financial statements. As defined in SFAS No. 157,The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

We utilize market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We attempt to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to level 1 measurements and the lowest priority to level 3 measurements, and accordingly, level 1 measurements should be used whenever possible.

As of December 31, 2008, we had $355.2 million of assets, or 10% of our total assets, classified as Level 3. This was entirely comprised of our derivative receivable balanceinstruments are measured based on quotes from our oil and gas cash flow hedges. During 2008, realized gains of $347.9 million were recognized in other comprehensive income. Derivative settlements during the year totaled $13.0 million. The fair values of our natural gas and crude oil price collars and swaps are valued based upon quotes obtained from counterparties to the agreements and are designated as Level 3.Company’s counterparties. Such quotes have been derived using a Black-Scholes model for the active oil and gas commodities marketvaluation models that considersconsider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. Although we utilizeterm as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes to assess the reasonableness of our values, we have not attempted to obtain sufficient corroborating market evidence to support classifying these derivative contracts as Level 2. We adjust the fair value quotes received by ourobtained from counterparties to take into account either the counterparties’ nonperformance risk or our own nonperformance

Index to Financial Statements

risk. Wefor reasonableness. The Company measured the nonperformance risk of ourits counterparties by reviewing credit default swap spreads for the various financial institutions in which we haveit has derivative transactions and made a reduction to our derivative receivable.transactions. In times where we have net derivative contract liabilities, our nonperformance risk is evaluated using a market credit spread provided by our bank. Additional disclosures are required for transactions measured at fair value and we have included these disclosures in Note 7 of the Notes to the Consolidated Financial Statements.

- 41 -


Long-Term Employee Benefit CostsPlans

Our costs of long-term employee benefits, particularly pension and postretirement benefits, are incurred over long periods of time, and involve many uncertainties over those periods. The net periodic benefit cost attributable to current periods is based on several assumptions about such future uncertainties, and is sensitive to changes in those assumptions. It is management’s responsibility, often with the assistance of independent experts, to select assumptions that in its judgment represent best estimates of those uncertainties. It also is management’s responsibility to review those assumptions periodically to reflect changes in economic or other factors that affect those assumptions.

The current benefit service costs, as well as the existing liabilities, for pensions and other postretirement benefits are measured on a discounted present value basis. The discount rate is a current rate, related Significant assumptions used to the rate at which the liabilities could be settled. Our assumed discount rate is based on average rates of return published for a theoretical portfolio of high-quality fixed income securities. In order to select the discount rate, we use benchmarks such as the Moody’s Aa Corporate Rate, which was 5.54% as of December 31, 2008, and the Citigroup Pension Liability Index, which was 5.87% as of December 31, 2008. We look to these benchmarks as well as considering durations of expected benefit payments. We have determined based on these assumptions that a discount rate of 5.75% at December 31, 2008 is reasonable.

In order to valuedetermine our projected pension liabilities, we use the RP-2000 Combined Mortality Table based on the demographics of our benefit plans. We have also assumed that salaries will increase four percent based on our expectation of future salary increases.

The benefit obligation and the periodic cost of postretirement medical benefits also are measured based on assumedrelated costs include discount rates, of future increase in the per capita cost of covered health care benefits. As of December 31, 2008, the assumed rate of increase was 9.0%. The net periodic cost of pension benefits included in expense also is affected by the expected long-term rate of return on plan assets assumption. The expected return on plan assets, rate is normally changed less frequently than the assumed discount rate, and reflects long-term expectations, rather than current fluctuations in market conditions. The actual rate of return on plan assets may differ fromcompensation increases, while the expected rate dueassumptions used to determine our postretirement benefit obligation and related costs include discount rates and health care cost trends. See Note 6 of the Notes to the volatility normally experienced in capital markets. Management’s goal is to manage the investments over the long-term to achieve optimal returns with an acceptable level of risk and volatility.

We have established objectives regarding plan assets in the pension plan. We attempt to maximize return over the long-term, subject to appropriate levels of risk. OneConsolidated Financial Statements for a full discussion of our plan objectives is that the performance of the equity portion of the pension plan exceed the Standard and Poors’ 500 Index over the long-term. We also seek to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. We establish the long-term expected rate of return by developing a forward-looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. In our pension calculations, we have used eight percent as the expected long-term return on plan assets for 2008, 2007 and 2006. A Monte Carlo simulation was run using 5,000 simulations based upon our actual asset allocation and liability duration, which has been determined to be approximately 15 years. This model uses historical data for the period of 1926-2007 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that we expect to achieve over 50 percent of the time, is approximately nine percent. We expect to achieve at a minimum approximately 7% annual real rate of return on the total portfolio over the long-term at least 75 percent of the time. We believe that the eight percent chosen is a reasonable estimate based on our actual results.

Index to Financial Statements

We generally target a portfolio of assets utilizing equity securities, fixed income securities and cash equivalents that are within a range of approximately 50% to 80% for equity securities and approximately 20% to 40% for fixed income securities. Large capitalization equities may make up a maximum of 65% of the portfolio. Small capitalization equities and international equities may make up a maximum of 30% and 15%, respectively, of the portfolio. Fixed income bonds may make up a maximum of 40% of our portfolio. The account will typically be fully invested; however, as a temporary investment or an asset protection measure, part of the account may be invested in money market investments up to 20%. One percent of the portfolio is invested in short-term funds at the designated bank to meet the cash flow needs of the plan. No prohibited investments, including direct or indirect investments in commodities, commodity futures, derivatives, short sales, real estate investment trusts, letter stock, restricted stock or other private placements, are allowed without prior committee approval.employee benefit plans.

Stock-Based Compensation

We account for stock-based compensation under a fair value based method of accounting for stock options and similar equity instruments.prescribed under ASC 718. Under the fair value method, compensation cost is measured at the grant date and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. The use of these models requires significant judgment with respect to expected life, volatility and other factors. Stock-based compensation cost for all types of awards is included in General and Administrative Expense in the Consolidated Statement of Operations.

Stock options and stock appreciation rights (SARs) are granted with an exercise price equal to the average of the high and low trading price of our stock on the grant date. The grant date fair value is calculated by using a Black-Scholes model that incorporations assumptions for stock price volatility, risk free rate of return, expected dividend and expected term. The expected term was derived by reviewing minimum and maximum expected term outputs from the Black-Scholes model based on award type and employee type. This term represents the period of time that awards granted are expected to be outstanding. The stock price volatility was calculated using our historical closing stock price data for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the US Treasury (Nominal 10) within the expected term as measured on the grant date. The expected dividend percentage assumes that we will continue to pay a consistent level of dividend each quarter. Expense is recorded based on a graded-vesting schedule over a three year service period, with one-third of the award becoming exercisable each year on the anniversary date of the grant. The forfeiture rate is determined based on the forfeiture history by type of award and by the group of individuals receiving the award.

The fair value of restricted stock awards, restricted stock units and certain performance share awards (which contain vesting restrictions based either on operating income or internal performance metrics) are measured based on the average of the high and low trading price of our stock on the grant date. Restricted stock awards primarily vest either at the end of a three year service period, or on a graded-vesting basis of one-third at each anniversary date over a three year service period. The annual forfeiture rate for restricted stock awards ranges from 0% to 7.2% based on approximately ten years of our history for this type of award to various employee groups. Performance shares that vest based on operating income vest on a graded-vesting basis of one-third at each anniversary date over a three year service period and no forfeiture rate is assumed. Performance shares that vest based on internal metrics vest at the end of a three year performance period and an annual forfeiture rate of 4.5% is assumed. Expense for restricted stock units is recorded immediately as these awards vest immediately. Restricted stock units are granted only to our directors and no forfeiture rate is assumed.

We grant another type of performance share award to executive employees that vest at the end of a three year performance period based on the comparative performance of our stock measured against sixteen other companies in our peer group. Depending on our performance, up to 100% of the fair market value of a share of our stock may be payable in stock plus an additional 100% of the fair market value of a share of our stock may be payable in cash. These awards are accounted for by bifurcating the equity and liability components. A Monte

Index to Financial Statements

Carlo model is used to value the liability component as well as the equity portion of the certain awards on the date of grant. The four primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns, correlation in movement of total shareholder return and the expected dividend. The risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for one and two year bonds and is set equal to the yield, for the period over the remaining duration of the performance period, on treasury securities as of the reporting date. Volatility was set equal to the annualized daily volatility measured over a historic one and two year period ending on the reporting date. Correlation in movement of total shareholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including us. The paired returns in the correlation matrix ranged from approximately 71% to approximately 89% for us and our peer group. The expected dividend is calculated using our dividends paid ($0.12 for 2008) divided by the December 31, 2008 closing price of our stock ($26.00). Based on these inputs discussed above, a ranking was projected identifying our rank relative to the peer group. No forfeiture rate is assumed for this type of award. Expense related to these awards can be volatile based on our comparative ranking at the end of each quarter.

We used the shortcut approach to derive our initial windfall tax benefit pool. We chose to use a one-pool approach which combines all awards granted to employees, including non-employee directors.

On January 16, 2008, our Board of Directors adopted a Supplemental Employee Incentive Plan. The plan was intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event our common stock reached specified trading prices. The bonus payout of a minimum of 50% of an employee’s base salary was triggered if, for any 20 trading days (which need not be consecutive) that fell within a period of 60 consecutive trading days occurring on or before November 1, 2011, the closing price per share of our common stock equaled or exceeded the final price goal of $60 per share. The plan also provided that an interim distribution of 10% of an employee’s base salary would be paid to eligible employees upon achieving the interim price goal of $50 per share prior to December 31, 2009.

On the January 16, 2008 adoption date of the plan, our closing stock price was $40.71. On April 8, 2008 and subsequently on June 2, 2008, we achieved the interim and final target goals and total distributions of $15.7 million were paid in 2009. No further distributions will be made under this plan.

On July 24, 2008, our Board of Directors adopted a second Supplemental Employee Incentive Plan (“Plan II”). Plan II is similar to the January 2008 Supplemental Incentive Plan; however, the final target is that the closing price per share of our common stock must equal or exceed the price goal of $105 per share on or before June 20, 2012. Under Plan II, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 50% of his or her base salary (or 30% of base salary if we paid interim distributions upon the achievement of the interim price goal discussed below). Plan II provides that a distribution of 20% of an eligible employee’s base salary upon achieving the interim price goal of $85 per share on or before June 30, 2010. The Compensation Committee can increase the 50% or 20% payment as it applies to any employee. Payments under this plan will partially be paid within 15 business days after achieving the target and the remaining portion will be paid based on a separate payment date as described in Plan II.

These awards under both plans discussed above have been accounted for as liability awards under SFAS No. 123(R), and the total expense for 2008 was $15.9 million. For further information regarding the supplemental employee incentive plans and our other stock-based compensation awards, please refer to See Note 1012 of the Notes to the Consolidated Financial Statements.Statements for a full discussion of our stock-based compensation.

OTHER ISSUES AND CONTINGENCIES

Regulations. Our operations are subject to various types of regulation by federal, state and local authorities. See “Regulation of Oil and Natural Gas Exploration and Production,” “Natural Gas Marketing, Gathering and

Index to Financial Statements

Transportation,” “Federal Regulation of Petroleum” and “Environmental Regulations” in the “Other Business Matters” section of Item 1 for a discussion of these regulations.

Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. In addition, we are required to maintain an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0 and a current ratio of 1.0 to 1.0. Our senior notes require us to maintain a ratio of cash and proved reserves to indebtedness and other liabilities of 1.51.75 to 1.0. At December 31, 2008,2010, we were in compliance in all material respects with all restrictive covenants on both the revolving credit agreement and notes. In the unforeseen event that we fail to comply with these covenants, we may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation. See further discussion in “Capital Resources and Liquidity.”

Operating Risks and Insurance Coverage.Our business involves a variety of operating risks. See “Risk Factors—We face a variety of hazards and risks that could cause substantial financial losses” in Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have invested a significant portion of our drilling dollars in the Gulf Coast, where insurance rates are significantly higher than in other regions such as the East.

Commodity Pricing and Risk Management Activities.Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and to a lesser extent, oil. Declines in oil and gas prices may have a material adverse effect on our financial condition, liquidity,

- 42 -


ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially trigger an impairment under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.ASC 360, “Property, Plant, and Equipment.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly largemore significant impact on our financial results.

The majority of our production is sold at market responsive prices. Generally, if the related commodity indexes fall,index falls, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk on all or a portion of our anticipated production with the use of derivative financial instruments. Most recently, we have used financial instruments such as price collars and swap arrangements to reduce the impact of declining prices on our revenue. Under both arrangements, there is also a risk that the movement of index prices may result in our inability to realize the full benefit of an improvement in market conditions.

Recently Issued Accounting Pronouncements

Settlement of Dispute.In December 2008, we settled a dispute with a third party and as a result recorded a gain of $51.9 million. The dispute involved the SECpropriety of possession of our intellectual property by a third party. The settlement was comprised of $20.2 million in cash paid by the third party to us and $31.7 million related to the fair value of unproved property rights transferred by the third party to us. The fair market value of the unproved property rights was determined based on observable market costs and conditions over a recent time period. Values were pro-rated by property based on the primary term remaining on the properties.

Recently Adopted Accounting Standards

In February 2010, the FASB issued ReleaseAccounting Standards Update (ASU) No. 33-8995, “Modernization of Oil and Gas Reporting,2010-09, “Subsequent Events,” which amends ASC 855 to eliminate the oilrequirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 will be required to price proved oil and gas reserves using the unweighted arithmetic average of the priceits adoption had no impact on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning January 1, 2010. We are currently evaluating what impact Release No. 33-8995 may have on ourCompany’s financial position, results of operations or cash flows.

IndexEffective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to Financial Statements

require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In June 2008,addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” Under this FSP, unvested share-based payment awards that contain nonforfeitable rightslevel of disaggregation and inputs and valuation techniques and makes conforming amendments to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securitiesthe guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and should be includedsettlements in the computation of earnings per share pursuant to the two-class method. FSP No. EITF 03-6-1 isLevel 3 reconciliation are effective for financial statements issued for fiscal years beginning after December 15, 2008, and2010 (and for interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. We do not believe that FSP No. EITF 03-6-1such years). Accordingly, the Company will have a materialapply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on our financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies a consistent framework for selecting accounting principles to be used in preparing financial statements for nongovernmental entities that are presented in conformity with United States generally accepted accounting principles (GAAP). The current GAAP hierarchy was criticized due to its complexity, ranking position of FASB Statements of Financial Accounting Concepts and the fact that it is directed at auditors rather than entities. SFAS No. 162 will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” The FASB does not expect that SFAS No. 162 will have a change in current practice, and we do not believe that SFAS No. 162 will have an impact on our financial position, results of operations or cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Enhanced disclosures to improve financial reporting transparency are required and include disclosure about the location and amounts of derivative instruments in the financial statements, how derivative instruments are accounted for and how derivatives affect an entity’s financial position, financial performance and cash flows. A tabular format including the fair value of derivative instruments and their gains and losses, disclosure about credit risk-related derivative features and cross-referencing within the footnotes are also new requirements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application and comparative disclosures encouraged, but not required. We have not yet adopted SFAS No. 161. We do not believe that there will be an impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS No. 141(R) will have on ourCompany’s financial position, results of operations or cash flows with respectas a result of the partial adoption of ASU No. 2010-06. For further information, please refer to any acquisitions completed after December 31, 2008.Note 14.

Forward-Looking Information

The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,”

Index to Financial Statements

“forecast, “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and

- 43 -


uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

RESULTS OF OPERATIONS

20082010 and 20072009 Compared

We reported net income for the year ended December 31, 20082010 of $211.3$103.4 million, or $2.10$0.99 per share. During 2007,2009, we reported net income of $167.4$148.3 million, or $1.73$1.43 per share. This increase of $43.9Net income decreased in 2010 by $45.0 million, in net income was primarily due to an increase inincreased operating, revenuesincome tax and gains on asset salesinterest expenses and settlements,decreased operating revenues partially offset by increased operating, interest and income tax expenses.gain on sale of assets. Operating revenues increaseddecreased by $213.6$35.2 million largely due to increasesdecreases in both natural gas production revenues and brokered natural gas revenues, andpartially offset by an increase in crude oil and condensate revenues. Operating expenses increased by $155.9$90.2 million between periods due primarily to increases in all categoriesdepreciation, depletion and amortization, impairment of operating expensesoil and gas properties and other assets, general and administrative expense and direct operations. These increases were partially offset by decreases in brokered natural gas cost, taxes other than income and exploration expense. In addition, net income was impacted by an increase in gain on sale

Revenue, Price and Volume Variances

Below is a discussion of assetsrevenue, price and gain on settlement of dispute of $39.6 million as well as an increase in expenses of $53.4 million resulting from a combination of increased income tax expense and interest and other expenses. Income tax expense was higher in 2008 as a result of higher income before income taxes in 2008 compared to 2007, in addition to an increase in the effective tax rate.volume variances.

   Year Ended December 31,   Variance 
         2010               2009         Amount   Percent 

Revenue Variances (In thousands)

        

Natural Gas(1) 

  $694,803    $731,688    $(36,885)     (5%) 

Brokered Natural Gas

   65,281     75,283     (10,002)     (13%) 

Crude Oil and Condensate

   79,091     69,936     9,155     13

Other

   5,086     4,323     763     18

(1)

Natural Gas Revenues exclude the unrealized loss from the change in fair value of our basis swaps of $0.2 million and $2.0 million in 2010 and 2009, respectively.

   Year Ended December 31,   Variance  Increase
(Decrease)
(In thousands)
 
         2010               2009         Amount  Percent  

Price Variances

        

Natural Gas(1)

  $5.54    $7.47    $(1.93  (26%)  $(242,758

Crude Oil and Condensate(2)

  $97.91    $85.52    $12.39    14  10,010  
           

Total

        $(232,748
           

Volume Variances

        

Natural Gas (Mmcf)

   125,474     97,914     27,560    28 $205,873  

Crude Oil and Condensate (Mbbl)

   808     818     (10  (1%)   (855
           

Total

        $205,018  
           

(1)

These prices include the realized impact of derivative instrument settlements, which increased the price by $1.23 per Mcf in 2010 and by $3.80 per Mcf in 2009.

(2)

These prices include the realized impact of derivative instrument settlements, which increased the price by $22.31 per Bbl in 2010 and by $28.85 per Bbl in 2009.

- 44 -


Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $8.39 per Mcf for 2008 compared to $7.23 per Mcf for 2007. These prices include the realized impact of derivative instrument settlements, which increased the price by $0.20 per Mcf in 2008 and by $0.99 per Mcf in 2007. There was no revenue impact from the unrealized change in natural gas derivative fair value for the years ended December 31, 2008 and 2007.

   Year Ended
December 31,
  Variance 
   2008  2007  Amount  Percent 

Natural Gas Production(Mmcf)

        

East

   25,171   24,344   827  3%

Gulf Coast

   34,577   26,797   7,780  29%

West

   26,535   25,409   1,126  4%

Canada

   4,142   3,925   217  6%
              

Total Company

   90,425   80,475   9,950  12%
              

Natural Gas Production Sales Price($/Mcf)

        

East

  $8.54  $7.78  $0.76  10%

Gulf Coast

  $9.23  $8.03  $1.20  15%

West

  $7.28  $6.13  $1.15  19%

Canada

  $7.62  $5.47  $2.15  39%

Total Company

  $8.39  $7.23  $1.16  16%

Natural Gas Production Revenue(In thousands)

        

East

  $214,852  $189,392  $25,460  13%

Gulf Coast

   319,246   215,106   104,140  48%

West

   193,100   155,676   37,424  24%

Canada

   31,557   21,466   10,091  47%
              

Total Company

  $758,755  $581,640  $177,115  30%
              

Index to Financial Statements
   Year Ended
December 31,
  Variance
   2008  2007  Amount  Percent

Price Variance Impact on Natural Gas Production Revenue

        

(In thousands)

        

East

  $19,029      

Gulf Coast

   41,347      

West

   30,524      

Canada

   8,906      
          

Total Company

  $99,806      
          

Volume Variance Impact on Natural Gas Production Revenue

        

(In thousands)

        

East

  $6,431      

Gulf Coast

   62,793      

West

   6,900      

Canada

   1,185      
          

Total Company

  $77,309      
          

The increasedecrease in Natural Gas Production Revenue of $177.1$36.9 million, excluding the impact of the unrealized gains and losses discussed above, is due primarily to the increasedecrease in realized natural gas sales prices, decreased production in additionthe South region associated with normal production declines, delays in completions and a shift from gas to oil projects, as well as the sale of our Canadian properties in April 2009. Partially offsetting these decreases was an increase in natural gas production. Natural gas production in the Gulf CoastNorth region associated with increased drilling and the start up of a portion of the Lathrop compressor station in the Marcellus shale at the end of the second quarter of 2010.

Crude Oil and Condensate Revenues

The $9.2 million increase in crude oil and condensate revenues is primarily due to increasedan increase in realized crude oil prices and an increase in crude oil production in the Minden field, largely due toSouth region associated with the properties we acquiredEagle Ford shale and Pettet formation production. These increases are partially offset by lower production in east Texas in August 2008,the North region as well as increased drillingthe sale of our Canadian properties in the County Line field. In addition, natural gas production increased in the West region associated with an increase in the drilling program, increased in the East region as a result of increased drilling activity in West Virginia and northeastern Pennsylvania. Canada increased due to drilling in the Hinton field.April 2009.

Brokered Natural Gas Revenue and Cost

 

   Year Ended
December 31,
  Variance 
   2008  2007  Amount  Percent 

Sales Price($/Mcf)

  $10.39  $8.40  $1.99  24%

Volume Brokered(Mmcf)

  x10,996  x11,101   (105) (1%)
           

Brokered Natural Gas Revenues(In thousands)

  $114,220  $93,215   
           

Purchase Price($/Mcf)

  $9.14  $7.37  $1.77  24%

Volume Brokered(Mmcf)

  x10,996  x11,101   (105) (1%)
           

Brokered Natural Gas Cost(In thousands)

  $100,449  $81,819   
           

Brokered Natural Gas Margin(In thousands)

  $13,771  $11,396  $2,375  21%
              

(In thousands)

      

Sales Price Variance Impact on Revenue

  $21,882     

Volume Variance Impact on Revenue

   (882)    
         
  $21,000     
         

(In thousands)

      

Purchase Price Variance Impact on Purchases

  $(19,399)    

Volume Variance Impact on Purchases

   774     
         
  $(18,625)    
         
   Year Ended
December 31,
   Variance  Price and
Volume
Variances
(In thousands)
 
   2010   2009   Amount  Percent  

Brokered Natural Gas Sales

        

Sales Price ($/Mcf)

  $5.41    $5.95    $(0.54  (9%)  $(6,527

Volume Brokered (Mmcf)

  x12,072    x12,656     (584  (5%)   (3,475
                 

Brokered Natural Gas Revenues (In thousands)

  $65,281    $75,283      $(10,002
                 

Brokered Natural Gas Purchases

        

Purchase Price ($/Mcf)

  $4.68    $5.30    $(0.62  (12%)  $7,489  

Volume Brokered (Mmcf)

  x12,072    x12,656     (584  (5%)   3,075  
                 

Brokered Natural Gas Cost (In thousands)

  $56,466    $67,030      $10,564  
                 

Brokered Natural Gas Margin (In thousands)

  $8,815    $8,253      $562  
                 

The increased brokered natural gas margin of $2.4$0.6 million is a result of an increasea lesser decrease in sales price that outpaced the increasethan in purchase price, partially offset by a decrease in the volumes brokered in 2008 over 2007.brokered.

Index to Financial Statements

Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price was $89.11 per Bbl for 2008 compared to $67.16 per Bbl for 2007. These prices include the realized impact of derivative instrument settlements, which decreased the price by $6.33 per Bbl in 2008 and by $0.97 per Bbl in 2007. There was no revenue impact from the unrealized change in crude oil and condensate derivative fair value in 2008 or 2007.

 

   Year Ended
December 31,
  Variance 
   2008  2007  Amount  Percent 

Crude Oil Production(Mbbl)

      

East

   23   26   (3) (12%)

Gulf Coast

   578   605   (27) (4%)

West

   160   174   (14) (8%)

Canada

   21   18   3  17%
              

Total Company

   782   823   (41) (5%)
              

Crude Oil Sales Price($/Bbl)

      

East

  $92.07  $66.97  $25.10  37%

Gulf Coast

  $87.39  $67.17  $20.22  30%

West

  $95.48  $67.86  $27.62  41%

Canada

  $85.08  $59.96  $25.12  42%

Total Company

  $89.11  $67.16  $21.95  33%

Crude Oil Revenue(In thousands)

      

East

  $2,101  $1,734  $367  21%

Gulf Coast

   50,540   40,673   9,867  24%

West

   15,243   11,784   3,459  29%

Canada

   1,827   1,052   775  74%
              

Total Company

  $69,711  $55,243  $14,468  26%
              

Price Variance Impact on Crude Oil Revenue

      

(In thousands)

      

East

  $573     

Gulf Coast

   11,691     

West

   4,409     

Canada

   600     
         

Total Company

  $17,273     
         

Volume Variance Impact on Crude Oil Revenue

      

(In thousands)

      

East

  $(206)    

Gulf Coast

   (1,824)    

West

   (950)    

Canada

   175     
         

Total Company

  $(2,805)    
         

The increase in realized crude oil prices, partially offset by a decrease in production, resulted in a net revenue increase of $14.4 million. The decrease in oil production is mainly the result of a natural decline in crude oil production in the Gulf Coast and West regions.

- 45 -

Index to Financial Statements

Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

 

   Year Ended December 31,
   2008  2007
    Realized  Unrealized  Realized  Unrealized
   (In thousands)

Operating Revenues - Increase/(Decrease) to Revenue

      

Cash Flow Hedges

      

Natural Gas Production

  $17,972  $—    $79,838  $—  

Crude Oil

   (4,951)  —     (796)  —  
                

Total Cash Flow Hedges

  $13,021  $—    $79,042  $—  
                

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our primary derivative contract counterparties are JPMorgan Chase, Morgan Stanley, BNP Paribas, Goldman Sachs, and Bank of Montreal.

   Year Ended December 31, 
   2010  2009 

(In thousands)

  Realized   Unrealized  Realized   Unrealized 

Operating Revenues—Increase / (Decrease) to Revenue

       

Cash Flow Hedges

       

Natural Gas

  $154,960    $—     $371,915    $—    

Crude Oil

   18,030     —      23,112     —    
                   

Total Cash Flow Hedges

   172,990     —      395,027     —    
                   

Other Derivative Financial Instruments

       

Natural Gas Basis Swaps

   —       (226  —       (1,954
                   

Total Other Derivative Financial Instruments

   —       (226  —       (1,954
                   

Total Cash Flow Hedges and Other Derivative Financial Instruments

  $172,990    $(226 $395,027    $(1,954
                   

Operating and Other Expenses

   Year Ended December 31,   Variance 

(In thousands)

        2010          2009         Amount  Percent 

Operating and Other Expenses

      

Brokered Natural Gas Cost

  $56,466   $67,030    $(10,564  (16%) 

Direct Operations—Field and Pipeline

   99,642    93,985     5,657    6

Taxes Other Than Income

   37,894    44,649     (6,755  (15%) 

Exploration

   42,725    50,784     (8,059  (16%) 

Depreciation, Depletion and Amortization

   327,083    251,260     75,823    30

Impairment of Oil and Gas Properties and Other Assets

   40,903    17,622     23,281    132

General and Administrative

   79,177    68,374     10,803    16
                  

Total Operating Expense

  $683,890   $593,704    $90,186    15

(Gain) / Loss on Sale of Assets

  $(106,294 $3,303    $(109,597  (3,318%) 

Interest Expense and Other

   67,941    58,979     8,962    15

Income Tax Expense

   95,112    74,947     20,165    27

Total costs and expenses from operations increased by $155.9$90.2 million in 2008 from 2007.2009 to 2010. The primary reasons for this fluctuation are as follows:

 

Depreciation, Depletion and Amortization increased by $41.5$75.8 million from 20072009 to 2008. This is2010, primarily due to the impact on the DD&A rate of higherincreased depreciation and depletion from increased capital costsspending and higher natural gasequivalent production volumes, includingvolumes. Amortization of unproved properties increased $17.6 million primarily due to increased unproved leasehold costs in the eastMarcellus shale and the Eagle Ford shale in south Texas acquisition.in late 2009 and continuing into 2010.

 

Impairment of Oil & Gas Properties and Other Assets increased by $31.1$23.3 million from 20072009 to 2008 primarily2010. Impairments in 2010 consisted of a $35.8 million impairment of two south Texas fields due to continued price declines and limited activity and a $5.1 million impairment related to impairments of approximately $28.3 million in the Trawick field in Rusk County, Texas in the Gulf Coast region resulting from a decline in natural gas pricesdrilling and higher well costs as well as $3.0 million in the Corral Creek field in Washakie County, Wyoming in the West region resulting from lower than expected performance from the two well field.service equipment.

 

- 46 -


General and Administrative expenses increased by $23.4$10.8 million from 20072009 to 2008. This2010. The increase is primarily due to increaseda $9.9 million increase in legal expenses primarily related to the December 2010 PaDEP settlement, ongoing litigation and related legal fees, a $8.3 million increase in pension expense primarily due to termination and amendment of our pension plans and a $2.4 million increase in incentive compensation. These increases were partially offset by an $8.5 million decrease in stock compensation expense related to the payouts of our supplemental employee incentive plan bonuses ($15.7 million) as well as increased expense related to our performance share awards ($5.1 million).

Impairment of Unproved Properties increased by $22.5 million from 2007 to 2008, primarily due to increased lease acquisition costsprior year awards that fully vested in several exploratoryFebruary 2010 and developmental areas, as well as a $17.0 million charge for the impairment of three exploratory oil and gas prospects locatedreduction in Mississippi, Montana and North Dakota. These prospects were impaired as a result of the significant decline in commodity prices in the fourth quarter of 2008 and abandonment of our exploration plans.stock price.

 

Brokered Natural Gas Cost increaseddecreased by $18.6$10.6 million from 20072009 to 2008.2010. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

Exploration expense decreased by $8.1 million from 2009 to 2010 primarily due to lower dry hole costs as a result of drilling one dry hole in 2010 compared to two dry holes in 2009. The decrease was partially offset by higher geophysical and geological expenses associated with seismic purchases related to our Marcellus, Eagle Ford and Haynesville shale properties during 2010.

Taxes Other Than Income decreased by $6.8 million from 2009 to 2010 primarily due to decreased production and ad valorem taxes due to lower natural gas prices and property values partially offset by increased business and occupational taxes and franchise taxes.

Direct Operations expenses increased by $14.6$5.7 million from 20072009 to 20082010 primarily due to higher personnellease maintenance expense in both the North and labor expenses, maintenance expenses, treating, compressor, pipelineSouth regions and workoverplug and abandonment costs in the North region related to plugging and vehicleabandoning three vertical wells in accordance with the PaDEP’s Second Modified Consent Order.

Gain / (Loss) on Sale of Assets

Gain / (Loss) on Sale of Assets increased by $109.6 million from 2009 to 2010. During 2010, we recognized a gain of $49.3 million from the sale of our Pennsylvania gathering infrastructure, $40.7 million from the sale of our investment in Tourmaline, $10.8 million from the sale of certain oil and fuel expenses,gas properties in the Texas Panhandle, $10.3 million on the sale of our Woodford shale properties, partially offset by lower insurance costs.

an impairment loss of $5.1 million on certain oil and gas properties in Colorado.

Index to Financial Statements

Taxes Other Than Income increased by $12.8During 2009, we recognized a $16.0 million from 2007 to 2008loss on sale of assets primarily due to higher production taxes as a resultthe sale of higher operating revenues and, to a lesser extent, higher ad valorem taxes,the Canadian properties, partially offset by lower franchise taxes.

Exploration expense decreased by $8.6a $12.7 million from 2007gain on sale of assets related to 2008 primarily due to fewer dry holes, partially offset by increased geological and geophysical costs.the sale of our Thornwood properties in the North region.

Interest Expense, Net

Interest expense, net increased by $19.2$9.0 million in 2008 comparedfrom 2009 to 20072010 primarily due to increased interest expense related to the debt we issuedan increase in our July and December 2008 private placements and, to a lesser extent, higher average credit facility borrowings, offset in part by a lower weighted-average interest rate on our revolving credit facility borrowings and lower outstanding borrowings on our 7.19% fixed rate debt. Weighted-average borrowings under our credit facility based on daily balances wereof approximately $172$340.4 million during 20082010 compared to approximately $52$166 million during 2007.2009, and to a lesser extent to the $175.0 million of debt we issued in December 2010. The weighted-average effective interest rate on the credit facility decreased to 4.8%approximately 3.8% during 2008 from 7.2%2010 compared to approximately 4.0% during 2007.2009. Interest expense in 2010 also includes a make-whole premium payment of $2.8 million associated with the early payment of $75.0 million of the 7.33% fixed rate notes that were due in July 2011.

Income Tax Expense

Income tax expense increased by $34.2$20.2 million due to a comparable increasehigher effective tax rate offset by a decrease in our pre-tax income. The effective tax rates for 20082010 and 20072009 were 37.0%47.9% and 35.0%33.6%, respectively. The effective tax rate was higher primarily due to an increase in our state rates used in establishing deferred income taxes mainly due to a shift in our state apportionment factors to higher rate states, primarily in Pennsylvania, as a result of our increased focus on development of our Marcellus shale properties.

- 47 -


2009 and 2008 Compared

We reported net income for 2009 of $148.3 million, or $1.43 per share. During 2008, we reported net income of $211.3 million, or $2.10 per share. Net income decreased in 2009 by $63.0 million, primarily due to decreased operating revenues and increased operating expenses, partially offset by increased gain on sale of assets. Operating revenues decreased by $66.5 million largely due to decreases in brokered natural gas and natural gas revenues. Operating expenses decreased by $33.1 million between periods due primarily to decreases in brokered natural gas costs, taxes other than income and general and administrative expenses, partially offset by increased depreciation, depletion and amortization, exploration expense and direct operations. In addition, net income was impacted in 2009 by higher interest expense, decreased income tax expense and, to a lesser extent, loss on sale of assets. Income tax expense was lower in 2009 as a result of a decrease in operating income, as discussed above, and a decrease in the effective tax rate. The decrease in the effective tax rate is primarily due to an overall reduction in state deferred tax liabilities and tax benefits associated with foreign tax credits.

Revenue, Price and Volume Variances

Below is a one time benefit for state taxesdiscussion of revenue, price and volume variances.

   Year Ended December 31,   Variance 
         2009               2008         Amount  Percent 

Revenue Variances (In thousands)

       

Natural Gas(1)

  $731,688    $758,755    $(27,067  (4%) 

Brokered Natural Gas

   75,283     114,220     (38,937  (34%) 

Crude Oil and Condensate

   69,936     69,711     225    0

Other

   4,323     3,105     1,218    39

(1)

Natural Gas Revenues exclude the unrealized loss from the change in fair value of our basis swaps of $2.0 million in 2009. There was no impact from the unrealized change in natural gas derivative fair value for 2008.

   Year Ended December 31,   Variance  Increase
(Decrease)
(In thousands)
 
         2009           2008         Amount  Percent  

Price Variances

        

Natural Gas(1)

  $7.47    $8.39    $(0.92  (11%)  $(89,606

Crude Oil and Condensate (2)

  $85.52    $89.11    $(3.59  (4%)   (2,966
           

Total

        $(92,572
           

Volume Variances

        

Natural Gas (Mmcf)

   97,914     90,425     7,489    8 $62,539  

Crude Oil and Condensate (Mbbl)

   818     782     36    5  3,191  
           

Total

        $65,730  
           

(1)

These prices include the realized impact of derivative instrument settlements, which increased the price by $3.80 per Mcf in 2009 and by $0.20 per Mcf in 2008.

(2)

These prices include the realized impact of derivative instrument settlements, which increased the price by $28.25 per Bbl in 2009 and decreased the price by $6.33 per Bbl in 2008.

Natural Gas Revenues

The decrease in 2007Natural Gas Revenue of approximately $2.8$27.1 million, attributable to favorable treatmentexcluding the impact of the gain fromunrealized gains and losses discussed above, is almost entirely due to the sale of south Louisianaour Canadian properties in 2006 and a reduction in special deductions in 2008.

2007 and 2006 Compared

We reported net income for the year ended December 31, 2007 of $167.4 million, or $1.73 per share. During 2006, we reported net income of $321.2 million, or $3.32 per share. This decrease of $153.8 million in net income was primarily due to a decrease in operating incomerealized natural gas prices that was essentially offset by an increase in natural gas production. This increase in natural gas

- 48 -


production was primarily a result of $254.2 million resulting fromincreased production in the gain onNorth region associated with the initiation of production in Susquehanna County, Pennsylvania in the third quarter of 2008 and increased drilling in the Marcellus shale prospect in Susquehanna County as well as increased natural gas production in the South region associated with the properties we acquired in east Texas in August 2008 and drilling in the Angie field. Partially offsetting these production gains were decreases in production in Canada due to the sale of assetssubstantially all of $231.2 million includedour Canadian properties in 2006 related to the 2006 south LouisianaApril 2009.

Crude Oil and offshore properties sale,Condensate Revenues

The increase in crude oil production, partially offset by a $99.2 million decrease in income tax expense andrealized crude oil prices, resulted in a $1.2 million decrease in interest and other expenses in 2007.

The decrease in operating income was primarily the result of a decrease in 2007 of $218.6 million in gain on sale of assets primarily from the 2006 south Louisiana and offshore properties sale. Additionally, there was a $29.8 million decrease in 2007 in operating revenues and annet revenue increase of $5.8 million in operating expenses. The decrease in operating revenues was largely the result of lower oil production in the Gulf Coast region primarily as a result of the 2006 south Louisiana and offshore properties sale.$0.2 million. The increase in operating expensescrude oil production was primarily the result of increased DD&Aproduction in the South region associated with the properties we acquired in the east Texas acquisition in August 2008 and impairment expenses,an increase related to Pettet formation production in the Angie field, partially offset by a decrease in part by reduced exploration and general and administrative expenses.

Index to Financial Statements

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $7.23 per Mcf for 2007 compared to $7.13 per Mcf for 2006. These prices include the realized impact of derivative instrument settlements, which increased the price by $0.99 per Mcf in 2007 and $0.35 per Mcf in 2006. There was no revenue impact from the unrealized change in natural gas derivative fair value for the years ended December 31, 2007 or 2006.

   Year Ended
December 31,
  Variance 
   2007  2006  Amount  Percent 

Natural Gas Production(Mmcf)

      

East

   24,344   23,542   802  3%

Gulf Coast

   26,797   29,973   (3,176) (11%)

West

   25,409   23,633   1,776  8%

Canada

   3,925   2,574   1,351  52%
              

Total Company

   80,475   79,722   753  1%
              

Natural Gas Production Sales Price($/Mcf)

      

East

  $7.78  $7.99  $(0.21) (3%)

Gulf Coast

  $8.03  $7.37  $0.66  9%

West

  $6.13  $6.05  $0.08  1%

Canada

  $5.47  $6.18  $(0.71) (11%)

Total Company

  $7.23  $7.13  $0.10  1%

Natural Gas Production Revenue(In thousands)

      

East

  $189,392  $188,111  $1,281  1%

Gulf Coast

   215,106   221,020   (5,914) (3%)

West

   155,676   143,058   12,618  9%

Canada

   21,466   15,908   5,558  35%
              

Total Company

  $581,640  $568,097  $13,543  2%
              

Price Variance Impact on Natural Gas Production Revenue

      

(In thousands)

      

East

  $(5,127)    

Gulf Coast

   17,774     

West

   2,121     

Canada

   (2,792)    
         

Total Company

  $11,976     
         

Volume Variance Impact on Natural Gas Production Revenue

      

(In thousands)

      

East

  $6,408     

Gulf Coast

   (23,688)    

West

   10,497     

Canada

   8,350     
         

Total Company

  $1,567     
         

The increase of $13.5 million in Natural Gas Production Revenue isCanada due to an increase in realized natural gas sales prices as well as increased natural gas production. Natural gas revenues increased inthe sale of substantially all regions except for the Gulf Coast region in 2007 over 2006. After removing from the 2006 results $70.5 million of natural gas revenues and 9,037 Mmcf of natural gas production associated withour Canadian properties in the Gulf Coast region sold in the 2006 south Louisiana and offshore properties sale, total natural gas revenue would have increased by $84.0 million, or 17%, and natural gas production would have increased by 9,791 Mmcf, or 14%, from 2006 to 2007.April 2009.

Index to Financial Statements

Brokered Natural Gas Revenue and Cost

 

   Year Ended
December 31,
  Variance 
   2007  2006  Amount  Percent 

Sales Price($/Mcf)

  $8.40  $8.14  $0.26  3%

Volume Brokered(Mmcf)

  x11,101  x11,502   (401) (3%)
           

Brokered Natural Gas Revenues(In thousands)

  $93,215  $93,651   
           

Purchase Price($/Mcf)

  $7.37  $7.25  $0.12  2%

Volume Brokered(Mmcf)

  x11,101  x11,502   (401) (3%)
           

Brokered Natural Gas Cost(In thousands)

  $81,819  $83,375   
           

Brokered Natural Gas Margin(In thousands)

  $11,396  $10,276  $1,120  11%
              

(In thousands)

      

Sales Price Variance Impact on Revenue

  $2,828     

Volume Variance Impact on Revenue

   (3,264)    
         
  $(436)    
         

(In thousands)

      

Purchase Price Variance Impact on Purchases

  $(1,351)    

Volume Variance Impact on Purchases

   2,907     
         
  $1,556     
         
   Year Ended December 31,   Variance  Price and
Volume
Variances
(In thousands)
 
         2009               2008         Amount  Percent  

Brokered Natural Gas Sales

        

Sales Price ($/Mcf)

  $5.95    $10.39    $(4.44  (43%)  $(56,185

Volume Brokered (Mmcf)

  x12,656    x10,996     1,660    15  17,248  
                 

Brokered Natural Gas Revenues (In thousands)

  $75,283    $114,220      $(38,937
                 

Brokered Natural Gas Purchases

        

Purchase Price ($/Mcf)

  $5.30    $9.14    $(3.84  (42%)  $48,592  

Volume Brokered (Mmcf)

  x12,656    x10,996     1,660    15  (15,173
                 

Brokered Natural Gas Cost (In thousands)

  $67,030    $100,449      $33,419  
                 

Brokered Natural Gas Margin (In thousands)

  $8,253    $13,771      $(5,518
                 

The increaseddecreased brokered natural gas margin of approximately $1.1$5.5 million is driven by an increasea result of a decrease in sales price that outpaced the increasedecrease in purchase price, partially offset by a decrease in the volumes brokered in 2007 over 2006.

Index to Financial Statements

Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price was $67.16 per Bbl for 2007. The 2007 price includes the realized impact of derivative instrument settlements which decreased the price by $0.97 per Bbl. Our average total company realized crude oil sales price was $65.03 per Bbl for 2006. There was no realized impact of crude oil derivative instruments in 2006. There was no unrealized impact of crude oil derivative instruments in 2007 or 2006.

   Year Ended
December 31,
  Variance 
   2007  2006  Amount  Percent 

Crude Oil Production(Mbbl)

      

East

   26   24   2  8%

Gulf Coast

   605   1,160   (555) (48%)

West

   174   209   (35) (17%)

Canada

   18   12   6  50%
              

Total Company

   823   1,405   (582) (41%)
              

Crude Oil Sales Price($/Bbl)

      

East

  $66.97  $62.03  $4.94  8%

Gulf Coast

  $67.17  $65.44  $1.73  3%

West

  $67.86  $63.36  $4.50  7%

Canada

  $59.96  $60.55  $(0.59) (1%)

Total Company

  $67.16  $65.03  $2.13  3%

Crude Oil Revenue(In thousands)

      

East

  $1,734  $1,474  $260  18%

Gulf Coast

   40,673   75,894   (35,221) (46%)

West

   11,784   13,253   (1,469) (11%)

Canada

   1,052   759   293  39%
              

Total Company

  $55,243  $91,380  $(36,137) (40%)
              

Price Variance Impact on Crude Oil Revenue

      

(In thousands)

      

East

  $128     

Gulf Coast

   1,048     

West

   781     

Canada

   (10)    
         

Total Company

  $1,947     
         

Volume Variance Impact on Crude Oil Revenue

      

(In thousands)

      

East

  $132     

Gulf Coast

   (36,269)    

West

   (2,250)    

Canada

   303     
         

Total Company

  $(38,084)    
         

The decrease in the realized crude oil production, partially offset by thean increase in realized prices, resulted in a net revenue decrease of approximately $36.1 million. The decrease in oil production is mainly the result of the 2006 south Louisiana and offshore properties sale in the Gulf Coast region. After removing from the 2006 results $47.4 million of crude oil revenues and 707 Mbbls of crude oil production associated with properties in the Gulf Coast region sold in the 2006 south Louisiana and offshore properties sale, total crude oil revenue would have increased by $11.2 million, or 26%, and crude oil production would have increased by 124 Mbbls, or 18%, from 2006 to 2007.volumes brokered.

Index to Financial Statements

Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

 

  Year Ended December 31,  Year Ended December 31, 
  2007  2006  2009 2008 
  Realized Unrealized  Realized  Unrealized
  (In thousands)

(In thousands)

  Realized   Unrealized Realized Unrealized 

Operating Revenues—Increase / (Decrease) to Revenue

             

Cash Flow Hedges

             

Natural Gas Production

  $79,838  $—    $28,266  $—    $371,915    $—     $17,972   $—    

Crude Oil

   (796)  —     —     —     23,112     —      (4,951  —    
                          

Total Cash Flow Hedges

  $79,042  $—    $28,266  $—     395,027     —      13,021    —    
                          

Other Derivative Financial Instruments

      

Natural Gas Basis Swaps

   —       (1,954  —      —    
              

Total Other Derivative Financial Instruments

   —       (1,954  —      —    
              

Total Cash Flow Hedges and Other Derivative Financial Instruments

  $395,027    $(1,954 $13,021   $—    
              

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity.

- 49 -


Operating and Other Expenses

   Year Ended December 31,  Variance 

(In thousands)

        2009               2008        Amount  Percent 

Operating and Other Expenses

      

Brokered Natural Gas Cost

  $67,030    $100,449   $(33,419  (33%) 

Direct Operations—Field and Pipeline

   93,985     91,839    2,146    2

Taxes Other Than Income

   44,649     66,540    (21,891  (33%) 

Exploration

   50,784     31,200    19,584    63

Depreciation, Depletion and Amortization

   251,260     226,915    24,345    11

Impairment of Oil and Gas Properties and Other Assets

   17,622     35,700    (18,078  (51%) 

General and Administrative

   68,374     74,185    (5,811  (8%) 
                  

Total Operating Expense

  $593,704    $626,828   $(33,124  (5%) 

(Gain) / Loss on Sale of Assets

  $3,303    $(1,143 $4,446    389

Interest Expense and Other

   58,979     36,389    22,590    62

Income Tax Expense

   74,947     124,333    (49,386  (40%) 

Total costs and expenses from operations increaseddecreased by $5.8$33.1 million for the year ended December 31, 2007 compared to the year ended December 31, 2006.in 2009 from 2008. The primary reasons for this fluctuation are as follows:

 

Brokered Natural Gas Cost decreased by $33.4 million from 2008 to 2009. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

Depreciation, Depletion and Amortization increased by $14.9$24.3 million in 2007 over 2006.from 2008 to 2009. This is primarily due to the impact on the DD&A rate of negative reserve revisions due to lower prices at the end of 2006, higher capital costs and commencement ofhigher natural gas and oil production in anvolumes, including the east Texas field.

Exploration expenseacquisition in August 2008. Amortization of unproved properties decreased by $9.6$11.5 million from 20062008 to 2007, primarily as a result of a decrease in total dry hole expense of $10.3 million, primarily in Canada and, to a lesser extent, in the West and Gulf Coast regions. In addition, there was a decrease in geophysical and geological expenses of $1.8 million,2009, primarily due to a decreasethe $17.0 million impairment of Mississippi, Montana and North Dakota leases in the Gulf Coast region,2008 offset in part by an increase in Canada. Offsetting part of these decreases was an increase of $2.6 million in land and lease search expenses during 2007.

Impairment of Unproved Properties increased by $7.9 million in 2007 compared to 2006, primarily due to increased lease acquisition costs during 2005 and 2006incurred in several exploratory areas.

General and Administrative expense decreased by $7.4 million in 2007 primarily due to decreased stock compensation charges of $5.9 million due to a reduction in performance share expense from a changedevelopmental areas in the liability component of the awards resulting from the varianceNorth and in our relative ranking from 2006 to 2007east Texas as well as a reductionthe amortization of undeveloped costs associated with the east Texas acquisition in restricted stock awards as a result of awards that vested in 2007. In addition, there was a decrease of $4.2 million related to decreased professional services fees for litigation. Partially offsetting these decreases were increases in employee compensation related expenses and bad debt expense.

Direct Operations expense increased by $2.4 million as a result of higher employee compensation charges and disposal, treating, compressor, workover and maintenance costs, partially offset by lower outside operated properties expense and insurance expense.

Brokered Natural Gas Cost decreased by $1.6 million from 2006 to 2007. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.August 2008.

 

Taxes Other Than Income decreased by $1.5$21.9 million for 2007 comparedfrom 2008 to 2006, primarily2009 due to decreasedlower production taxes of $3.3 million as a result of decreased commodity volumeslower average natural gas and prices as well as decreased franchise taxes, partially offsetcrude oil prices.

Exploration expense increased by an increase in ad valorem taxes.$19.6 million from 2008 to 2009 primarily due to higher charges for idle contract rigs and higher dry hole and geological and geophysical costs.

Index to Financial Statements

Impairment of Oil & Gas Properties and Other Assets decreased by $18.1 million from 2008 to 2009. Impairments in 2009 consisted of approximately $12.0 million in the Fossil Federal field in San Miguel County, Colorado resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas resulting from lower well performance.

General and Administrative expenses decreased by $5.8 million from 2008 to 2009. This is primarily due to decreased stock compensation expense largely related to a reduction in supplemental employee compensation expense of $14.7 million, partially offset by an increase in performance share award expense of $5.5 million and an increase in pension expense related to our qualified pension plan.

Direct Operations expenses increased by $0.7$2.1 million for the year ended December 31, 2007 comparedfrom 2008 to the year ended December 31, 2006,2009 primarily due to an impairment recorded in 2007 inhigher personnel and labor expenses, increased severance and employee relocation costs associated with the Gulf Coast region resulting from two non-commercial development completions in a small field in north Louisiana.reorganization of operations and higher compressor and outside operated properties charges.

Interest Expense, Net

Interest expense, net decreasedincreased by $1.1$22.6 million in 2007 comparedfrom 2008 to 20062009 primarily due to a lower weighted-averageincreased interest rate on borrowings under our revolving credit facility, a lower outstandingexpense related to the $492 million principal amount of debt we issued in our 7.19% fixed rate debtJuly and lower weighted-average borrowings under our credit facility, as well as increased income related to FIN 48 as discussed below. These decreases to interest expense were offset in part by decreased regulatory capitalized interest on our pipeline in the East region.December 2008 private

- 50 -


placements. Weighted-average borrowings under our credit facility based on daily balances were approximately $52$166 million during 20072009 compared to approximately $61$172 million during 2006.2008. The weighted-average effective interest rate on the credit facility decreased to 7.2%approximately 4.0% during 2007 from 7.9%2009 compared to approximately 4.8% during 2006. In addition, interest expense decreased due to the reversal of interest payable on a previous uncertain tax position. During 2007, we recorded net interest income related to FIN 48 of $1.3 million, with no amount recorded in 2006.2008.

Income Tax Expense

Income tax expense decreased by $99.2$49.4 million due to a comparable decrease in our pre-tax income, primarily as a result of the decrease in the gain on sale of assets.income. The effective tax rates for 20072009 and 20062008 were 35.0%33.6% and 37.1%37.0%, respectively. The decrease in the effective tax rate is primarily due to aan overall reduction in our overall state incomedeferred tax rate for 2007.liabilities and tax benefits associated with foreign tax credits.

 

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Our primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The debtcapital markets continue to be volatile with periods of easy access and equity markets have recently experiencedtimes with unfavorable conditions, which may affect our ability to access those markets.conditions. As a result of the volatility and disruption in the capital markets and our increased level of borrowings, we may at times experience increased costs associated with future borrowings and debt issuances.issuances based on recent financings. At this time, we do not believe our liquidity has been materially affected by the recent market events. We will continue to monitor events and circumstances surrounding each of our lenders in our revolving credit facility.

Derivative Instruments and Hedging Activity

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 1113 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk

Index to Financial Statements

management policies and not subjecting us to material speculative risks. AtAs of December 31, 2008,2010, we had 26 cash flow hedges11 derivative contracts open: 14 natural gas price collar arrangements, 10four natural gas price swap arrangements, six natural gas basis swaps arrangements and twoone crude oil price swap arrangements. At December 31, 2008, a $355.2 million ($223.1 million, net of tax) unrealized gain was recorded in Accumulated Other Comprehensive Income / (Loss), along with a $264.7 million short-term derivative receivable and a $90.5 million long-term derivative receivable.

The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income / (Loss). The ineffective portion of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives, are recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate. For the years ended December 31 2008, 2007 and 2006, there was no ineffectiveness recorded in the Consolidated Statement of Operations.

collar arrangement. During the second quarter of 2008, in anticipation of the east Texas acquisition,2010, we entered into 12a total of six new derivative contracts including one crude oil swap contract for 2010, four natural gas swap contracts for natural gas price swaps2011 and three contracts forone crude oil swaps (2009 andcollar contract for 2011.

- 51 -


As of December 31, 2010, contracts includedwe had the following outstanding commodity derivatives:

Commodity and Derivative Type

 

Weighted-Average

Contract Price

 Volume  

Contract Period

 Net Unrealized
Gain / (Loss)
(In thousands)
 

Derivatives Designated as Hedging Instruments

    

Natural Gas Swaps

 $6.24 per Mcf  12,909 Mmcf   January - December 2011 $18,669  

Crude Oil Collars

 

$93.25 Ceiling /$80.00

Floor per Bbl

  365 Mbbl   January - December 2011  (1,743
       
    $16,926  

Derivatives Not Designated as Hedging Instruments

    

Natural Gas Basis Swaps

 $(0.27) per Mcf  16,123 Mmcf   January - December 2012  (2,180
       
    $14,746  
       

The amounts set forth under the net unrealized gain / (loss) column in the amounts discussed above) for the remainder of 2008 and extending through 2010 for the purpose of reducing commodity price risk associated with anticipated production after the transaction closing.

Based upon estimatestables above represent our total unrealized derivative position at December 31, 2008,2010 and include the impact of nonperformance risk. Nonperformance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we would expect to reclassify to the Consolidated Statement of Operations, over the next 12 months, $166.2 million in after-tax income associated with commodity hedges. This reclassification represents the net short-term receivable associated with open positions currently not reflected in earnings at December 31, 2008 related to anticipated 2009 production.

Hedges on Production—Swapshave derivative transactions.

From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

During 2008,2010, natural gas price swaps covered 9,821 Mmcf,35.9 Bcf, or 11%29%, of our 20082010 gas production at an average price of $10.27$9.30 per Mcf. We had two crude oil price swaps covering 730 Mbbl, or 90%, of our 2010 oil production at an average price of $104.25 per Bbl.

During 2008,2010, we also entered into crude oil swaps to hedge our price exposure on our 2010 production, natural gas swaps to hedge our price exposure on our 2011 production and crude oil price collars to hedge our price exposure on our 2011 production. In addition, we also have natural gas basis swaps covering a portion of our anticipated 2008, 2009 and 20102012 production, including production related to the east Texas acquisition.

At December 31, 2008, we had open natural gas price swap contracts covering a portion of our anticipated 2009 and 2010 production as follows:

   Natural Gas Price Swaps

Contract Period

  Volume
in
Mmcf
  Weighted-Average
Contract Price
(per Mcf)
  Net Unrealized
Gain
(In thousands)

Year Ended December 31, 2009

  16,079  $12.18  $90,267

Year Ended December 31, 2010

  19,295  $11.43  $70,345

We had one crude oil price swap covering 92 Mbbl, or 12%, of our 2008 production at a price of $127.15 per Bbl. During 2008, we entered into crude oil price swaps covering a portion of our anticipated 2008, 2009 and 2010 production.

Index to Financial Statements

At December 31, 2008, we had open crude oil price swap contracts covering a portion of our anticipated 2009 and 2010 production as follows:

   Crude Oil Price Swaps

Contract Period

  Volume
in
Mbbl
  Contract
Price
(per Bbl)
  Net Unrealized
Gain
(In thousands)

Year Ended December 31, 2009

  365  $125.25  $25,656

Year Ended December 31, 2010

  365  $125.00  $21,840

Hedges on Production—Options

From time to time, we enter into natural gas and crude oil collar agreements with counterparties towhich do not qualify for hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. During 2008, natural gas price collars covered 54,173 Mmcf, or 60%, of our 2008 gas production, with a weighted-average floor of $8.53 per Mcf and a weighted-average ceiling of $10.70 per Mcf.

At December 31, 2008, we had open natural gas price collar contracts covering a portion of our anticipated 2009 production as follows:

   Natural Gas Price Collars

Contract Period

  Volume
in
Mmcf
  Weighted-Average
Ceiling / Floor
(per Mcf)
  Net Unrealized
Gain
(In thousands)

Year Ended December 31, 2009

  47,253  $12.39/$9.40  $152,191

During 2008, an oil price collar covered 366 Mbbls, or 47%, of our 2008 crude oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.accounting.

We are exposed to market risk on these open contracts,derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedgedderivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commoditycommodity. Although notional contract amounts are used to express the volume of natural gas agreements, the amounts that is hedged.

The amounts set forth under the net unrealized gain columnscan be subject to credit risk in the tables above representevent of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our total unrealized gain position at December 31, 2008. Also impacting the total unrealized net gain (reflecting the net receivable position) in accumulated other comprehensive income / (loss) in the Consolidated Balance Sheet is a reductionfinancial results due to non-performance by third parties. Our primary derivative contract counterparties are Bank of $5.1 million related to our assessmentMontreal, JPMorgan, Bank of our counterparties’ nonperformance risk. This risk was evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions.America and BNP Paribas.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

Fair Market Value of Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. value due to the short-term maturities of these instruments.

- 52 -


The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate

Index to Financial Statements

and the year-period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new issuesissuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes excludingand the credit facility areis based on interest rates currently available to the us. The credit facility approximates fair value because this instrument bears interest at rates based on current market rates.

We use available marketing data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:

   December 31, 2010   December 31, 2009 

(In thousands)

  Carrying
Amount
   Estimated
Fair Value
   Carrying
Amount
   Estimated
Fair Value
 

Long-Term Debt

  $975,000    $1,100,830    $805,000    $863,559  

- 53 -


ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page

Report of Independent Registered Public Accounting Firm

55

Consolidated Statement of Operations for the Years Ended December 31, 2010, 2009 and 2008

56

Consolidated Balance Sheet at December 31, 2010 and 2009

57

Consolidated Statement of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008

58

Consolidated Statement of Stockholders’ Equity for the Years Ended December  31, 2010, 2009 and 2008

59

Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008

60

Notes to the Consolidated Financial Statements

61

Supplemental Oil and Gas Information (Unaudited)

105

Quarterly Financial Information (Unaudited)

110

- 54 -


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Cabot Oil & Gas Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders’ equity, comprehensive income and of cash flows present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/    PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2011

- 55 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

   Year Ended December 31, 

(In thousands, except per share amounts)

  2010   2009  2008 

OPERATING REVENUES

     

Natural Gas

  $694,577    $729,734   $758,755  

Brokered Natural Gas

   65,281     75,283    114,220  

Crude Oil and Condensate

   79,091     69,936    69,711  

Other

   5,086     4,323    3,105  
              
   844,035     879,276    945,791  

OPERATING EXPENSES

     

Brokered Natural Gas Cost

   56,466     67,030    100,449  

Direct Operations—Field and Pipeline

   99,642     93,985    91,839  

Taxes Other Than Income

   37,894     44,649    66,540  

Exploration

   42,725     50,784    31,200  

Depreciation, Depletion and Amortization

   327,083     251,260    226,915  

Impairment of Oil & Gas Properties and Other Assets

   40,903     17,622    35,700  

General and Administrative

   79,177     68,374    74,185  
              
   683,890     593,704    626,828  

Gain/(Loss) on Sale of Assets

   106,294     (3,303  1,143  

Gain on Settlement of Dispute

   —       —      51,906  
              

INCOME FROM OPERATIONS

   266,439     282,269    372,012  

Interest Expense and Other

   67,941     58,979    36,389  
              

Income Before Income Taxes

   198,498     223,290    335,623  

Income Tax Expense

   95,112     74,947    124,333  
              

NET INCOME

  $103,386    $148,343   $211,290  
              

Earnings Per Share

     

Basic

  $0.99    $1.43   $2.10  

Diluted

  $0.98    $1.42   $2.08  

Weighted-Average Common Shares Outstanding

     

Basic

   103,911     103,616    100,737  

Diluted

   105,195     104,683    101,726  

Dividends Per Common Share

  $0.12    $0.12   $0.12  

The accompanying notes are an integral part of these consolidated financial statements.

- 56 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET

   December 31,  December 31, 

(In thousands, except share amounts)

  2010  2009 

ASSETS

   

Current Assets

   

Cash and Cash Equivalents

  $55,949   $40,158  

Accounts Receivable, Net

   94,488    80,362  

Income Taxes Receivable

   —      8,909  

Inventories

   29,667    27,990  

Derivative Instruments

   16,926    114,686  

Other Current Assets

   5,978    9,397  
         

Total Current Assets

   203,008    281,502  

Properties and Equipment, Net (Successful Efforts Method)

   3,762,760    3,358,199  

Other Assets

   39,263    43,700  
         
  $4,005,031   $3,683,401  
         

LIABILITIES AND STOCKHOLDERS’ EQUITY

   

Current Liabilities

   

Accounts Payable

  $229,981   $215,588  

Income Taxes Payable

   25,957    —    

Accrued Liabilities

   47,897    58,049  

Deferred Income Taxes

   —      35,104  
         

Total Current Liabilities

   303,835    308,741  

Pension and Postretirement Benefits

   34,053    54,835  

Long-Term Debt

   975,000    805,000  

Deferred Income Taxes

   714,953    644,801  

Asset Retirement Obligation

   72,311    29,676  

Other Liabilities

   32,179    27,834  
         

Total Liabilities

   2,132,331    1,870,887  
         

Commitments and Contingencies (Note 8)

   

Stockholders’ Equity

 �� 

Common Stock:

   

Authorized—240,000,000 Shares of $0.10 Par Value in 2010 and 2009

   

Issued—104,210,084 Shares and 103,856,447 Shares in 2010 and 2009, respectively

   10,421    10,386  

Additional Paid-in Capital

   720,920    705,569  

Retained Earnings

   1,148,391    1,057,472  

Accumulated Other Comprehensive Income / (Loss)

   (3,683  42,436  

Less Treasury Stock, at Cost:
202,200 Shares in 2010 and 2009, respectively

   (3,349  (3,349
         

Total Stockholders’ Equity

   1,872,700    1,812,514  
         
  $4,005,031   $3,683,401  
         

The accompanying notes are an integral part of these consolidated financial statements.

- 57 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

   Year Ended December 31, 

(In thousands)

  2010  2009  2008 

CASH FLOWS FROM OPERATING ACTIVITIES

    

Net Income

  $103,386   $148,343   $211,290  

Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:

    

Depreciation, Depletion and Amortization

   327,083    251,260    226,915  

Impairment of Oil & Gas Properties and Other Assets

   40,903    17,622    35,700  

Deferred Income Tax Expense

   61,809    101,815    120,851  

(Gain) / Loss on Sale of Assets

   (106,294  3,303    (1,143

Gain on Settlement of Dispute

   —      —      (31,706

Exploration Expense

   11,657    50,784    31,200  

Unrealized Loss on Derivatives

   226    1,954    —    

Amortization of Debt Issuance Cost

   3,381    3,635    634  

Stock-Based Compensation Expense and Other

   15,413    25,924    14,989  

Changes in Assets and Liabilities:

    

Accounts Receivable, Net

   (14,125  28,725    (3,928

Inventories

   (1,677  17,687    (18,324

Other Current Assets

   3,675    3,103    10,816  

Other Assets and Other Liabilities

   6,204    531    6,422  

Accounts Payable and Accrued Liabilities

   (1,488  (27,202  3,321  

Income Taxes

   34,866    358    38,101  

Stock-Based Compensation Tax Benefit

   (108  (13,790  (10,691
             

Net Cash Provided by Operating Activities

   484,911    614,052    634,447  
             

CASH FLOWS FROM INVESTING ACTIVITIES

    

Capital Expenditures

   (857,251  (610,813  (848,640

Acquisitions

   —      (394  (605,748

Proceeds from Sale of Assets

   243,510    80,180    2,099  
             

Net Cash Used in Investing Activities

   (613,741  (531,027  (1,452,289
             

CASH FLOWS FROM FINANCING ACTIVITIES

    

Borrowings from Debt

   525,000    105,000    892,000  

Repayments of Debt

   (355,000  (167,000  (375,000

Net Proceeds from Sale of Common Stock

   801    83    316,230  

Stock-Based Compensation Tax Benefit

   108    13,790    10,691  

Dividends Paid

   (12,467  (12,432  (12,073

Capitalized Debt Issuance Costs

   (13,821  (10,409  (4,403
             

Net Cash Provided by / (Used in) Financing Activities

   144,621    (70,968  827,445  
             

Net Increase in Cash and Cash Equivalents

   15,791    12,057    9,603  

Cash and Cash Equivalents, Beginning of Period

   40,158    28,101    18,498  
             

Cash and Cash Equivalents, End of Period

  $55,949   $40,158   $28,101  
             

The accompanying notes are an integral part of these consolidated financial statements.

- 58 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands, except per share
amounts)

 Common
Shares
  Stock
Par
  Treaury
Shares
  Treasury
Stock
  Paid-In
Capital
  Accumulated
Other
Comprehensive
Income /
(Loss)
  Retained
Earnings
  Total 

Balance at December 31, 2007

  102,681   $10,268    5,205   $(85,690 $424,229   $(894 $722,344   $1,070,257  
                                

Net Income

  —      —      —      —      —      —      211,290    211,290  

Exercise of Stock Options

  328    33    —      —      2,692    —      —      2,725  

Retirement of Treasury Stock

  (5,003  (500  (5,003  82,341    (81,841  —      —      —    

Tax Benefit of Stock-Based Compensation

  —      —      —      —      10,691    —      —      10,691  

Stock Amortization and Vesting

  418    42    —      —      6,545    —      —      6,587  

Stock Held in Rabbi Trust

  64    6    —      —      (3,198  —      —      (3,192

Stock Issued for Drilling Company Acquisition

  70    7    —      —      3,493    —      —      3,500  

Issuance of Common Stock

  5,003    500    —      —      312,957    —      —      313,457  

Cash Dividends at $0.12 per Share

  —      —      —      —      —      —      (12,073  (12,073

Other Comprehensive Income / (Loss)

  —      —      —      —      —      187,320    —      187,320  
                                

Balance at December 31, 2008

  103,561   $10,356    202   $(3,349 $675,568   $186,426   $921,561   $1,790,562  
                                

Net Income

  —      —      —      —      —      —      148,343    148,343  

Exercise of Stock Options and

        

Stock Appreciation Rights

  14    2    —      —      53    —      —      55  

Tax Benefit of Stock-Based Compensation

  —      —      —      —      13,790    —      —      13,790  

Stock Amortization and Vesting

  281    28    —      —      14,898    —      —      14,926  

Sale of Stock Held in Rabbi Trust

  —      —      —      —      1,260    —      —      1,260  

Cash Dividends at $0.12 per Share

  —      —      —      —      —      —      (12,432  (12,432

Other Comprehensive Income / (Loss)

  —      —      —      —      —      (143,990  —      (143,990
                                

Balance at December 31, 2009

  103,856   $10,386    202   $(3,349 $705,569   $42,436   $1,057,472   $1,812,514  
                                

Net Income

  —      —      —      —      —      —      103,386    103,386  

Exercise of Stock Options and

        

Stock Appreciation Rights

  39    4    —      —      766    —      —      770  

Tax Benefit of Stock-Based Compensation

  —      —      —      —      108    —      —      108  

Stock Amortization and Vesting

  315    31    —      —      12,899    —      —      12,930  

Sale of Stock Held in Rabbi Trust

  —      —      —      —      1,578    —      —      1,578  

Cash Dividends at $0.12 per Share

  —      —      —      —      —      —      (12,467  (12,467

Other Comprehensive Income / (Loss)

  —      —      —      —      —      (46,119  —      (46,119
                                

Balance at December 31, 2010

  104,210   $10,421    202   $(3,349 $720,920   $(3,683 $1,148,391   $1,872,700  
                                

The accompanying notes are an integral part of these consolidated financial statements.

- 59 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

  Year Ended December 31, 

(In thousands)

 2010  2009  2008 

Net Income

  $103,386    $148,343    $211,290  
               

Other Comprehensive Income / (Loss), net of taxes:

      

Reclassification Adjustment for Settled Contracts, net of taxes of $65,734, $147,048 and $4,844, respectively

   (107,256   (247,979   (8,177

Changes in Fair Value of Hedge Positions, net of taxes of $(29,777), $(57,303) and $(134,259), respectively

   45,878     96,783     226,692  

Defined Benefit Pension and Postretirement Plans:

      

Net Gain / (Loss) Arising During the Year, net of taxes of $(3,245), $1,773 and $10,445, respectively

 $5,693    $(3,009  $(17,629 

Effect of Plan Termination and Amendment, net of taxes of $(310), $0 and $0, respectively

  506     —       —     

Settlement, net of taxes of $(1,528), $0 and $0, respectively

  2,493     —       —     

Amortization of Net Obligation at Transition, net of taxes of $(240), $(236) and $(234), respectively

  392     396     398   

Amortization of Prior Service Cost, net of taxes of $(217), $(267) and $(373), respectively

  355     450     630   

Amortization of Net Loss, net of taxes of $(3,548), $(1,432) and $(603), respectively

  5,788    15,227    2,422    259    1,020    (15,581
               

Foreign Currency Translation Adjustment, net of taxes of $(20), $(4,116) and $9,292, respectively

   32     6,947     (15,614
               

Total Other Comprehensive Income / (Loss)

   (46,119   (143,990   187,320  
               

Comprehensive Income

  $57,267    $4,353    $398,610  
               

The accompanying notes are an integral part of these consolidated financial statements.

- 60 -


CABOT OIL & GAS CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Nature of Operations

Cabot Oil & Gas Corporation and its subsidiaries are engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil development, exploitation and exploration, exclusively within the continental United States. The Company’s exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

Certain reclassifications have been made to prior year statement to conform with current year presentation. These reclassifications have no impact on net income.

In 2009, the Company reorganized its operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with its Texas and Louisiana areas to form the South region. Additionally, the Company exited Canada through the sale of its properties in April 2009. Prior to the third quarter of 2009, the Company presented the geographic areas as East, Gulf Coast, West and Canada.

The consolidated financial statements contain the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions.

Recently Adopted Accounting Standards

In February 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends Accounting Standards Codification (ASC) 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, the Company will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 14.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents were primarily concentrated in one financial institution at December 31, 2010 and 2009. The Company periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal.

Inventories

Inventories are comprised of natural gas in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of average cost or market.

- 61 -


Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net pipeline imbalance is included in inventory in the Consolidated Balance Sheet.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against Accounts Receivable in the Consolidated Balance Sheet, was $4.1 million and $3.6 million at December 31, 2010 and 2009, respectively.

Accounts Payable

This account may include credit balances from outstanding checks in zero balance cash accounts. These credit balances are referred to as book overdrafts and are included as a component of Accounts Payable on the Consolidated Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in Accounts Payable at December 31, 2010 and 2009 as sufficient cash was available for offset.

Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to exploration expense.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Generally pipeline and transmission systems are depreciated over 12 to 25 years, gathering and compression equipment is depreciated over 10 years and storage equipment and facilities are depreciated over 10 to 16 years. Certain other assets are depreciated on a straight-line basis over 3 to 10 years. Buildings are depreciated on a straight-line basis over 25 to 40 years.

Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not

- 62 -


significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

The Company evaluates the impairment of its oil and gas properties and other assets whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil. During 2010, 2009 and 2008, the Company recorded total impairments of $40.9 million, $17.6 million and $31.3 million (excluding the impairment of $4.4 million of goodwill), respectively.

Costs attributable to the Company’s unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past drilling and development experience and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities are also recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2010, there were no assets legally restricted for purposes of settling asset retirement obligations.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included within Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Operations.

Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or zero-cost price collars, as a hedging strategy to manage commodity price risk associated with its production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge are recognized currently in the results of operations.

When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to

- 63 -


occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge.

Effective January 1, 2009, the Company adopted the amended disclosure requirements prescribed in ASC 815, “Derivatives and Hedging.”

Revenue Recognition

Gas Imbalance

The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in Accounts Payable in the Consolidated Balance Sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties.

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses in accordance with ASC 605-45, “Revenue Recognition: Principle Agent Considerations”. The Company realizes brokered margin as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company and/or the counterparty takes title to the natural gas purchased or sold. The Company realized $8.8 million, $8.3 million and $13.8 million of brokered natural gas margin in 2010, 2009 and 2008, respectively.

Natural Gas Measurement

The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

- 64 -


The Company recognizes accrued interest related to uncertain tax positions in Interest Expense and Other expense and accrued penalties related to such positions in General and Administrative expense in the Consolidated Statement of Operations.

Stock-Based Compensation

The Company accounts for stock-based compensation under a fair value based method of accounting prescribed under ASC 718. Under the fair value method, compensation cost is measured at the grant date and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. Stock-based compensation cost for all types of awards is included in General and Administrative Expense in the Consolidated Statement of Operations.

The tax benefit for stock-based compensation is included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. In accordance with ASC 718, the Company recognizes a tax benefit only to the extent it reduces the Company’s income taxes payable. For the years ended December 31, 2010, 2009 and 2008, the Company realized tax benefits of $0.1 million, $13.8 million and $10.7 million, respectively.

Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

Market Risk

The Company’s primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The capital markets continue to be volatile with periods of easy access and times with unfavorable conditions. As a result of the volatility in the capital markets and the Company’s increased level of borrowings, it may a times experience increased costs associated with future borrowings and debt issuances based on recent financings. At this time, the Company does not believe its liquidity has been materially affected by market events.

Credit Risk

Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

In 2010, one customer accounted for approximately 11% of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of the Company’s total sales.

Use of Estimates

In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and

- 65 -


liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, asset retirement obligations, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:

   December 31, 

(In thousands)

  2010  2009 

Proved Oil and Gas Properties

  $4,794,650   $4,118,005  

Unproved Oil and Gas Properties

   490,181    423,373  

Gathering and Pipeline Systems

   237,043    294,755  

Land, Building and Other Equipment

   86,248    77,474  
         
   5,608,122    4,913,607  

Accumulated Depreciation, Depletion and Amortization

   (1,845,362  (1,555,408
         
  $3,762,760   $3,358,199  
         

The following table reflects the net changes in capitalized exploratory well costs during 2010, 2009 and 2008.

   December 31, 

(In thousands)

  2010  2009  2008 

Beginning balance at January 1

  $4,179   $5,990   $2,161  

Additions to capitalized exploratory well costs pending the determination of proved reserves

   4,285    4,179    5,990  

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves

   (4,148  (762  (1,259

Capitalized exploratory well costs charged to expense

   (31  (5,228  (902
             

Ending balance at December 31

  $4,285   $4,179   $5,990  
             

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

   December 31, 

(In thousands)

  2010   2009   2008 

Capitalized exploratory well costs that have been capitalized for a period of one year or less

  $4,285    $4,179    $5,990  

Capitalized exploratory well costs that have been capitalized for a period greater than one year

   —       —       —    
               

Balance at December 31

  $4,285    $4,179    $5,990  
               

- 66 -


At December 31, 2010, 2009 and 2008, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

In November 2010, the Company recorded an impairment of $5.1 million related to drilling and service equipment that was primarily used in drilling our West Virginia properties. The impairment was a result of decreased activity in West Virginia and the decision to sell the underlying assets. These assets were reduced to fair value of approximately $4.0 million. Fair value was determined using the market approach which considered broker quotes from market participants in the oil field services sector. The estimate was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined in ASC 820.

In September 2010, the Company recorded a $35.8 million impairment of oil and gas properties due to continued price declines and limited activity in two south Texas fields. These fields were reduced to a fair value of approximately $15.4 million using discounted future cash flows.

During 2009, the Company recorded $17.6 million of impairments of oil and gas properties. The Company recorded an impairment of $12.0 million in the Fossil Federal field in San Miguel County, Colorado in the North region resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas in the South region resulting from lower well performance. These fields were reduced to fair value of approximately $8.9 million using discounted future cash flows.

The fair value of the impaired fields was based on significant inputs that were not observable in the market and are considered to be level 3 inputs as defined in ASC 820. Refer to Note 14 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and production costs and (4) risk adjusted discount rates (14% at September 30, 2010 and 16% at December 31, 2009, respectively).

During 2008, the Company recorded an impairment of approximately $3.0 million in the Corral Creek field in Washakie County, Wyoming in the North region resulting from lower than expected performance from the two well field and $28.3 million in the Trawick field in Rusk County, Texas in the South region resulting from a decline in natural gas prices and higher well costs.

During 2010, 2009 and 2008, amortization of the Company’s unproved properties were $47.6 million, $30.0 million and $41.5 million, respectively and are included in Depreciation, Depletion, and Amortization in the Consolidated Statement of Operations. Included in 2008 amortization was $17.0 million related to three exploratory oil and gas prospects located in Mississippi, Montana and North Dakota that were abandoned. These prospects were abandoned as a result of the significant decline in commodity prices in the fourth quarter of 2008 and the Company’s change in exploration plans for these prospects.

In April 2008, the Company acquired a small oilfield services business for total consideration of $21.6 million, comprised of the conversion of a $15.6 million note receivable, the issuance of 70,168 shares of Company common stock, and the payment of $2.5 million in cash. The transaction was accounted for as a business combination, and the Company recorded approximately $4.4 million of goodwill. In December 2008, the Company fully impaired the goodwill due to the impact of the broad economic downturn and the related reductions in future drilling programs.

- 67 -


East Texas Property Acquisition

On August 15, 2008, the Company completed the acquisition of certain producing oil and gas properties located in Panola and Rusk counties, Texas in order to expand its position in the Minden field. Total net cash consideration paid by the Company in the transaction was approximately $604.0 million. The east Texas acquisition was recorded using the purchase method of accounting. Financial results for the period from the closing date on August 15, 2008 to December 31, 2009 are included within the Company’s Consolidated Statements of Operations. The following table presents the unaudited pro forma results of operations for the year ended December 31, 2008, as if the acquisition was made at the beginning of the period. These pro forma results are not necessarily indicative of future results, nor do they purport to represent the actual financial results that would have occurred had the acquisition been in effect for the periods presented.

(In thousands, except per share amounts)

  Year Ended
December 31,  2008
 
   (Unaudited) 

Revenues

  $1,009,412  

Net Income

  $218,290  

Earnings Per Share:

  

Basic

  $2.12  

Diluted

  $2.10  

Weighted-Average Common Shares Outstanding:

  

Basic

   103,142  

Diluted

   104,131  

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 and recognized a $49.3 million gain on sale of assets. 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. 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 in Susquehanna County, and build two compressor stations 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.

In November 2010, the Company sold certain oil and gas properties in the Texas panhandle to Kimbrel Oil Corporation and Millbrae Energy VII, LLC for $11.5 million and recognized a $10.8 million gain on sale of assets.

In July 2010, the Company sold certain oil and gas properties located in Colorado to Patera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, the Company recognized an impairment loss of approximately $5.8 million associated with the sale of these properties. The impairment charge is included in Gain / (Loss) on Sale of Assets in the Consolidated Statement of Operations. Fair value of the impaired properties was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of assets held for sale were considered Level 2 in the fair value hierarchy.

In June 2010, the Company sold its Woodford shale prospect located in Oklahoma to Continental Resources, Inc. The Company received approximately $15.9 million in cash proceeds and recognized a $10.3 million gain on sale of assets.

- 68 -


The Company recognized a $3.3 million aggregate loss on sale of assets for the year ended December 31, 2009. This loss included a loss of approximately $16.0 million primarily related to the sale of the Canadian properties described below and a gain of $12.7 million primarily related to the sale of Thornwood properties in the North region. Cash proceeds of $11.4 million were received from the sale of the Thornwood properties.

In April 2009, the Company sold substantially all of its Canadian properties to a Tourmaline Oil Corporation (Tourmaline). Total consideration received from the sale was $84.4 million, consisting of $63.8 million in cash and $20.6 million in common stock of Tourmaline (see Note 4). The total net book value of the Canadian properties sold was $95.0 million. At December 31, 2008, the Company recorded 40.4 Bcfe of proved reserves (two percent of total proved reserves) related to these properties.

- 69 -


3. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:

   December 31, 

(In thousands)

  2010  2009 

ACCOUNTS RECEIVABLE, NET

   

Trade Accounts

  $91,077   $78,656  

Joint Interest Accounts

   4,901    3,564  

Other Accounts

   2,603    1,756  
         
   98,581    83,976  

Allowance for Doubtful Accounts

   (4,093  (3,614
         
  $94,488   $80,362  
         

INVENTORIES

   

Natural Gas in Storage

  $13,371   $14,434  

Tubular Goods and Well Equipment

   17,072    14,420  

Pipeline Imbalances

   (776  (864
         
  $29,667   $27,990  
         

OTHER CURRENT ASSETS

   

Drilling Advances

  $2,796   $3,417  

Prepaid Balances

   2,925    5,980  

Deferred Income Taxes

   257    —    
         
  $5,978   $9,397  
         

OTHER ASSETS

   

Rabbi Trust Deferred Compensation Plan

  $15,788   $10,031  

Debt Issuance Cost

   22,061    11,621  

Other Accounts

   1,414    1,412  

Investment in Equity Securities

   —      20,636  
         
  $39,263   $43,700  
         

ACCOUNTS PAYABLE

   

Trade Accounts

  $27,401   $17,434  

Natural Gas Purchases

   3,596    3,558  

Royalty and Other Owners

   36,034    40,080  

Accrued Capital Costs

   146,824    141,122  

Taxes Other Than Income

   2,655    4,267  

Drilling Advances

   523    864  

Wellhead Gas Imbalances

   5,142    4,140  

Other Accounts

   7,806    4,123  
         
  $229,981   $215,588  
         

ACCRUED LIABILITIES

   

Employee Benefits

  $10,790   $11,222  

Pension and Postretirement Benefits

   1,688    1,469  

Taxes Other Than Income

   14,576    22,780  

Interest Payable

   19,488    20,205  

Derivative Contracts

   —      425  

Other Accounts

   1,355    1,948  
         
  $47,897   $58,049  
         

OTHER LIABILITIES

   

Rabbi Trust Deferred Compensation Plan

  $21,600   $19,087  

Derivative Contracts

   2,180    1,954  

Other Accounts

   8,399    6,793  
         
  $32,179   $27,834  
         

- 70 -


4. Investment in Equity Securities Carried at Cost

In April 2009, the Company received three million shares of common stock in Tourmaline as partial proceeds for the sale of substantially all of the Company’s Canadian assets. The common stock was carried at cost of $20.6 million and was included in Other Assets in the Consolidated Balance Sheet. As of December 31, 2009, the Company estimated the fair value of its investment to be $42.8 million based on the common stock value received in a recent private placement of Tourmaline’s common stock. Accordingly, the inputs associated with the fair value of the investment were considered level 3 in the fair value hierarchy.

In November 2010, the Company sold its investment in common stock of Tourmaline for $61.3 million and recognized a gain of $40.7 million which is included in Gain/(Loss) on Sale of Assets in the Consolidated Statement of Operations.

5. Debt and Credit Agreements

The Company’s debt consisted of the following as of:

(In thousands)

  December 31,
2010
   December 31,
2009
 

Long-Term DebtBasis of Presentation and Nature of Operations

   December 31, 2008  December 31, 2007 
   Carrying
Amount
  Estimated
Fair Value
  Carrying
Amount
  Estimated
Fair Value
 
   (In thousands) 

Long-Term Debt

  $867,000  $807,508  $350,000  $364,500 

Current Maturities

   (35,857)  (35,796)  (20,000)  (20,466)
                 

Long-Term Debt, excluding Current Maturities

  $831,143  $771,712  $330,000  $344,034 
                 

Index to Financial Statements
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page

Report of Independent Registered Public Accounting Firm

57

Consolidated Statement of Operations for the Years Ended December 31, 2008, 2007 and 2006

58

Consolidated Balance Sheet at December 31, 2008 and 2007

59

Consolidated Statement of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

60

Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006

61

Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006

62

Notes to the Consolidated Financial Statements

63

Supplemental Oil and Gas Information (Unaudited)

105

Quarterly Financial Information (Unaudited)

109

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Cabot Oil & Gas Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”)are engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil development, exploitation and exploration, exclusively within the continental United States. The Company’s exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

Certain reclassifications have been made to prior year statement to conform with current year presentation. These reclassifications have no impact on net income.

In 2009, the Company reorganized its operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with its Texas and Louisiana areas to form the South region. Additionally, the Company exited Canada through the sale of its properties in April 2009. Prior to the third quarter of 2009, the Company presented the geographic areas as East, Gulf Coast, West and Canada.

The consolidated financial statements contain the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions.

Recently Adopted Accounting Standards

In February 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends Accounting Standards Codification (ASC) 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, the Company will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 14.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents were primarily concentrated in one financial institution at December 31, 2010 and 2009. The Company periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal.

Inventories

Inventories are comprised of natural gas in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of average cost or market.

- 61 -


Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net pipeline imbalance is included in inventory in the Consolidated Balance Sheet.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against Accounts Receivable in the Consolidated Balance Sheet, was $4.1 million and $3.6 million at December 31, 2010 and 2009, respectively.

Accounts Payable

This account may include credit balances from outstanding checks in zero balance cash accounts. These credit balances are referred to as book overdrafts and are included as a component of Accounts Payable on the Consolidated Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in Accounts Payable at December 31, 2010 and 2009 as sufficient cash was available for offset.

Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to exploration expense.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Generally pipeline and transmission systems are depreciated over 12 to 25 years, gathering and compression equipment is depreciated over 10 years and storage equipment and facilities are depreciated over 10 to 16 years. Certain other assets are depreciated on a straight-line basis over 3 to 10 years. Buildings are depreciated on a straight-line basis over 25 to 40 years.

Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not

- 62 -


significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

The Company evaluates the impairment of its oil and gas properties and other assets whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil. During 2010, 2009 and 2008, the Company recorded total impairments of $40.9 million, $17.6 million and 2007,$31.3 million (excluding the impairment of $4.4 million of goodwill), respectively.

Costs attributable to the Company’s unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past drilling and development experience and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities are also recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2010, there were no assets legally restricted for purposes of settling asset retirement obligations.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included within Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Operations.

Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or zero-cost price collars, as a hedging strategy to manage commodity price risk associated with its production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge are recognized currently in the results of operations.

When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to

- 63 -


occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge.

Effective January 1, 2009, the Company adopted the amended disclosure requirements prescribed in ASC 815, “Derivatives and Hedging.”

Revenue Recognition

Gas Imbalance

The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in Accounts Payable in the Consolidated Balance Sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties.

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses in accordance with ASC 605-45, “Revenue Recognition: Principle Agent Considerations”. The Company realizes brokered margin as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company and/or the counterparty takes title to the natural gas purchased or sold. The Company realized $8.8 million, $8.3 million and $13.8 million of brokered natural gas margin in 2010, 2009 and 2008, respectively.

Natural Gas Measurement

The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

- 64 -


The Company recognizes accrued interest related to uncertain tax positions in Interest Expense and Other expense and accrued penalties related to such positions in General and Administrative expense in the Consolidated Statement of Operations.

Stock-Based Compensation

The Company accounts for stock-based compensation under a fair value based method of accounting prescribed under ASC 718. Under the fair value method, compensation cost is measured at the grant date and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. Stock-based compensation cost for all types of awards is included in General and Administrative Expense in the Consolidated Statement of Operations.

The tax benefit for stock-based compensation is included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. In accordance with ASC 718, the Company recognizes a tax benefit only to the extent it reduces the Company’s income taxes payable. For the years ended December 31, 2010, 2009 and 2008, the Company realized tax benefits of $0.1 million, $13.8 million and $10.7 million, respectively.

Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and their cash flowsthat do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

Market Risk

The Company’s primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for eachoil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The capital markets continue to be volatile with periods of easy access and times with unfavorable conditions. As a result of the three yearsvolatility in the capital markets and the Company’s increased level of borrowings, it may a times experience increased costs associated with future borrowings and debt issuances based on recent financings. At this time, the Company does not believe its liquidity has been materially affected by market events.

Credit Risk

Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

In 2010, one customer accounted for approximately 11% of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of the Company’s total sales.

Use of Estimates

In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and

- 65 -


liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, asset retirement obligations, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:

   December 31, 

(In thousands)

  2010  2009 

Proved Oil and Gas Properties

  $4,794,650   $4,118,005  

Unproved Oil and Gas Properties

   490,181    423,373  

Gathering and Pipeline Systems

   237,043    294,755  

Land, Building and Other Equipment

   86,248    77,474  
         
   5,608,122    4,913,607  

Accumulated Depreciation, Depletion and Amortization

   (1,845,362  (1,555,408
         
  $3,762,760   $3,358,199  
         

The following table reflects the net changes in capitalized exploratory well costs during 2010, 2009 and 2008.

   December 31, 

(In thousands)

  2010  2009  2008 

Beginning balance at January 1

  $4,179   $5,990   $2,161  

Additions to capitalized exploratory well costs pending the determination of proved reserves

   4,285    4,179    5,990  

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves

   (4,148  (762  (1,259

Capitalized exploratory well costs charged to expense

   (31  (5,228  (902
             

Ending balance at December 31

  $4,285   $4,179   $5,990  
             

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

   December 31, 

(In thousands)

  2010   2009   2008 

Capitalized exploratory well costs that have been capitalized for a period of one year or less

  $4,285    $4,179    $5,990  

Capitalized exploratory well costs that have been capitalized for a period greater than one year

   —       —       —    
               

Balance at December 31

  $4,285    $4,179    $5,990  
               

- 66 -


At December 31, 2010, 2009 and 2008, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

In November 2010, the Company recorded an impairment of $5.1 million related to drilling and service equipment that was primarily used in drilling our West Virginia properties. The impairment was a result of decreased activity in West Virginia and the decision to sell the underlying assets. These assets were reduced to fair value of approximately $4.0 million. Fair value was determined using the market approach which considered broker quotes from market participants in the oil field services sector. The estimate was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined in ASC 820.

In September 2010, the Company recorded a $35.8 million impairment of oil and gas properties due to continued price declines and limited activity in two south Texas fields. These fields were reduced to a fair value of approximately $15.4 million using discounted future cash flows.

During 2009, the Company recorded $17.6 million of impairments of oil and gas properties. The Company recorded an impairment of $12.0 million in the Fossil Federal field in San Miguel County, Colorado in the North region resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas in the South region resulting from lower well performance. These fields were reduced to fair value of approximately $8.9 million using discounted future cash flows.

The fair value of the impaired fields was based on significant inputs that were not observable in the market and are considered to be level 3 inputs as defined in ASC 820. Refer to Note 14 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and production costs and (4) risk adjusted discount rates (14% at September 30, 2010 and 16% at December 31, 2009, respectively).

During 2008, the Company recorded an impairment of approximately $3.0 million in the Corral Creek field in Washakie County, Wyoming in the North region resulting from lower than expected performance from the two well field and $28.3 million in the Trawick field in Rusk County, Texas in the South region resulting from a decline in natural gas prices and higher well costs.

During 2010, 2009 and 2008, amortization of the Company’s unproved properties were $47.6 million, $30.0 million and $41.5 million, respectively and are included in Depreciation, Depletion, and Amortization in the Consolidated Statement of Operations. Included in 2008 amortization was $17.0 million related to three exploratory oil and gas prospects located in Mississippi, Montana and North Dakota that were abandoned. These prospects were abandoned as a result of the significant decline in commodity prices in the fourth quarter of 2008 and the Company’s change in exploration plans for these prospects.

In April 2008, the Company acquired a small oilfield services business for total consideration of $21.6 million, comprised of the conversion of a $15.6 million note receivable, the issuance of 70,168 shares of Company common stock, and the payment of $2.5 million in cash. The transaction was accounted for as a business combination, and the Company recorded approximately $4.4 million of goodwill. In December 2008, the Company fully impaired the goodwill due to the impact of the broad economic downturn and the related reductions in future drilling programs.

- 67 -


East Texas Property Acquisition

On August 15, 2008, the Company completed the acquisition of certain producing oil and gas properties located in Panola and Rusk counties, Texas in order to expand its position in the Minden field. Total net cash consideration paid by the Company in the transaction was approximately $604.0 million. The east Texas acquisition was recorded using the purchase method of accounting. Financial results for the period from the closing date on August 15, 2008 to December 31, 2009 are included within the Company’s Consolidated Statements of Operations. The following table presents the unaudited pro forma results of operations for the year ended December 31, 2008, as if the acquisition was made at the beginning of the period. These pro forma results are not necessarily indicative of future results, nor do they purport to represent the actual financial results that would have occurred had the acquisition been in conformity with accounting principles generally acceptedeffect for the periods presented.

(In thousands, except per share amounts)

  Year Ended
December 31,  2008
 
   (Unaudited) 

Revenues

  $1,009,412  

Net Income

  $218,290  

Earnings Per Share:

  

Basic

  $2.12  

Diluted

  $2.10  

Weighted-Average Common Shares Outstanding:

  

Basic

   103,142  

Diluted

   104,131  

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 and recognized a $49.3 million gain on sale of assets. 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 United Statesfirst half of America. Also2011. 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 in Susquehanna County, and build two compressor stations in the next two years. Additionally, Williams will connect all of the Company’s drilling program wells, which will connect our opinion,production to five interstate pipeline delivery options.

In November 2010, the Company maintained,sold certain oil and gas properties in the Texas panhandle to Kimbrel Oil Corporation and Millbrae Energy VII, LLC for $11.5 million and recognized a $10.8 million gain on sale of assets.

In July 2010, the Company sold certain oil and gas properties located in Colorado to Patera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, the Company recognized an impairment loss of approximately $5.8 million associated with the sale of these properties. The impairment charge is included in Gain / (Loss) on Sale of Assets in the Consolidated Statement of Operations. Fair value of the impaired properties was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of assets held for sale were considered Level 2 in the fair value hierarchy.

In June 2010, the Company sold its Woodford shale prospect located in Oklahoma to Continental Resources, Inc. The Company received approximately $15.9 million in cash proceeds and recognized a $10.3 million gain on sale of assets.

- 68 -


The Company recognized a $3.3 million aggregate loss on sale of assets for the year ended December 31, 2009. This loss included a loss of approximately $16.0 million primarily related to the sale of the Canadian properties described below and a gain of $12.7 million primarily related to the sale of Thornwood properties in the North region. Cash proceeds of $11.4 million were received from the sale of the Thornwood properties.

In April 2009, the Company sold substantially all material respects, effective internal control over financial reportingof its Canadian properties to a Tourmaline Oil Corporation (Tourmaline). Total consideration received from the sale was $84.4 million, consisting of $63.8 million in cash and $20.6 million in common stock of Tourmaline (see Note 4). The total net book value of the Canadian properties sold was $95.0 million. At December 31, 2008, the Company recorded 40.4 Bcfe of proved reserves (two percent of total proved reserves) related to these properties.

- 69 -


3. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:

   December 31, 

(In thousands)

  2010  2009 

ACCOUNTS RECEIVABLE, NET

   

Trade Accounts

  $91,077   $78,656  

Joint Interest Accounts

   4,901    3,564  

Other Accounts

   2,603    1,756  
         
   98,581    83,976  

Allowance for Doubtful Accounts

   (4,093  (3,614
         
  $94,488   $80,362  
         

INVENTORIES

   

Natural Gas in Storage

  $13,371   $14,434  

Tubular Goods and Well Equipment

   17,072    14,420  

Pipeline Imbalances

   (776  (864
         
  $29,667   $27,990  
         

OTHER CURRENT ASSETS

   

Drilling Advances

  $2,796   $3,417  

Prepaid Balances

   2,925    5,980  

Deferred Income Taxes

   257    —    
         
  $5,978   $9,397  
         

OTHER ASSETS

   

Rabbi Trust Deferred Compensation Plan

  $15,788   $10,031  

Debt Issuance Cost

   22,061    11,621  

Other Accounts

   1,414    1,412  

Investment in Equity Securities

   —      20,636  
         
  $39,263   $43,700  
         

ACCOUNTS PAYABLE

   

Trade Accounts

  $27,401   $17,434  

Natural Gas Purchases

   3,596    3,558  

Royalty and Other Owners

   36,034    40,080  

Accrued Capital Costs

   146,824    141,122  

Taxes Other Than Income

   2,655    4,267  

Drilling Advances

   523    864  

Wellhead Gas Imbalances

   5,142    4,140  

Other Accounts

   7,806    4,123  
         
  $229,981   $215,588  
         

ACCRUED LIABILITIES

   

Employee Benefits

  $10,790   $11,222  

Pension and Postretirement Benefits

   1,688    1,469  

Taxes Other Than Income

   14,576    22,780  

Interest Payable

   19,488    20,205  

Derivative Contracts

   —      425  

Other Accounts

   1,355    1,948  
         
  $47,897   $58,049  
         

OTHER LIABILITIES

   

Rabbi Trust Deferred Compensation Plan

  $21,600   $19,087  

Derivative Contracts

   2,180    1,954  

Other Accounts

   8,399    6,793  
         
  $32,179   $27,834  
         

- 70 -


4. Investment in Equity Securities Carried at Cost

In April 2009, the Company received three million shares of common stock in Tourmaline as partial proceeds for the sale of substantially all of the Company’s Canadian assets. The common stock was carried at cost of $20.6 million and was included in Other Assets in the Consolidated Balance Sheet. As of December 31, 2008, based on criteria established inInternal Control—Integrated Framework issued by2009, the CommitteeCompany estimated the fair value of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility isinvestment to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal controlbe $42.8 million based on the assessed risk. Our audits also included performing such other procedures as wecommon stock value received in a recent private placement of Tourmaline’s common stock. Accordingly, the inputs associated with the fair value of the investment were considered necessarylevel 3 in the circumstances. We believe that our audits provide a reasonable basis for our opinions.fair value hierarchy.

As discussed in Note 11 to the consolidated financial statements,In November 2010, the Company changedsold its investment in common stock of Tourmaline for $61.3 million and recognized a gain of $40.7 million which is included in Gain/(Loss) on Sale of Assets in the manner in which it accounts forConsolidated Statement of Operations.

5. Debt and reports fair value measurements in 2008. As discussed in Note 5 to the consolidated financial statements, the Company changed the manner in which it accounts for its defined benefit pension and other postretirement plans in 2006.Credit Agreements

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositionsThe Company’s debt consisted of the assets of the company; (ii) provide reasonable assurance that transactions are recordedfollowing as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/    PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2009

Index to Financial Statements

CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)of:

 

   Year Ended December 31,
   2008  2007  2006

OPERATING REVENUES

      

Natural Gas Production

  $758,755  $581,640  $568,097

Brokered Natural Gas

   114,220   93,215   93,651

Crude Oil and Condensate

   69,711   55,243   91,380

Other

   3,105   2,072   8,860
            
   945,791   732,170   761,988

OPERATING EXPENSES

      

Brokered Natural Gas Cost

   100,449   81,819   83,375

Direct Operations—Field and Pipeline

   91,839   77,170   74,790

Exploration

   31,200   39,772   49,397

Depreciation, Depletion and Amortization

   185,403   143,951   128,975

Impairment of Unproved Properties

   41,512   19,042   11,117

Impairment of Oil & Gas Properties and Other Assets (Note 2)

   35,700   4,614   3,886

General and Administrative

   74,185   50,775   58,168

Taxes Other Than Income

   66,540   53,782   55,351
            
   626,828   470,925   465,059

Gain on Sale of Assets

   1,143   13,448   232,017

Gain on Settlement of Dispute (Note 7)

   51,906   —     —  
            

INCOME FROM OPERATIONS

   372,012   274,693   528,946

Interest Expense and Other

   36,389   17,161   18,441
            

Income Before Income Taxes

   335,623   257,532   510,505

Income Tax Expense

   124,333   90,109   189,330
            

NET INCOME

  $211,290  $167,423  $321,175
            

Basic Earnings Per Share

  $2.10  $1.73  $3.32

Diluted Earnings Per Share

  $2.08  $1.71  $3.26

Weighted-Average Common Shares Outstanding

   100,737   96,978   96,803

Diluted Common Shares (Note 13)

   101,726   98,130   98,601

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements

CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands, except share amounts)

   December 31, 
    2008  2007 
     

ASSETS

   

Current Assets

   

Cash and Cash Equivalents

  $28,101  $18,498 

Accounts Receivable, Net (Note 3)

   109,087   109,306 

Income Taxes Receivable

   526   3,832 

Inventories (Note 3)

   45,677   27,353 

Deferred Income Taxes

   —     22,526 

Derivative Contracts (Note 11)

   264,660   12,655 

Other Current Assets (Note 3)

   12,500   23,313 
         

Total Current Assets

   460,551   217,483 

Properties and Equipment, Net (Successful Efforts Method) (Note 2)

   3,135,828   1,908,117 

Derivative Contracts (Note 11)

   90,542   —   

Other Assets (Note 3)

   14,743   31,217 
         
  $3,701,664  $2,156,817 
         

LIABILITIES AND STOCKHOLDERS’ EQUITY

   

Current Liabilities

   

Accounts Payable (Note 3)

  $222,985  $173,497 

Current Portion of Long-Term Debt

   35,857   20,000 

Deferred Income Taxes

   63,985   —   

Income Taxes Payable

   5,535   1,391 

Derivative Contracts (Note 11)

   —     5,383 

Accrued Liabilities (Note 3)

   50,551   48,065 
         

Total Current Liabilities

   378,913   248,336 

Long-Term Liability for Pension and Postretirement Benefits (Note 5)

   54,714   26,947 

Long-Term Debt (Note 4)

   831,143   330,000 

Deferred Income Taxes

   599,106   433,923 

Other Liabilities (Note 3)

   47,226   47,354 

Commitments and Contingencies (Note 7)

   

Stockholders’ Equity

   

Common Stock:

   

Authorized—120,000,000 Shares of $0.10 Par Value

   

Issued—103,561,268 Shares and 102,681,468 Shares in 2008 and 2007, respectively

   10,356   10,268 

Additional Paid-in Capital

   675,568   424,229 

Retained Earnings

   921,561   722,344 

Accumulated Other Comprehensive Income / (Loss) (Note 14)

   186,426   (894)

Less Treasury Stock, at Cost: (Note 9)
202,200 Shares and 5,204,700 Shares in 2008 and 2007, respectively

   (3,349)  (85,690)
         

Total Stockholders’ Equity

   1,790,562   1,070,257 
         
  $3,701,664  $2,156,817 
         

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements

CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

   Year Ended December 31, 
    2008  2007  2006 

CASH FLOWS FROM OPERATING ACTIVITIES

    

Net Income

  $211,290  $167,423  $321,175 

Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:

    

Depreciation, Depletion and Amortization

   185,403   143,951   128,975 

Impairment of Unproved Properties

   41,512   19,042   11,117 

Impairment of Oil & Gas Properties and Other Assets

   35,700   4,614   3,886 

Deferred Income Tax Expense

   120,851   95,152   52,011 

Gain on Sale of Assets

   (1,143)  (13,448)  (232,017)

Gain on Settlement of Dispute

   (31,706)  —     —   

Exploration Expense

   31,200   39,772   49,397 

Stock-Based Compensation Expense and Other

   15,623   16,241   21,271 

Changes in Assets and Liabilities:

    

Accounts Receivable, Net

   (3,928)  6,854   39,463 

Income Taxes Receivable

   34,521   14,456   (11,198)

Inventories

   (18,324)  5,644   (8,381)

Other Current Assets

   10,816   (14,908)  1,007 

Other Assets

   5,698   (29,795)  (733)

Accounts Payable and Accrued Liabilities

   3,321   1,052   (29,694)

Income Taxes Payable

   3,580   (1,281)  18,398 

Other Liabilities

   724   7,368   1,912 

Stock-Based Compensation Tax Benefit

   (10,691)  —     (9,485)
             

Net Cash Provided by Operating Activities

   634,447   462,137   357,104 
             

CASH FLOWS FROM INVESTING ACTIVITIES

    

Capital Expenditures

   (817,440)  (553,229)  (460,742)

Acquisitions

   (605,748)  (3,982)  (6,688)

Proceeds from Sale of Assets

   2,099   7,061   329,474 

Exploration Expense

   (31,200)  (39,772)  (49,397)
             

Net Cash Used in Investing Activities

   (1,452,289)  (589,922)  (187,353)
             

CASH FLOWS FROM FINANCING ACTIVITIES

    

Increase in Debt

   892,000   175,000   205,000 

Decrease in Debt

   (375,000)  (65,000)  (305,000)

Net Proceeds from Sale of Common Stock

   316,230   5,099   6,235 

Stock-Based Compensation Tax Benefit

   10,691   —     9,485 

Purchase of Treasury Stock

   —     —     (46,492)

Dividends Paid

   (12,073)  (10,670)  (7,751)

Capitalized Debt Issuance Costs

   (4,403)  —     —   
             

Net Cash Provided by / (Used in) Financing Activities

   827,445   104,429   (138,523)
             

Net Increase / (Decrease) in Cash and Cash Equivalents

   9,603   (23,356)  31,228 

Cash and Cash Equivalents, Beginning of Year

   18,498   41,854   10,626 
             

Cash and Cash Equivalents, End of Year

  $28,101  $18,498  $41,854 
             

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements

CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands, except per share amounts)

   Common
Shares
  Stock
Par
  Treasury
Shares
  Treasury
Stock
  Paid-In
Capital
  Accumulated
Other
Comprehensive
Income /
(Loss)(1)
  Retained
Earnings
  Total 

Balance at December 31, 2005

  100,164  $10,016  3,028  $(39,198) $392,341  $(15,115) $252,167  $600,211 
                               

Net Income

  —     —    —     —     —     —     321,175   321,175 

Exercise of Stock Options

  876   88  —     —     6,127   —     —     6,215 

Purchase of Treasury Stock

  —     —    2,177   (46,492)  —     —     —     (46,492)

Tax Benefit of Stock-Based Compensation

  —     —    —     —     9,485   —     —     9,485 

Stock Amortization and Vesting

  378   38  —     —     10,042   —     —     10,080 

Cash Dividends at $0.08 per Share

  —     —    —     —     —     —     (7,751)  (7,751)

Effect of Adoption of SFAS No. 158

  —     —    —     —     —     (14,079)  —     (14,079)

Other Comprehensive Income

  —     —    —     —     —     66,354   —     66,354 
                               

Balance at December 31, 2006

  101,418  $10,142  5,205  $(85,690) $417,995  $37,160  $565,591  $945,198 
                               

Net Income

  —     —    —     —     —     —     167,423   167,423 

Exercise of Stock Options

  619   62  —     —     5,005   —     —     5,067 

Stock Amortization and Vesting

  430   43  —     —     7,503   —     —     7,546 

Stock Held in Rabbi Trust

  214   21  —     —     (6,274)  —     —     (6,253)

Cash Dividends at $0.11 per Share

  —     —    —     —     —     —     (10,670)  (10,670)

Other Comprehensive Income

  —     —    —     —     —     (38,054)  —     (38,054)
                               

Balance at December 31, 2007

  102,681  $10,268  5,205  $(85,690) $424,229  $(894) $722,344  $1,070,257 
                               

Net Income

  —     —    —     —     —     —     211,290   211,290 

Exercise of Stock Options

  328   33  —     —     2,692   —     —     2,725 

Retirement of Treasury Stock

  (5,003)  (500) (5,003)  82,341   (81,841)  —     —     —   

Tax Benefit of Stock-Based Compensation

  —     —    —     —     10,691   —     —     10,691 

Stock Amortization and Vesting

  418   42  —     —     6,545   —     —     6,587 

Stock Held in Rabbi Trust

  64   6  —     —     (3,198)  —     —     (3,192)

Stock Issued for Drilling Company Acquisition

  70   7  —     —     3,493   —     —     3,500 

Issuance of Common Stock

  5,003   500  —     —     312,957   —     —     313,457 

Cash Dividends at $0.12 per Share

  —     —    —     —     —     —     (12,073)  (12,073)

Other Comprehensive Income

  —     —    —     —     —     187,320   —     187,320 
                               

Balance at December 31, 2008

  103,561  $10,356  202  $(3,349) $675,568  $186,426  $921,561  $1,790,562 
                               

(1)

For further details on the components of Accumulated Other Comprehensive Income and Loss, refer to Note 14 of the Notes to the Consolidated Financial Statements.

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements

CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(In thousands)

   Year Ended December 31, 
    2008  2007  2006 

Net Income

   $211,290   $167,423  $321,175 
               

Other Comprehensive Income / (Loss), net of taxes:

      

Reclassification Adjustment for Settled Contracts, net of taxes of $4,844, $29,801 and $10,686, respectively

    (8,177)   (49,241)  (17,580)

Changes in Fair Value of Hedge Positions, net of taxes of $(134,259), $(1,777) and $(49,311), respectively

    226,692    2,555   81,679 

Defined Benefit Pension and Postretirement Plans:

      

Net Loss Arising During the Year, net of taxes of $10,445 and $1,034, respectively

  $(17,629)  $(1,733)  

Amortization of Net Obligation at Transition, net of taxes of $(234) and $(238), respectively

   398    394   

Amortization of Prior Service Cost, net of taxes of $(373) and $(413), respectively

   630    681   

Amortization of Net Loss, net of taxes of $(603) and $(483), respectively

   1,020   (15,581)  799   141   3,081 
            

Foreign Currency Translation Adjustment, net of taxes of $9,292, $(5,072) and $507, respectively

    (15,614)   8,491   (826)
               

Total Other Comprehensive Income / (Loss)

    187,320    (38,054)  66,354 
               

Comprehensive Income

   $398,610   $129,369  $387,529 
               

The accompanying notes are an integral part of these consolidated financial statements.

Index to Financial Statements

CABOT OIL & GAS CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

(In thousands)

  December 31,
2010
   December 31,
2009
 

Basis of Presentation and Nature of Operations

Cabot Oil & Gas Corporation and its subsidiaries are engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, crude oil and natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil development, exploitation and exploration, exclusively within the continental United States and Canada.States. The Company’s exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

Certain reclassifications have been made to prior year statement to conform with current year presentation. These reclassifications have no impact on net income.

In 2009, the Company reorganized its operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with its Texas and Louisiana areas to form the South region. Additionally, the Company exited Canada through the sale of its properties in April 2009. Prior to the third quarter of 2009, the Company presented the geographic areas as East, Gulf Coast, West and Canada.

The consolidated financial statements contain the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain prior year amounts have been reclassified to conform to the current year presentation.

On February 23, 2007, the Board of Directors declared a 2-for-1 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 30, 2007 to stockholders of record on March 16, 2007. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company’s common stock.

Recently IssuedAdopted Accounting PronouncementsStandards

In December 2008,February 2010, the Securities and Exchange Commission (SEC)Financial Accounting Standards Board (FASB) issued ReleaseAccounting Standards Update (ASU) No. 33-8995, “Modernization of Oil and Gas Reporting,2010-09, “Subsequent Events,” which amends Accounting Standards Codification (ASC) 855 to eliminate the oilrequirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 will be required to price proved oil and gas reserves using the unweighted arithmetic average of the priceits adoption had no impact on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning January 1, 2010. The Company is currently evaluating what impact Release No. 33-8995 may have on itsCompany’s financial position, results of operations or cash flows.

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In June 2008,addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” Under this FSP, unvested share-based payment awards that contain nonforfeitable rightslevel of disaggregation and inputs and valuation techniques and makes conforming amendments to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securitiesthe guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and should be includedsettlements in the computation of earnings per share pursuant to the two-class method. FSP No. EITF 03-6-1 isLevel 3 reconciliation are effective for financial statements issued for fiscal years beginning after December 15, 2008, and2010 (and for interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. Thesuch years). Accordingly, the Company does not believe that FSP No. EITF 03-6-1 will have a materialapply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on its financial position, results of operations or cash flows.

In May 2008, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies a consistent framework for selecting accounting principles to be used in preparing financial statements for nongovernmental entities that are presented in conformity with United States generally accepted accounting principles (GAAP). The current GAAP hierarchy

Index to Financial Statements

was criticized due to its complexity, ranking position of FASB Statements of Financial Accounting Concepts and the fact that it is directed at auditors rather than entities. SFAS No. 162 will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” The FASB does not expect that SFAS No. 162 will have a change in current practice, and the Company does not believe that SFAS No. 162 will have an impact on its financial position, results of operations or cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Enhanced disclosures to improve financial reporting transparency are required and include disclosure about the location and amounts of derivative instruments in the financial statements, how derivative instruments are accounted for and how derivatives affect an entity’s financial position, financial performance and cash flows. A tabular format including the fair value of derivative instruments and their gains and losses, disclosure about credit risk-related derivative features and cross-referencing within the footnotes are also new requirements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application and comparative disclosures encouraged, but not required. The Company has not yet adopted SFAS No. 161. It does not believe that there will be an impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. The Company cannot predict the impact that the adoption of SFAS No. 141(R) will have on itsCompany’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 14.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with respectoriginal maturities of three months or less to any acquisitions completed afterbe cash equivalents. Cash and cash equivalents were primarily concentrated in one financial institution at December 31, 2008.2010 and 2009. The Company periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal.

Inventories

Inventories are comprised of natural gas in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of average cost or market. Natural gas in storage is valued at average cost. Tubular goods and well equipment are valued at historical cost.

- 61 -


Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of the natural gaspipeline imbalance is included in inventory in the Consolidated Balance Sheet.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against Accounts Receivable in the Consolidated Balance Sheet, was $4.1 million and $3.6 million at December 31, 2010 and 2009, respectively.

Accounts Payable

This account may include credit balances from outstanding checks in zero balance cash accounts. These credit balances are referred to as book overdrafts and are included as a component of Accounts Payable on the Consolidated Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in Accounts Payable at December 31, 2010 and 2009 as sufficient cash was available for offset.

Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Index to Financial Statements

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to exploration expense. For a discussion of the Company’s suspended wells, see Note 2 of the Notes to the Consolidated Financial Statements.

The Company determines if an impairment has occurred through either adverse changes or as a result of a review of all fields. The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. During 2008, 2007 and 2006, the Company recorded total impairments of $31.3 million (excluding the impairment of $4.4 million of goodwill), $4.6 million and $3.9 million, respectively.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. The costs of unproved oil and gas properties are generally combined and impaired over a period that is based on the average holding period for such properties and the Company’s experience of successful drilling. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Generally pipeline and transmission systems are depreciated over 12 to 25 years, gathering and compression equipment is depreciated over 10 years and storage equipment and facilities are depreciated over 10 to 16 years. Certain other assets are depreciated on a straight-line basis over 3 to 10 years. Buildings are depreciated on a straight-line basis over 25 to 40 years.

Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not

- 62 -


significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold. See Note 2

The Company evaluates the impairment of its oil and gas properties and other assets whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the Notesasset. If the future undiscounted expected cash flows, based on estimates of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil. During 2010, 2009 and 2008, the Company recorded total impairments of $40.9 million, $17.6 million and $31.3 million (excluding the impairment of $4.4 million of goodwill), respectively.

Costs attributable to the Consolidated Financial Statements forCompany’s unproved properties are not subject to the impairment analysis described above; however, a discussionportion of the dispositioncosts associated with such properties is subject to amortization based on past drilling and development experience and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities are also recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2010, there were no assets legally restricted for purposes of settling asset retirement obligations.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included within Depreciation, Depletion and Amortization expense on the Company’s offshore portfolioConsolidated Statement of Operations.

Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas and certain south Louisiana propertiescrude oil price swaps or zero-cost price collars, as a hedging strategy to manage commodity price risk associated with its production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a third party, which was substantially completedhedge is terminated prior to expected maturity, gains or losses are deferred and included in 2006 (the 2006 south Louisianaincome in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge are recognized currently in the results of operations.

When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to

- 63 -


occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge.

Effective January 1, 2009, the Company adopted the amended disclosure requirements prescribed in ASC 815, “Derivatives and offshore properties sale).Hedging.”

Revenue Recognition and

Gas ImbalancesImbalance

The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in accounts payableAccounts Payable in the Consolidated Balance Sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties. See Note 3 of the Notes to the Consolidated Financial Statements for the Company’s wellhead gas imbalances.

Index to Financial Statements

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses.Expenses in accordance with ASC 605-45, “Revenue Recognition: Principle Agent Considerations”. The Company realizes brokered margin as a result of buying and selling natural gas in back-to-backutilizing separate purchase and sale transactions, typically with separate counterparties.counterparties, whereby the Company and/or the counterparty takes title to the natural gas purchased or sold. The Company realized $13.8$8.8 million, $11.4$8.3 million and $10.3$13.8 million of brokered natural gas margin in 2010, 2009 and 2008, 2007respectively.

Natural Gas Measurement

The Company records estimated amounts for natural gas revenues and 2006, respectively.natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around.reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

Natural Gas Measurement

- 64 -


The Company records estimated amounts for natural gas revenuesrecognizes accrued interest related to uncertain tax positions in Interest Expense and natural gas purchase costs based on volumetric calculations under its natural gas salesOther expense and purchase contracts. Variances or imbalances resulting fromaccrued penalties related to such calculations are inherentpositions in natural gas sales, production, operation, measurement,General and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Accounts Payable

This account may include credit balances from outstanding checksAdministrative expense in zero balance cash accounts. These credit balances are referred to as book overdrafts, as a component of Accounts Payable on the Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in accounts payable at December 31, 2008 and 2007 as sufficient cash was available for offset.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against the accounts receivable line on the Consolidated Balance Sheet, was $3.5 million and $4.0 million at December 31, 2008 and 2007, respectively.

Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or zero-cost price collars, as a hedging strategy to manage commodity price risk associated with its production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its production or other underlying commitment is hedged

Index to Financial Statements

as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge are recognized currently in the resultsStatement of operations.

When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 11 of the Notes to the Consolidated Financial Statements for further discussion.Operations.

Stock-Based Compensation

The Company followsaccounts for stock-based compensation under a fair value based method of accounting prescribed under ASC 718. Under the provisionsfair value method, compensation cost is measured at the grant date and remeasured each reporting period for liability-classified awards based on the fair value of SFAS No. 123(R), “Share Based Payment (revised 2004).” an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. Stock-based compensation cost for all types of awards is included in General and Administrative Expense in the Consolidated Statement of Operations.

The tax benefit for stock-based compensation is included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. In accordance with SFAS No. 123(R),ASC 718, the Company recognizes a tax benefit only to the extent it reduces the Company’s income taxes payable. For the years ended December 31, 20082010, 2009 and 2006,2008, the Company realized tax benefits of $0.1 million, $13.8 million and $10.7 million, and $9.5 million, respectively. For the year ended December 31, 2007, the Company did not recognize a tax benefit for stock-based compensation as a result of the tax net operating loss position for the year under the Alternative Minimum Tax system. See Note 10 of the Notes to the Consolidated Financial Statements for additional details.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2008 and 2007, the cash and cash equivalents are primarily concentrated in two financial institutions. The Company periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal. Excluded from cash and cash equivalents at December 31, 2007 is $11.6 million of restricted cash. See Note 7 of the Notes to the Consolidated Financial Statements for further details.

Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

Market Risk

The Company’s primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The capital markets continue to be volatile with periods of easy access and times with unfavorable conditions. As a result of the volatility in the capital markets and the Company’s increased level of borrowings, it may a times experience increased costs associated with future borrowings and debt issuances based on recent financings. At this time, the Company does not believe its liquidity has been materially affected by market events.

Credit Risk

Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

In 2010, one customer accounted for approximately 11% of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of the Company’s total sales.

Use of Estimates

In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and

- 65 -


liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other

Index to Financial Statements

contingencies, depreciation, depletion and amortization, asset retirement obligations, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:

 

  December 31,   December 31, 
  2008 2007 
  (In thousands) 

(In thousands)

  2010 2009 

Proved Oil and Gas Properties

  $4,794,650   $4,118,005  

Unproved Oil and Gas Properties

  $315,782  $108,868    490,181    423,373  

Proved Oil and Gas Properties

   3,813,014   2,627,346 

Gathering and Pipeline Systems

   274,192   235,127    237,043    294,755  

Land, Building and Other Equipment

   68,606   41,602    86,248    77,474  
              
   4,471,594   3,012,943    5,608,122    4,913,607  

Accumulated Depreciation, Depletion and Amortization

   (1,335,766)  (1,104,826)   (1,845,362  (1,555,408
              
  $3,135,828  $1,908,117   $3,762,760   $3,358,199  
              

The provisions of FSP FAS 19-1, “Accounting for Suspended Well Costs,” require that, in order for costs to be capitalized, a sufficient quantity of reserves must be discovered in the well to justify its completion as a producing well and that sufficient progress must be made in assessing the well’s economic and operating feasibility. If both of these requirements are not met, the costs should be expensed. The following table reflects the net changes in capitalized exploratory well costs during 2008, 20072010, 2009 and 2006.2008.

 

  December 31,   December 31, 
  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Beginning balance at January 1

  $2,161  $8,428  $6,132   $4,179   $5,990   $2,161  

Additions to capitalized exploratory well costs pending the determination of proved reserves

   5,990   2,161   8,317    4,285    4,179    5,990  

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves

   (1,259)  (8,011)  (5,926)   (4,148  (762  (1,259

Capitalized exploratory well costs charged to expense

   (902)  (417)  (95)   (31  (5,228  (902
                    

Ending balance at December 31

  $5,990  $2,161  $8,428   $4,285   $4,179   $5,990  
                    

At December 31, 2008 and 2007, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling. At December 31, 2006, the Company had four projects that had exploratory well costs that were capitalized for a period greater than one year.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

 

  December 31,  December 31, 
  2008  2007  2006
  (In thousands)

(In thousands)

  2010   2009   2008 

Capitalized exploratory well costs that have been capitalized for a period of one year or less

  $5,990  $2,161  $8,317  $4,285    $4,179    $5,990  

Capitalized exploratory well costs that have been capitalized for a period greater than one year

   —     —     111   —       —       —    
                     

Balance at December 31

  $5,990  $2,161  $8,428  $4,285    $4,179    $5,990  
                     

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year

   —     —     4
         

Index to Financial Statements

- 66 -


At December 31, 2006,2010, 2009 and 2008, the Company had two wells where the drilling was complete, but a determination of whether proved reserves existed coulddid not be made. Costs associated with these wells have been capitalized for less than one year. One well, located in Canada, completed drilling in September 2006. Subsequent well completion attempts were halted until mid-November 2006, waiting for acceptable weather conditions. The well was completed in the first quarter of 2007. The second well is in the Rocky Mountains area and reached total depth in November 2006. Completion attempts were postponed due to the Bureau of Land Management stipulation which prohibited activity until the summer of 2007. Subsequent completion attempts proved unsuccessful and the costs were expensed in the second quarter of 2007.

Included in the December 31, 2006 amount ofany projects that had exploratory well costs that have beenwere capitalized for a period of greater than one year are $0.1 million of costs that have been capitalized since 2005. This amount relates to three projects comprised of preliminary costs incurred in the preparation of well sites where drilling has not commenced as of December 31, 2006. after drilling.

In 2007, it was determined not to drill these projects and associated costs were expensed. Also included in the December 31, 2006 amount was another well that had completed drilling in January 2007 and was awaiting completion results before confirmation of proved reserves could be made. That well was completed in 2007 and proved reserves were recorded in the first quarter of 2007.

During 2008,November 2010, the Company recorded $31.3an impairment of $5.1 million related to drilling and service equipment that was primarily used in drilling our West Virginia properties. The impairment was a result of decreased activity in West Virginia and the decision to sell the underlying assets. These assets were reduced to fair value of approximately $4.0 million. Fair value was determined using the market approach which considered broker quotes from market participants in the oil field services sector. The estimate was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined in ASC 820.

In September 2010, the Company recorded a $35.8 million impairment of oil and gas properties due to continued price declines and limited activity in two south Texas fields. These fields were reduced to a fair value of approximately $15.4 million using discounted future cash flows.

During 2009, the Company recorded $17.6 million of impairments of oil and gas properties. The Company recorded an impairment of $12.0 million in the Fossil Federal field in San Miguel County, Colorado in the North region resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas in the South region resulting from lower well performance. These fields were reduced to fair value of approximately $8.9 million using discounted future cash flows.

The fair value of the impaired fields was based on significant inputs that were not observable in the market and are considered to be level 3 inputs as defined in ASC 820. Refer to Note 14 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and production costs and (4) risk adjusted discount rates (14% at September 30, 2010 and 16% at December 31, 2009, respectively).

During 2008, the Company recorded an impairment of approximately $3.0 million in the Corral Creek field in Washakie County, Wyoming in the WestNorth region resulting from lower than expected performance from the two well field and $28.3 million in the Trawick field in Rusk County, Texas in the Gulf CoastSouth region resulting from a decline in natural gas prices and higher well costs. These fields

During 2010, 2009 and 2008, amortization of the Company’s unproved properties were reduced to fair market value (using discounted future cash flows)$47.6 million, $30.0 million and remain as developmental opportunities for the Company. During 2007, the Company recorded an impairment of approximately $4.6$41.5 million, respectively and are included in Depreciation, Depletion, and Amortization in the Castor field in Bienville Parish, Louisiana in the Gulf Coast region resulting from two non-commercial development completions. During 2006, the Company recorded an impairmentConsolidated Statement of $3.9 million. The impairment was recorded on a marginally productive gas well in Colorado County, Texas in the Gulf Coast region. These impairment charges were reflected in the operating results of the Company for each respective period

During 2008, 2007 and 2006, the Company recorded impairments of unproved properties of $41.5 million, $19.0 million and $11.1 million, respectively.Operations. Included in 2008 impairments wereamortization was $17.0 million related to the impairment of three exploratory oil and gas prospects located in Mississippi, Montana and North Dakota.Dakota that were abandoned. These prospects were impairedabandoned as a result of the significant decline in commodity prices in the fourth quarter of 2008 and abandonment of the Company’s change in exploration plans.plans for these prospects.

In April 2008, the Company acquired a small oilfield services business for total consideration of $21.6 million, comprised of the conversion of a $15.6 million note receivable, the issuance of 70,168 shares of Company common stock, and the payment of $2.5 million in cash. The transaction was accounted for as a business combination, and the Company recorded approximately $4.4 million of goodwill. In December 2008, the Company fully impaired the goodwill due to the impact of the broad economic downturn and the related reductions in future drilling programs.

- 67 -


East Texas Property Acquisition

On August 15, 2008, the Company completed the acquisition of certain producing oil and gas properties located in Panola and Rusk counties, Texas in order to expand its position in the Minden field. Total net cash consideration paid by the Company in the transaction was approximately $604.0 million, which reflects the total gross purchase price of $604.4 million adjusted by $0.4 million comprised of a $1.8 million decrease for the impact of purchase price adjustments, including adjustments based on each party’s share of production proceeds received, expenses paid and capital costs incurred for periods before and after the effective date of the acquisition of May 1, 2008, and a $1.4 million increase for the impact of transaction costs, which were primarily legal and accounting costs.

Index to Financial Statements

The $604.0 million purchase price was allocated to Properties and Equipment and Other Liabilities (for the asset retirement obligation) as follows:

    (In thousands) 

Proved Oil and Gas Properties(1)

  $528,813 

Unproved Oil and Gas Properties

   52,897 

Gathering and Pipeline Systems

   22,814 
     

Total Assets Acquired

   604,524 

Less:

  

Asset Retirement Obligations

   (488)
     
  $604,036 
     

(1)

Proved oil and gas properties were determined based on estimated reserves.

The acquired properties are comprised of approximately 25,000 gross leasehold acres with a 97% average working interest near the Company’s existing Minden field. Most of the producing properties were operated by the sellers. In addition, the acquisition included a natural gas gathering infrastructure of 31 miles of pipeline, 5,400 horsepower of compression and four water disposal wells. The Company estimates that proved reserves included in the acquisition were approximately 182 Bcfe as of August 1, 2008 (allocated mainly to the Cotton Valley formation).

million. The east Texas acquisition was recorded using the purchase method of accounting. Financial results for the period from the closing date on August 15, 2008 to December 31, 20082009 are included within the Company’s 2008 Consolidated StatementStatements of Operations. The following table presents the unaudited pro forma results of operations for the yearsyear ended December 31, 2008, and 2007, as if the acquisition was made at the beginning of eachthe period. These pro forma results are not necessarily indicative of future results, nor do they purport to represent the actual financial results that would have occurred had the acquisition been in effect for the periods presented.

 

   Year Ended December 31,
    2008  2007
   (Unaudited)  (Unaudited)
   (In thousands, except per
share amounts)

Revenues

  $1,009,412  $746,089

Net Income

  $218,290  $135,992

Earnings Per Share:

    

Basic

  $2.12  $1.33

Diluted

  $2.10  $1.32

Weighted-Average Common Shares Outstanding:

    

Basic

   103,142   101,981

Diluted

   104,131   103,133

The Company funded the acquisition with a combination of the net proceeds from its June 2008 sale of approximately five million shares of common stock (see Note 9 of the Notes to the Consolidated Financial Statements) and the net proceeds from its July 2008 private placement of senior unsecured fixed rate notes (see Note 4 of the Notes to the Consolidated Financial Statements). Additionally, in order to mitigate the exposure to price fluctuations of natural gas and crude oil, the Company entered into 12 contracts for natural gas price swaps and three contracts for crude oil swaps in the second quarter of 2008 covering production associated with the acquired properties for the second half of 2008 through 2010 (see Note 11 of the Notes to the Consolidated Financial Statements).

Index to Financial Statements

(In thousands, except per share amounts)

  Year Ended
December 31,  2008
 
   (Unaudited) 

Revenues

  $1,009,412  

Net Income

  $218,290  

Earnings Per Share:

  

Basic

  $2.12  

Diluted

  $2.10  

Weighted-Average Common Shares Outstanding:

  

Basic

   103,142  

Diluted

   104,131  

Disposition of Assets

On September 29, 2006,In December 2010, the Company substantially completedsold 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 and recognized a $49.3 million gain on sale of assets. Under the 2006 south Louisianaterms of the purchase and offshoresale 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. 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 in Susquehanna County, and build two compressor stations 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.

In November 2010, the Company sold certain oil and gas properties in the Texas panhandle to Kimbrel Oil Corporation and Millbrae Energy VII, LLC for $11.5 million and recognized a $10.8 million gain on sale of assets.

In July 2010, the Company sold certain oil and gas properties located in Colorado to Phoenix ExplorationPatera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, the Company LPrecognized an impairment loss of approximately $5.8 million associated with the sale of these properties. The impairment charge is included in Gain / (Loss) on Sale of Assets in the Consolidated Statement of Operations. Fair value of the impaired properties was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of assets held for a gross sales price of $340.0 million.sale were considered Level 2 in the fair value hierarchy.

In June 2010, the Company sold its Woodford shale prospect located in Oklahoma to Continental Resources, Inc. The Company received approximately $333.3$15.9 million in netcash proceeds from the sale. In addition to the netand recognized a $10.3 million gain on sale of $231.2assets.

- 68 -


The Company recognized a $3.3 million ($144.5 million, netaggregate loss on sale of tax) recordedassets for the year ended December 31, 2006,2009. This loss included a loss of approximately $16.0 million primarily related to the sale of the Canadian properties described below and a gain of $12.7 million primarily related to the sale of Thornwood properties in the North region. Cash proceeds of $11.4 million were received from the sale of the Thornwood properties.

In April 2009, the Company sold substantially all of its Canadian properties to a Tourmaline Oil Corporation (Tourmaline). Total consideration received from the sale was $84.4 million, consisting of $63.8 million in cash and $20.6 million in common stock of Tourmaline (see Note 4). The total net book value of the Canadian properties sold was $95.0 million. At December 31, 2008, the Company recorded a net gain40.4 Bcfe of $12.3 million ($7.7 million, netproved reserves (two percent of tax) in the Consolidated Statement of Operations for the year ended December 31, 2007, which included cash proceeds of $5.8 million, $2.1 million in purchase price adjustments and $4.4 million that had been deferred until legal titletotal proved reserves) related to certain properties could be assigned.these properties.

- 69 -


3. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:

 

  December 31,   December 31, 
  2008 2007 
  (In thousands) 

(In thousands)

  2010 2009 

ACCOUNTS RECEIVABLE, NET

      

Trade Accounts

  $94,164  $94,550   $91,077   $78,656  

Joint Interest Accounts

   16,454   16,443    4,901    3,564  

Other Accounts

   1,987   2,291    2,603    1,756  
              
   112,605   113,284    98,581    83,976  

Allowance for Doubtful Accounts

   (3,518)  (3,978)   (4,093  (3,614
              
  $109,087  $109,306   $94,488   $80,362  
              

INVENTORIES

      

Natural Gas in Storage

  $27,478  $20,472   $13,371   $14,434  

Tubular Goods and Well Equipment

   16,439   5,953    17,072    14,420  

Pipeline Imbalances

   1,760   928    (776  (864
              
  $45,677  $27,353   $29,667   $27,990  
              

OTHER CURRENT ASSETS

      

Drilling Advances

  $4,869  $2,475   $2,796   $3,417  

Prepaid Balances

   7,631   8,900    2,925    5,980  

Restricted Cash

   —     11,600 

Other Accounts

   —     338 
       

Deferred Income Taxes

   257    —    
  $12,500  $23,313        
         $5,978   $9,397  
          

OTHER ASSETS

      

Note Receivable

  $—    $13,375 

Rabbi Trust Deferred Compensation Plan

   8,651   9,744   $15,788   $10,031  

Debt Issuance Cost

   22,061    11,621  

Other Accounts

   6,092   8,098    1,414    1,412  
       

Investment in Equity Securities

   —      20,636  
  $14,743  $31,217        
         $39,263   $43,700  
          

ACCOUNTS PAYABLE

      

Trade Accounts

  $44,088  $27,678   $27,401   $17,434  

Natural Gas Purchases

   5,346   6,465    3,596    3,558  

Royalty and Other Owners

   42,349   37,023    36,034    40,080  

Capital Costs

   117,029   83,754 

Accrued Capital Costs

   146,824    141,122  

Taxes Other Than Income

   5,617   6,416    2,655    4,267  

Drilling Advances

   1,289   1,528    523    864  

Wellhead Gas Imbalances

   3,354   3,227    5,142    4,140  

Other Accounts

   3,913   7,406    7,806    4,123  
              
  $222,985  $173,497   $229,981   $215,588  
              

ACCRUED LIABILITIES

   

Employee Benefits

  $10,790   $11,222  

Pension and Postretirement Benefits

   1,688    1,469  

Taxes Other Than Income

   14,576    22,780  

Interest Payable

   19,488    20,205  

Derivative Contracts

   —      425  

Other Accounts

   1,355    1,948  
       
  $47,897   $58,049  
       

OTHER LIABILITIES

   

Rabbi Trust Deferred Compensation Plan

  $21,600   $19,087  

Derivative Contracts

   2,180    1,954  

Other Accounts

   8,399    6,793  
       
  $32,179   $27,834  
       

Index to Financial Statements
   December 31,
    2008  2007
   (In thousands)

ACCRUED LIABILITIES

    

Employee Benefits

  $10,807  $13,699

Current Liability for Pension Benefits

   245   116

Current Liability for Postretirement Benefits

   642   642

Taxes Other Than Income

   16,582   13,216

Interest Payable

   20,684   6,518

Litigation

   —     11,600

Other Accounts

   1,591   2,274
        
  $50,551  $48,065
        

OTHER LIABILITIES

    

Rabbi Trust Deferred Compensation Plan

  $14,531  $16,018

Accrued Plugging and Abandonment Liability

   27,978   24,724

Other Accounts

   4,717   6,612
        
  $47,226  $47,354
        

- 70 -


4. Investment in Equity Securities Carried at Cost

In April 2009, the Company received three million shares of common stock in Tourmaline as partial proceeds for the sale of substantially all of the Company’s Canadian assets. The common stock was carried at cost of $20.6 million and was included in Other Assets in the Consolidated Balance Sheet. As of December 31, 2009, the Company estimated the fair value of its investment to be $42.8 million based on the common stock value received in a recent private placement of Tourmaline’s common stock. Accordingly, the inputs associated with the fair value of the investment were considered level 3 in the fair value hierarchy.

In November 2010, the Company sold its investment in common stock of Tourmaline for $61.3 million and recognized a gain of $40.7 million which is included in Gain/(Loss) on Sale of Assets in the Consolidated Statement of Operations.

5. Debt and Credit Agreements

The Company’s debt consisted of the following:following as of:

 

(In thousands)

  December 31,
2010
   December 31,
2009
 

Long-Term Debt

    

7.33% Weighted-Average Fixed Rate Notes

  $95,000    $170,000  

6.51% Weighted-Average Fixed Rate Notes

   425,000     425,000  

9.78% Notes

   67,000     67,000  

5.58% Weighted-Average Fixed Rate Notes

   175,000     —    

Credit Facility

   213,000     143,000  
        
  December 31,
2008
 December 31,
2007
   $975,000    $805,000  
  (In thousands)         

Long-Term Debt

   

7.19% Notes

  $20,000  $40,000 

7.33% Weighted-Average Fixed Rate Notes

   170,000   170,000 

6.51% Weighted-Average Fixed Rate Notes

   425,000   —   

9.78% Notes

   67,000   —   

Credit Facility

   185,000   140,000 

Current Maturities

   

7.19% Notes

   (20,000)  (20,000)

Credit Facility

   (15,857)  —   
       

Long-Term Debt, excluding Current Maturities

  $831,143  $330,000 
       

The Company has debt maturities of $75 million due in 2013. No other tranches of debt are due within the next five years.

In June 2010, the Company amended the agreements governing its senior notes to amend the required asset coverage ratio (the present value of the Company’s proved reserves plus working capital to debt) contained in the agreements. The amendments revised the calculation of present value of proved reserves to reflect specified pricing assumptions based on quoted futures prices in lieu of historical realized prices, reduced the limit on proved undeveloped reserves included in the calculation from 35% to 30%, and increased the required ratio to 1.75:1 from 1.50:1. The amendments also provided that for so long as a borrowing base calculation is required under the Company’s credit facility, the calculated indebtedness may not exceed 115% of such borrowing base for this ratio. If such a borrowing base calculation is not required under the credit facility, the Company would no longer be subject to the asset coverage ratio under the agreements, but would instead be required to maintain a ratio of debt to consolidated EBITDAX (as defined) not to exceed 3.0 to 1.0. In conjunction with the amendments, the Company incurred $2.0 million of debt issuance costs which were capitalized and are being amortized over the term of the respective amended agreements in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

7.19%7.33% Weighted-Average Fixed Rate Notes

In November 1997,July 2001, the Company issued an aggregate principal amount of $100$170 million of its 12-year 7.19% Notes (7.19% Notes) to a group of sixseven institutional investors in a private placement. The 7.19% Notes require five annual $20 million principal payments which startedhave bullet maturities and were issued in November 2005 and are concluding in November 2009. three separate tranches as follows:

   Principal   Term   Maturity
Date
   Coupon 

Tranche 1

  $75,000,000     10-year     July 2011     7.26

Tranche 2

  $75,000,000     12-year     July 2013     7.36

Tranche 3

  $20,000,000     15-year     July 2016     7.46

- 71 -


The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% Notes7.33% weighted-average fixed rate notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. TheseThose covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must beof at least 1.51.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

Index to Financial Statements

7.33% Weighted-Average Fixed Rate Notes

In July 2001,December 2010, the Company issued $170repaid the $75.0 million outstanding of Notes to a group of seven institutional investors in a private placement. PriorTranche 1 prior to the determination ofdue date. In connection with the Notes’ interest rates,early payment the Company entered intowas required to pay a treasury lockmake-whole premium of $2.8 million which is included in order to reduceInterest Expense and Other in the riskConsolidated Statement of rising interest rates. Interest rates rose during the pricing period, resulting in a $0.7 million gain that is being amortized over the life of the Notes, and thereby reducing the effective interest rate by 5.5 basis points. The Notes have bullet maturities and were issued in three separate tranches as follows:

   Principal  Term  Maturity
Date
  Coupon 

Tranche 1

  $75,000,000  10-year  July 2011  7.26%

Tranche 2

  $75,000,000  12-year  July 2013  7.36%

Tranche 3

  $20,000,000  15-year  July 2016  7.46%

The 7.33% weighted-average fixed rate notes were issued under a substantially similar note purchase agreement as the 7.19% notes and contain the same covenants as discussed above for the 7.19% notes.Operations.

6.51% Weighted-Average Fixed Rate Notes

In July 2008, the Company issued $425 million of senior unsecured fixed-rate notes to a group of 41 institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:

 

  Principal  Term  Maturity
Date
  Coupon   Principal   Term   Maturity
Date
   Coupon 

Tranche 1

  $245,000,000  10-year  July 2018  6.44%  $245,000,000     10-year     July 2018     6.44

Tranche 2

  $100,000,000  12-year  July 2020  6.54%  $100,000,000     12-year     July 2020     6.54

Tranche 3

  $80,000,000  15-year  July 2023  6.69%  $80,000,000     15-year     July 2023     6.69

Interest on each series of the 6.51% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The Notes contain restrictions on the merger of the Company with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves plus adjusted cash (as defined in the note purchase agreement) to debt and other liabilities), of at least 1.51.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. The Notes also are subject to customary events of default. The Company is required to offer to prepay the Notes upon specified change in control events accompanied by a ratings decline below investment grade.

9.78% Notes

In December 2008, the Company issued $67 million aggregate principal amount of its 10-year 9.78% Series G Senior Notes to a group of four institutional investors in a private placement. Interest on the Notes is payable semi-annually. The Company may prepay all or any portion of the Notes on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The other terms of the Notes are substantially similar to the terms of the 6.51% Weighted-Average Fixed Rate Notes.

5.58% Weighted-Average Fixed Rate Notes

In December 2010, the Company issued $175 million of senior unsecured fixed-rate notes to a group of eight institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:

   Principal   Term   Maturity
Date
   Coupon 

Tranche 1

  $88,000,000     10-year     January 2021     5.42

Tranche 2

  $25,000,000     12-year     January 2023     5.59

Tranche 3

  $62,000,000     15-year     January 2026     5.80

Interest on each series of the 5.58% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal

- 72 -


amount thereof plus accrued and unpaid interest plus a make-whole premium. The other terms of the Notes are substantially similar to the terms of the 6.51% Weighted-Average Fixed Rate Notes.

Revolving Credit Agreement

On December 16, 2008,In September 2010, the Company amended and restated its Revolving Credit Agreement (credit facility) with a group of six banks (Class A lenders). Under the amendment, the commitment period for Class A lenders holding approximately 90% of the aggregate commitments of all lenders was extended from December 2009 to October

Index to Financial Statements

2010.revolving credit facility. The outstanding balance under the credit facility provides for the one lender that is not a Class A lender is reflected in the current portionan available credit line of long-term debt on the balance sheet. In June 2008,$900 million and contains an accordion feature allowing the Company amended the credit facility to increase the borrowings capacity from $250 millionavailable credit line to $350 million under the existing accordion feature. At December 31, 2008 and 2007, borrowings outstanding under the credit facility were $185 million and $140 million, respectively. The December 2008 amendment added an accordion feature to allow the Company,$1.0 billion, if any one or more of the existing banks or new banks agree to increaseprovide such increased commitment amount. The credit facility also provides for the availableissuance of letters of credit, line from $350which would reduce the Company’s borrowing capacity. The amended facility provides for a $1.5 billion borrowing base and matures in September 2015.

In conjunction with entering into the September 2010 amended credit facility, the Company incurred $11.7 million to $450 million.of debt issuance costs, which were capitalized and will be amortized over the term of the amended credit facility. Approximately $6.3 million in unamortized costs associated with the original credit facility, as amended in June 2010, will be amortized over the term of the amended credit facility in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

The credit facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of (1) the projected present value (as determined by the banks’ petroleum engineer)banks based on the Company’s reserve reports and engineering reports) of estimated future net cash flows from certain proved oil and gas reserves and certain other assets of the Company.Company (the “Borrowing Base”) and (2) the outstanding principal balance of the Company’s senior notes. Under the credit facility, the Borrowing Base is set at $1.5 billion, to be periodically redetermined as described below. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings in connection with scheduled redetermination or due to a termination of hedge positions, the Company has a period of six months either to reduce its outstanding debt in equal monthly installments to the adjusted credit line available with a requirement to provide additional borrowing base assets or to pay down one-sixthavailable.

The Borrowing Base is redetermined annually under the terms of the excess during eachcredit facility on April 1st. In addition, either the Company or the banks may request an interim redetermination twice a year in connection with certain acquisitions or sales of the six months.oil and gas properties.

Interest rates under the credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins increase if the total indebtedness under the credit facility and the Company’s senior notes is greater than 25%, greater than 50%, greater than 75% or greater than 90% of the Company’s debt limit of $1.2 billion,Borrowing Base, as shown below for Class A lenders holding approximately 90% of the aggregate commitments of all lenders:below:

 

   Debt Percentage 
   Less than
or equal
to 50%
  Greater than
50% and
less than or
equal to
75%
  Greater than
75% and
less than or
equal to
90%
  Greater than
90%
 

Euro-Dollar margin

  1.750% 2.000% 2.250% 2.500%

Base Rate margin

  0.500% 0.750% 1.000% 1.250%

Commitment Fee Rate

  0.375% 0.375% 0.500% 0.500%
   Debt Percentage 
   <25%  ³ 25% <50%  ³ 50% <75%  ³ 75% <90%  ³ 90% 

Eurodollar Margin

   2.000  2.250  2.500  2.750  3.000

Base Rate Margin

   1.125  1.375  1.625  1.875  2.125

The credit facility provides for a commitment fee on the unused available balance at annual rates as shown above.

The Company’s weighted-average effective interest rates for the credit facility during the years ended December 31, 2008, 2007 and 2006 were approximately 4.8%, 7.2% and 7.9%, respectively. As of December 31, 2008, the weighted-average interest rate on the Company’s credit facility was approximately 3.7%0.50%.

The credit facility contains various customary restrictions, which include the following:following (with all calculations based on definitions contained in the agreement):

 

 (a)Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

 

 (b)Maintenance of an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0.

- 73 -


(c)Maintenance of a current ratio of 1.0 to 1.0.

(d)Prohibition on the merger or sale of all or substantially all of the Company’s or any subsidiary’s assets to a third party, except under certain limited conditions.

In addition, the credit facility includes a customary condition to the Company’s borrowings under the facility that there has not occurred a material adverse change has not occurred with respect to the Company.

TheAt December 31, 2010 and 2009, borrowings outstanding under the Company’s credit facilities were $213.0 million and $143.0 million, respectively. In addition, the Company believes it was in compliance in all material respects with its covenants contained in its various debt agreementshad $0.30 million letters of credit outstanding at December 31, 2008 and 2007 and2010.

The Company’s weighted-average effective interest rates for the credit facilities during the years then ended.

ended December 31, 2010, 2009 and 2008 were approximately 3.8%, 4.0% and 4.8%, respectively. As of December 31, 2010 and 2009, the weighted-average interest rate on the Company’s credit facility was approximately 3.1% and 3.9%, respectively.

Index to Financial Statements

5.6. Employee Benefit Plans

Pension Plan

The Company has an underfundeda non-contributory, defined benefit pension plan for all full-time employees.employees, referred to as the tax qualified defined benefit pension plan (qualified pension plan). Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly equity securities and fixed income investments. The Company complies with the Employee Retirement Income Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan.

The Company also has an unfunded non-qualified equalizationsupplemental pension plan to ensure payments to certain executive officers of amounts to which they are alreadywould have been entitled under the provisions of the pension plan, but which are subject tofor limitations imposed by federal tax laws.laws, referred to as the supplemental non-qualified pension arrangements (non-qualified pension plan).

Termination and Amendment of Qualified and Non-Qualified Pension Plans

On July 28, 2010, the Company notified its employees of its plan to terminate its qualified pension plan, with the plan and its related trust to be liquidated following appropriate filings with the Pension Benefit Guaranty Corporation and Internal Revenue Service, effective September 30, 2010. The Company then amended and restated the qualified pension plan to freeze benefit accruals, to provide for termination of the plan, to allow for an early retirement enhancement to be available to all active participants as of September 30, 2010 regardless of their age and years of service as of that date, and to make certain changes that were required or made desirable as a result of developments in the law. Because no further benefits will accrue under the qualified pension plan after September 30, 2010, the Company’s related non-qualified pension plan was effectively frozen and no additional benefits will be accrued under those arrangements after September 30, 2010.

Freezing the above plans resulted in a remeasurement of the pension obligations and plan assets as of July 28, 2010. In calculating the remeasurement at the time of the termination, management used a discount rate of 5.25% for the qualified pension plan and 4.5% for the non-qualified pension plan, which was consistent with the Company’s methodology of determining the discount rate for these plans in prior periods. The discount rate was based on a yield curve based on high-quality corporate bonds that could be purchased to settle the pension obligation. Management determined the discount rate by matching this yield curve with the timing and amounts of the expected benefit payments for the Company’s plans.

As a result of these changes to the Company’s qualified and non-qualified pension plans, the Company revised its amortization period for prior service costs and actuarial losses, which are now amortized over 17

- 74 -


months (from August 2010 to December 2011) to reflect the expected amortization period until final distribution of benefits from each plan. Prior service costs established in each plan prior to freeze were fully recognized in the third quarter of 2010 as a result of the plan freeze. Actuarial losses in the qualified pension plan were previously amortized over 10.6 years and actuarial losses in the non-qualified pension plan were previously amortized over 6 years.

Obligations and Funded Status

The funded status represents the difference between the projected benefit obligation of the Company’s qualified and non-qualified pension plans and the fair value of the qualified pension plan’s assets at December 31.

The change in the combined projected benefit obligation of the Company’s qualified and non-qualified pension plans and the change in the Company’s qualified pension plan assets at fair value during the last three years are as follows:

 

  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Change in Benefit Obligation

        

Benefit Obligation at Beginning of Year

  $51,603  $45,475  $41,211   $75,092   $63,008   $51,603  

Service Cost

   3,313   2,931   2,720    2,774    3,443    3,313  

Interest Cost

   3,272   2,769   2,333    3,700    3,712    3,272  

Actuarial Loss

   5,683   1,314   5    9,265    6,262    5,683  

Plan Amendments

   —     —     (3)

Plan Termination and Amendment

   (12,331  —      —    

Benefits Paid

   (863)  (886)  (791)   (14,628  (1,333  (863
                    

Benefit Obligation at End of Year

   63,008   51,603   45,475    63,872    75,092    63,008  
                    

Change in Plan Assets

        

Fair Value of Plan Assets at Beginning of Year

   44,744   38,189   23,765    53,180    34,295    44,744  

Actual Return on Plan Assets

   (13,682)  3,179   3,587    7,095    10,903    (13,682

Employer Contributions

   5,000   5,000   12,008    15,416    10,136    5,000  

Benefits Paid

   (863)  (886)  (791)   (14,628  (1,333  (863

Expenses Paid

   (904)  (738)  (380)   (985  (821  (904
                    

Fair Value of Plan Assets at End of Year

   34,295   44,744   38,189    60,078    53,180    34,295  
                    

Funded Status at End of Year

  $(28,713) $(6,859) $(7,286)  $(3,794 $(21,912 $(28,713
                    

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet at December 31 consist of the following:

 

   2008  2007  2006 
   (In thousands) 

Current Liabilities

  $(245) $(116) $(67)

Long-Term Liabilities

   (28,468)  (6,743)  (7,219)
             
  $(28,713) $(6,859) $(7,286)
             

Index to Financial Statements

(In thousands)

  2010  2009  2008 

Current Liabilities

  $(603 $(488 $(245

Long-Term Liabilities

   (3,191  (21,424  (28,468
             
  $(3,794 $(21,912 $(28,713
             

Amounts Recognized in Accumulated Other Comprehensive Income

Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:

 

  2008  2007  2006
  (In thousands)

(In thousands)

  2010   2009   2008 

Prior Service Cost

  $143  $194  $336  $1,267    $92    $143  

Net Actuarial Loss

   36,373   13,744   12,946   12,248     32,061     36,373  
                     
  $36,516  $13,938  $13,282  $13,515    $32,153    $36,516  
                     

- 75 -


Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets

 

  2008  2007  2006
  (In thousands)

(In thousands)

  2010   2009   2008 

Projected Benefit Obligation

  $63,008  $51,603  $45,475  $63,872    $75,092    $63,008  

Accumulated Benefit Obligation

  $48,050  $39,544  $34,824  $63,872    $61,822    $48,050  

Fair Value of Plan Assets

  $34,295  $44,744  $38,189  $60,078    $53,180    $34,295  

Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income

Combined Qualified and Non-Qualified Pension Plans

 

  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Components of Net Periodic Benefit Cost

        

Current Year Service Cost

  $3,313  $2,931  $2,721   $2,774   $3,443   $3,313  

Interest Cost

   3,272   2,769   2,333    3,700    3,712    3,272  

Expected Return on Plan Assets

   (3,535)  (3,015)  (1,962)   (4,260  (2,685  (3,535

Amortization of Prior Service Cost

   51   142   175    572    51    51  

Amortization of Net Loss

   1,175   1,089   1,210    8,705    3,177    1,175  

Plan Termination and Amendment

   4,444    —      —    
                    

Net Periodic Pension Cost

  $4,276  $3,916  $4,477   $15,935   $7,698   $4,276  
                    

Other Changes in Qualified Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income

        

Net Loss

  $23,804  $1,887   N/A 

Effect of Plan Termination and Amendment

  $(816 $—     $—    

Settlement

   (4,021  —      —    

Net (Gain) / Loss

   (4,523  (1,135  23,804  

Amortization of Net Loss

   (1,175)  (1,089)  N/A    (8,705  (3,335  (1,175

Amortization of Prior Service Cost

   (51)  (142)  N/A    (572  —      (51
                    

Total Recognized in Other Comprehensive Income

   22,578   656   N/A   $(18,637 $(4,470 $22,578  
                    

Total Recognized in Net Periodic Benefit Cost and Other Comprehensive Income

  $26,854  $4,572   N/A   $(2,702 $3,228   $26,854  
                    

The estimated prior service cost and net loss for the qualified defined benefit pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are less than $0.1$1.0 million and $2.7$10.9 million, respectively.

The estimated prior service cost and net loss for the defined benefit non-qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are less than $0.1$0.3 million and $0.1$1.3 million, respectively.

Index to Financial Statements

Assumptions

Weighted-average assumptions used to determine projected pension benefit obligations at December 31 were as follows:

 

  2008 2007 2006   2010 2009 2008 

Discount Rate

  5.75% 6.00% 5.75%   5.25  5.75  6.00

Rate of Compensation Increase

  4.00% 4.00% 4.00%   —      4.00  4.00

- 76 -


Weighted-average assumptions used to determine net periodic pension costs at December 31 are as follows:

 

  2008 2007 2006   2010 2009 2008 

Discount Rate

  6.00% 5.75% 5.50%

Discount Rate (January 1 - December 31)(1)

   —      5.75  5.75

Discount Rate (January 1, 2010 - July 31, 2010)(2)

   5.25  —      —    

Discount Rate (August 1, 2010 - December 31, 2010)(2)

   4.80  —      —    

Expected Long-Term Return on Plan Assets

  8.00% 8.00% 8.00%   8.00  8.00  8.00

Rate of Compensation Increase

  4.00% 4.00% 4.00%   —      4.00  4.00

(1)

Represents the discount rate used to determine the projected benefit costs for qualified and non-qualified pension plans for 2008 and 2009, respectively.

(2)

Represents the discount rate used to determine the net periodic pension costs for qualified and non-qualified pension plans for 2010. 5.25% was used from January 1, 2010 through July 31, 2010. Due to the plan termination and amendments that were effective in July 2010, the discount rate was adjusted for determining the net periodic pension costs for the remainder of the year to 4.8%.

The long-term expected rate of return on plan assets used in 2008,2010, as shown above, is eight percent.8.0%. The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. One of the plan objectives is that performance of the equity portion of the pension plan exceedexceeds the Standard and Poors’ 500 Index over the long-term. The Company also seeks to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. In the Company’s pension calculations, the Company has used eight percent8.0 % as the expected long-term return on plan assets for 2008, 20072010, 2009 and 2006.2008. In order to derive this return, a Monte Carlo simulation was run using 5,000 simulations based upon the Company’s actual asset allocation and liability duration, which has been determined to be approximately 15 years. This model uses historical data for the period of 1926-2007 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that the Company expects to achieve over 50 percent50% of the time, is approximately nine percent.9%. The Company expects to achieve at a minimum approximately seven percent7% annual real rate of return on the total portfolio over the long-term at least 75 percent75% of the time. The Company believes that the eight percent8% chosen is a reasonable estimate based on its actual results.

Plan Assets

The Company’s pension plan assets were accounted for at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Each portfolio uses independent pricing services approved by the Trustee to value the Company’s investments. All common/collective trust funds are managed by the Trustee. Refer to Note 14 for more information and a description of the fair value hierarchy.

The Company’s investments in equity securities for which market quotations are readily available are valued at the last reported sale price or official closing price as reported by an independent pricing service on the primary market or exchange on which they are traded.

The Company’s investment in debt securities are valued based on quotations received from dealers who transact in markets with such securities or by independent pricing services. For corporate bonds, bank notes, floating rate loans, foreign government and government agency obligations, municipal securities, preferred securities, supranational obligations, U.S. government and government agency obligations pricing services generally utilize matrix pricing which considers yield or price of bonds of comparable quality, coupon, maturity and type as well as dealer supplied prices.

- 77 -


At December 31, 20082010 and 2007,2009, the non-qualified pension plan did not have plan assets. The fair value of the plan assets of the Company’s qualified pension plan at December 31, 20082010 and 2007,2009 by asset category are as follows:

 

   2008  2007 
    Amount  Percent  Amount  Percent 
   (In thousands)     (In thousands)    

Equity securities

  $23,585  69% $31,220  70%

Debt securities

   10,398  30%  12,684  28%

Other(1)

   312  1%  840  2%
               

Total

  $34,295  100% $44,744  100%
               

(In thousands)

  Quoted Prices in
Active Markets
for Identical
Assets (Level 1)
   Significant Other
Observable Inputs
(Level 2)
   Significant
Unobservable Inputs
(Level 3)
   Balance as of
December 31, 2010
 

Asset Category

        

Cash

  $1,201    $—      $—      $1,201  

Equity securities:

        

Domestic:

        

Large-cap

   —       17,578     —       17,578  

Small-cap

   —       3,072     —       3,072  

Emerging Markets

   —       1,817     —       1,817  

Growth

   —       3,623     —       3,623  

International:

        

Diversified

   —       10,204     —       10,204  

Small-cap

   —       1,232     —       1,232  

Debt securities

   —       21,351     —       21,351  
                    
  $1,201    $58,877    $—      $60,078  
                    

 

(1)

Primarily consists of cash and cash equivalents.

(In thousands)

  Quoted Prices in
Active Markets
for Identical
Assets (Level 1)
   Significant Other
Observable Inputs
(Level 2)
   Significant
Unobservable Inputs
(Level 3)
   Balance as of
December 31, 2009
 

Asset Category

        

Cash

  $1,486    $—      $—      $1,486  

Equity securities:

        

Domestic:

        

Large-cap

   —       13,070     —       13,070  

Small-cap

   —       2,731     —       2,731  

Growth

   —       4,544     —       4,544  

International:

        

Diversified

   —       9,623     —       9,623  

Small-cap

   —       2,140     —       2,140  

Debt securities

   —       19,586     —       19,586  
                    
  $1,486    $51,694    $—      $53,180  
                    

The Company’s investment strategy for the pension benefit plan assets is to investremain fully invested in funds to maximize the return overmarket until the long-term, subject to an appropriate level of risk. Additionally,final determination for the objectiveplan termination is for each class of investments to outperform its representative benchmark over the long-term.complete. The Company generally targetswill continue to target a portfolio of assets utilizing equity securities, debt securities and cash equivalents that are within a range of approximately 50% to 80% for equity securities and approximately 20% to 40% for fixed income securities. Large capitalization

Index to Financial Statements

equities may make up a maximum of 65% of the portfolio. Small capitalization equities and international equities may make up a maximum of 30% and 15%, respectively, of the portfolio. Fixed income bonds may make up a maximum of 40% of the portfolio. The account will typically be fully invested; however, as a temporary investment or an asset protection measure, part of the account may be invested in money market investments up to 20%. One percent of the portfolio is invested in short-term funds at the designated bank to meet the cash flow needs of the plan. No prohibited investments, including direct or indirect investments in commodities, commodity futures, derivatives, short sales, real estate investment trusts, letter stock, restricted stock or other private placements, are allowed without prior committee approval.

Cash Flows

Employer Contributions

The funding levels of the pension and postretirement benefit plans (described below) are in compliance with standards set by applicable law or regulation. In 2008, theThe Company did not have any required minimum funding obligations;obligations for its qualified pension plan in 2010; however, it chose to fund $5$10.0 million into the qualified pension plan. In 2009,2011, the Company does not have any required minimum funding obligations for the qualified pension plan. The Company will contribute $0.3 million, as shown below, for the non-qualified pension plan. Currently, management has not determined if any additional discretionary funding will be made in 2009.2011.

- 78 -


The Company previously disclosed in its financial statements for the year ended December 31, 2009 that it expected to contribute $0.5 million to its non-qualified pension plan in 2010. During 2010, the Company contributed $5.4 million to its non-qualified pension plan primarily due to settlements during the year.

Estimated Future Benefit Payments

The following estimated benefit payments underAs a result of the Company’stermination of the qualified and non-qualified pension plans, which reflect expected future service, as appropriate, are expectedthe Company expects to be paid as follows:make a final distribution of benefits from each plan in late 2011 or early 2012.

    Qualified  Non-Qualified  Total
   (In thousands)

2009

  $1,303  $252  $1,555

2010

   1,373   414   1,787

2011

   1,599   322   1,921

2012

   2,079   738   2,817

2013

   2,482   1,374   3,856

Years 2014 - 2018

   19,531   2,232   21,763

Postretirement Benefits Other than Pensions

In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants’ contributions adjusted annually. The life insurance plans were non-contributory. As of January 1, 2006, the Company no longer provides postretirement life insurance coverage. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 234257 retirees and their dependents at the end of 20082010 and 235251 retirees and their dependents at the end of 2007.2009.

When the Company adopted SFAS No. 106, “Employers’ Accounting for Postretirement Benefits ASC 715-60, “Compensation—Retirement Benefits—Defined Benefit Plans—Other Than Pension,”Postretirement” in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the transition obligation, over a period of 20 years, or $0.8 million per year which is included in the annual expense of the plan. Included in the transition obligation are the effects of plan amendments during 1996, 2000 and 2004. As a result of subsequent updates to the adoption of SFAS No. 158,requirements for accounting for Defined Benefit Plans codified in ASC 715-20, “Compensation—Retirement Benefits—Defined Benefit Plans—General,” the remaining unamortized balance at December 31, 2006 of $3.2 million is now recognized in accumulated other comprehensive income. Additionally, a portion of this amount will be amortized and reclassified from the balance sheet to the income statement as expense each year.

Index to Financial Statements

Obligations and Funded Status

The funded status represents the difference between the accumulated benefit obligation of the Company’s postretirement plan and the fair value of plan assets at December 31. The postretirement plan does not have any plan assets; therefore, the funded status is equal to the amount of the December 31 accumulated benefit obligation.

The change in the Company’s postretirement benefit obligation during the last three years, as well as the funded status at the end of the last three years is as follows:

 

  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Change in Benefit Obligation

        

Benefit Obligation at Beginning of Year

  $20,846  $18,781  $11,793   $34,392   $26,888   $20,846  

Service Cost

   1,083   871   789    1,265    1,279    1,083  

Interest Cost

   1,380   1,076   877    1,696    1,594    1,380  

Actuarial Loss

   4,270   880   6,337    (4,415  5,917    4,270  

Plan Amendments

   —     —     (153)

Benefits Paid

   (691)  (762)  (862)   (991  (1,286  (691
                    

Benefit Obligation at End of Year

   26,888   20,846   18,781   $31,947   $34,392   $26,888  
                    

Change in Plan Assets

        

Fair Value of Plan Assets at End of Year

   N/A   N/A   N/A    N/A    N/A    N/A  
                    

Funded Status at End of Year

  $(26,888) $(20,846) $(18,781)  $(31,947 $(34,392 $(26,888
                    

- 79 -


Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet at December 31 consist of the following:

 

  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Current Liabilities

  $(642) $(642) $(577)  $(1,085 $(981 $(642

Long-Term Liabilities

   (26,246)  (20,204)  (18,204)   (30,862  (33,411  (26,246
                    
  $(26,888) $(20,846) $(18,781)  $(31,947 $(34,392 $(26,888
                    

Amounts Recognized in Accumulated Other Comprehensive Income

Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:

 

  2008  2007  2006
  (In thousands)

(In thousands)

  2010   2009   2008 

Transition Obligation

  $1,895  $2,527  $3,159  $632    $1,263    $1,895  

Prior Service Cost

   666   1,618   2,570   —       —       666  

Net Actuarial Loss

   8,214   4,392   3,705   8,408     13,455     8,214  
                     
  $10,775  $8,537  $9,434  $9,040    $14,718    $10,775  
                     

The estimated net obligation at transition prior service cost and net loss for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic postretirement cost over the next fiscal year are $0.6 million $0.7 million and $0.5$0.6 million, respectively.

Index to Financial Statements

Components of Net Periodic Benefit Cost

 

  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Components of Net Periodic Postretirement Benefit Cost

        

Current Year Service Cost

  $1,083  $871  $789   $1,265   $1,279   $1,083  

Interest Cost

   1,380   1,076   877    1,696    1,594    1,380  

Amortization of Prior Service Cost

   952   952   952    —      666    952  

Amortization of Net Obligation at Transition

   632   632   632    632    632    632  

Amortization of Net Loss

   448   193   32    631    676    448  
                    

SFAS 106 Net Periodic Postretirement Cost

   4,495   3,724   3,282 
          

Recognized Curtailment Gain

   —     —     (86)
          

SFAS 88 Cost

   —     —     (86)
          

Total SFAS 106 and SFAS 88 Cost

  $4,495  $3,724  $3,196 

Net Periodic Postretirement Cost

  $4,224   $4,847   $4,495  
                    

Other Changes in Benefit Obligations Recognized in Other Comprehensive Income

        

Net Loss

  $4,270  $880   N/A 

Net (Gain) / Loss

  $(4,415 $5,917   $4,270  

Amortization of Prior Service Cost

   (952)  (952)  N/A    —      (666  (952

Amortization of Net Obligation at Transition

   (632)  (632)  N/A    (632  (632  (632

Amortization of Net Loss

   (448)  (193)  N/A    (631  (676  (448
                    

Total Recognized in Other Comprehensive Income

   2,238   (897)  N/A    (5,678  3,943    2,238  
                    

Total Recognized in Qualified Net Periodic Benefit Cost and Other Comprehensive Income

  $6,733  $2,827   N/A   $(1,454 $8,790   $6,733  
                    

- 80 -


Assumptions

Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:

 

  2008 2007 2006   2010 2009 2008 

Discount Rate(1)

  5.75% 6.00% 5.75%   5.75  5.75  5.75

Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year

  9.00% 9.00% 8.00%   9.00  10.00  9.00

Rate to which the cost trend rate is assumed to decline (the Ultimate Trend Rate)

  5.00% 5.00% 5.00%   5.00  5.00  5.00

Year that the rate reaches the Ultimate Trend Rate

  2013  2012  2010    2015    2015    2013  

 

(1)

Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2008, 20072010, 2009 and 2006,2008, respectively, the beginning of year discount rates of 6.0%5.75%, 5.75% and 5.5%6.0% were used.

Coverage provided to participants age 65 and older is under a fully-insured arrangement. The Company subsidy is limited to 60% of the expected annual fully-insured premium for participants age 65 and older. For all participants under age 65, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, was limited to an aggregate annual amount not to exceed $648,000. This limit increases by 3.5% annually thereafter. The Company prepaid the life insurance premiums for all retirees retiring before January 1, 2006 eliminating all future premiums for retiree life insurance. A life insurance product is offered to employees allowing employees to continue coverage into retirement by paying the premiums directly to the life insurance provider.

Index to Financial Statements

Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

 

  1-Percentage-
Point Increase
  1-Percentage-
Point Decrease
 
  (In thousands) 

(In thousands)

  1-Percentage-
Point  Increase
   1-Percentage-
Point  Decrease
 

Effect on total of service and interest cost

  $453  $(366)  $516    $(419

Effect on postretirement benefit obligation

   4,145   (3,403)   4,727     (3,893

Cash Flows

Contributions

The Company expects to contribute approximately $0.8$1.1 million to the postretirement benefit plan in 2009.2011.

Estimated Future Benefit Payments

The following estimated benefit payments under the Company’s postretirement plans, which reflect expected future service, as appropriate, are expected to be paid as follows:

 

  (In thousands)

2009

  $824

2010

   883

(In thousands)

    

2011

   974  $1,116  

2012

   1,089   1,195  

2013

   1,245   1,384  

Years 2014 - 2018

   8,724

2014

   1,588  

2015

   1,717  

Years 2016 - 2020

   11,119  

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit

- 81 -


plans that provide a benefit that is at least actuarially equivalent to certain Medicare benefits. In accordance with FSP No. FAS 106-2, “Accountingaccounting and Disclosure Requirements Relateddisclosure requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”,2003 codified in ASC 715-60, any measures of the accumulated plan benefit obligation or net periodic postretirement benefit cost in the financial statements or accompanying notes do not reflect the effects of the Act on the Company’s plan. As amended by the Company on January 1, 2006, the postretirement benefit plan excludes prescription drug benefits to participants age 65 and older. Due to this amendment, FSP No. 106-2 did not have anthere was no impact on operating results, financial position or cash flows of the Company.

Savings Investment Plan

The Company has a Savings Investment Plan (SIP), which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary, and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $2.2 million, $2.0$2.2 million and $1.8$2.2 million in 2008, 20072010, 2009 and 2006,2008, respectively. The Company matches employee contributions dollar-for-dollar on the first six percent of an employee’s pretax earnings. The Company’s common stock is an investment option within the SIP.

In July 2010, the Company amended the SIP to provide for discretionary profit sharing contributions upon termination of the qualified pension plan effective September 30, 2010. The Company presently makes a discretionary profit-sharing contribution to this plan in an amount equal to 9% of an eligible plan participant’s salary and bonus. The Company charged to expense plan contributions of $0.8 million in 2010.

Deferred Compensation Plan

In 1998, the Company established a Deferred Compensation Plan. This plan isPlan which was available to officers of the Company and acts as a supplement to the Savings Investment Plan. IfSIP. The Internal Revenue Code does not cap the employee’s base salary and bonus deferrals cause the employee to not receive the full six percent company matchamount of compensation that may be taken into account for purposes of determining contributions to the Savings InvestmentDeferred Compensation Plan

Index and does not impose limitations on the amount of contributions to Financial Statements

the Deferred Compensation Plan. Effective October 1, 2010, the Company will make a contribution annually intoamended the Deferred Compensation Plan to ensure thatbroaden the employee receives a full matching contribution fromgroup of eligible employees who participate in the plan beyond the officers of the Company. UnlikeUnder this amendment, the SIP,Company may designate any member of the Company’s management group as a participant in the Deferred Compensation Plan does notand may further designate whether such a participant is eligible to make deferral elections from their compensation. At the present time, the Company anticipates making such a contribution to the Deferred Compensation Plan on behalf of a participant in the event that Internal Revenue Code limitations cause a participant to receive less than the full Company matching contribution under the SIP. The Deferred Compensation Plan was also amended to provide that the Company would credit the accounts of participants who had entered into supplemental employee retirement plan agreements with the Company in an amount equal to which such participant would have dollar limitsbeen entitled under the terms of the supplemental employee retirement plan agreement in effect between the Company and the participant as of September 29, 2010, if the participant had terminated employment on tax deferred contributions. However,September 30, 2010. This amendment also placed restrictions on the payment of these amounts in order to comply with Section 409A of the Internal Revenue Code.

The assets of this planthe Deferred Compensation Plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company.

The officer participants guidedirect the diversificationdeemed investment of trust assets.amounts credited to their accounts under the Deferred Compensation Plan. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company’s common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly traded and have market prices that are readily available and are reported at market value.available. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company’s common stock, was $8.7$15.8 million and $9.7$10.0 million at December 31, 20082010 and 2007,2009, respectively, and is included within Other Assets in the Consolidated

- 82 -


Balance Sheet. Related liabilities, including the Company’s common stock, totaled $14.5$21.6 million and $16.0$19.1 million at December 31, 20082010 and 2007,2009, respectively, and are included within Other Liabilities in the Consolidated Balance Sheet. ThereWith the exception of the Company’s common stock, there is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets excluding the Company’s common stock, because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants.

The Company’s common stock held in the rabbi trust is recorded at the market value on the date of deferral, which totaled $9.5$6.6 million and $6.3$8.2 million at December 31, 20082010 and 2007,2009, respectively and is included within Additional Paid-in Capital in Stockholders’ Equity in the Consolidated Balance Sheet. As of December 31, 2008, 256,4002010, 174,318 shares of the Company’s stock representing vested performance share awards were deferred into the rabbi trust. During 2008, a reduction2010, an increase to the rabbi trust deferred compensation liability of $4.8$2.5 million was recognized, representing the decreasean increase of $4.1 million related to an increase in the closing price of all shares from December 31, 2009 to December 31, 2010 offset by a reduction in the liability due to shares held inthat were sold out of the rabbi trust from December 31, 2007 to December 31, 2008. This reduction in stock-based compensation expense was included in General and Administrative expense in the Consolidated Statement of Operations.totaling $1.6 million. The CompanyCompany’s common stock issued to the trust is not considered outstanding for purposes of calculating basic earnings per share, but is considered a common stock equivalent in the calculation of diluted earnings per share.

The Company charged to expense plan contributions of $109,196 in 2010, $0 in 2009 and less than $20,000 in each of 2008, 2007 and 2006.2008.

6.7. Income Taxes

Income tax expense / (benefit) is summarized as follows:

 

   Year Ended December 31,
    2008  2007  2006
   (In thousands)

Current

     

Federal

  $2,631  $(1,424) $123,155

State

   30   (3,619)  14,164
            

Total

   2,661   (5,043)  137,319
            

Deferred

     

Federal

   116,127   91,257   49,911

State

   5,545   3,895   2,100
            

Total

   121,672   95,152   52,011
            

Total Income Tax Expense

  $124,333  $90,109  $189,330
            

Index to Financial Statements
   Year Ended December 31, 

(In thousands)

  2010   2009  2008 

Current

     

Federal

  $29,879    $(26,323 $2,631  

State

   3,424     (545  30  
              

Total

   33,303     (26,868  2,661  
              

Deferred

     

Federal

   37,981     100,896    116,127  

State

   23,828     919    5,545  
              

Total

   61,809     101,815    121,672  
              

Total Income Tax Expense

  $95,112    $74,947   $124,333  
              

Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:

 

  Year Ended December 31,   Year Ended December 31, 
  2008 2007 2006 
  (Dollars in thousands) 

(Dollars in thousands)

  2010 2009 2008 

Statutory Federal Income Tax Rate

   35%  35%  35%   35  35  35

Computed “Expected” Federal Income Tax

  $117,468  $90,137  $178,818   $69,475   $78,153   $117,468  

State Income Tax, Net of Federal Income Tax Benefit

   6,581   5,452   14,494    6,638    4,476    6,581  

Qualified Production Activities Deduction(1)

   1,174   —     (2,327)

Benefit Related to Favorable State Tax Determination(2)

   —     (2,831)  —   

Deferred Tax Benefit Related to Reduction in Overall State Tax Rate

   (1,453)  (1,378)  (2,605)

Deferred Tax Adjustment Related to Change in Overall State Tax Rate

   18,973    (3,925  (1,453

Sale of Foreign Assets

   —      (1,656  —    

Other, Net

   563   (1,271)  950    26    (2,101  1,737  
                    

Total Income Tax Expense

  $124,333  $90,109  $189,330   $95,112   $74,947   $124,333  
                    

 

(1)

Carryback of 2008 regular federal net operating losses reduces the 2006 Qualified Production Activities Deduction.

(2)

In November 2007, the Company received a favorable ruling letter related to the computation of income taxes for 2006.

- 83 -


The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31 were as follows:

 

  Year Ended December 31,  Year Ended December 31, 
  2008  2007
  (In thousands)

(In thousands)

        2010               2009       

Deferred Tax Liabilities

        

Property, Plant and Equipment

  $644,347  $472,444  $925,397    $765,811  

Items Accrued for Financial Reporting Purposes

   6,540   5,395

Other Comprehensive Income

   132,474   7,861

Hedging Liabilities / Receivables

   6,419     42,243  

Prepaid Expenses and Other

   6,654     1,635  
              

Total

   783,361   485,700   938,470     809,689  
              

Deferred Tax Assets

        

Alternative Minimum Tax Credit

   17,764   8,587   62,105     38,835  

Net Operating Loss

   40,339   22,170   95,102     31,111  

Items Accrued for Financial Reporting Purposes

   40,472   35,193

Other Comprehensive Income

   21,695   8,353

Foreign Tax Credits

   6,354     1,738  

Pension and Other Post-Retirement Benefits

   13,342     20,914  

Items Accrued for Financial Reporting Purposes and Other

   46,871     37,186  
              

Total

   120,270   74,303   223,774     129,784  
              

Net Deferred Tax Liabilities

  $663,091  $411,397  $714,696    $679,905  
              

As of December 31, 2008, the2010, The Company had incurred net operating losses foralternative minimum tax credit carryforwards of $62.1 million which do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax reporting purposes of $153.4 million that it expects to utilize against 2006 taxable income. These losses include $36.1 million of excess tax deductions pursuant to SFAS No. 123(R) not included as deferred tax assets, the benefit of which cannot be recognized until the deductions reduce taxes payable.in any such year. The Company also had net operating loss carryforwards of $170.7$288.5 million for state income tax reporting purposes, the majority of which will expire between 2016 and 2028.2030. It is more likely than notexpected that these deferred tax benefits will be utilized prior to their expiration.

Uncertain Tax Positions

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.” This Interpretation provides guidance for recognizing and measuring uncertain tax

Index to Financial Statements

positions as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit of the uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN 48 provides additional guidance on measuring the amount of the uncertain tax position. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and increased disclosure of these uncertain tax position. FIN 48 is effective for fiscal years beginning after December 15, 2006.

The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized no change to the liability for unrecognized tax benefits.

The Company recognizes accrued interest related to uncertain tax positions in Interest Expense and Other and accrued penalties related to such positions in General and Administrative expense in the Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods. As of December 31, 2008, the Company determined that no accrual for penalties was required.

As of December 31, 2008 and 2007, the Company’s unrecognized tax benefits were $0.5 million and $2.4 million, respectively. These amounts, if recognized, would not have a significant impact on the effective tax rate.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 

  Year Ended
December 31,
   Year Ended December 31, 
  2008 2007 
  (In thousands) 

(In thousands)

  2010 2009   2008 

Unrecognized tax benefit balance at beginning of year

  $2,425  $1,029   $500   $500    $2,425  

Additions based on tax positions related to the current year

   —     —   

Additions based on tax provisions related to the current year

   —      —       —    

Additions for tax positions of prior years

   —     1,415     —       —    

Reductions for tax positions of prior years

   (1,925)  (19)   (500  —       (1,925

Settlements

   —     —      —      —       —    
                  

Unrecognized tax benefit balance at end of year

  $500  $2,425   $—     $500    $500  
                  

During 2010, unrecognized tax benefits were reduced by $0.5 million as a result of the completion of Internal Revenue Service (IRS) Joint Committee on Taxation review of the 2005-2008 tax years that were under audit by the IRS. This reduction did not materially affect the effective tax rate. During 2008, the Company executed a final settlement agreement with the Internal Revenue ServiceIRS that reduced unrecognized tax benefits by $1.9 million. This reduction did not affect the effective tax rate. The amount of remaining unrecognized tax benefits as

As of December 31, 2008, if recognized, would2010, the Company did not have a significant impact on the effectiveany uncertain tax rate. It is possible that the amount of unrecognized tax benefits will changepositions reported in the next twelve months. The Company does not expect that a change would have a significant impact on its results of operations, financial position or cash flows.Consolidated Balance Sheet.

The Company files income tax returns in the U.S. federal jurisdiction, various states and Canada. The Company is no longer subject to examinations by state authorities before 2001.2005. The Company is not currently under examination by the Internal Revenue Service for 2006.IRS.

- 84 -


7.8. Commitments and Contingencies

Firm Gas Transportation Agreements

The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. These agreements provide firm transportation capacity rights on pipeline systems primarily in

Index to Financial Statements

Canada, the West and East regions.North region. The remaining terms on these agreements range from less than one year to approximately 20 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability. The agreements that the Company previously had in place on pipeline systems in Canada were transferred in April 2009 to the buyer in connection with the sale of the Company’s Canadian properties (discussed in Note 2).

During 2010, the Company entered into new firm gas transportation arrangements with third-party pipelines to transport approximately 296 Mmcf/day in the North region. One of the new agreements commenced in the second quarter of 2010 and the remaining new agreements are expected to commence in 2011, which includes the 20 year transportation agreement entered into with Williams in December 2010 (discussed in to Note 2). These new agreements have terms of five to twenty years from the respective commencement dates. Future obligations under firm gas transportation agreements which commenced during 2010 are $78.4 million as of December 31, 2010.

Future obligations under firm gas transportation agreements in effect atas of December 31, 20082010 are as follows:

 

  (In thousands)

2009

  $13,218

2010

   12,335

(In thousands)

    

2011

   11,600  $32,504  

2012

   10,024   35,684  

2013

   3,350   28,356  

2014

   28,356  

2015

   28,356  

Thereafter

   44,143   332,363  
       
  $94,670  $485,619  
       

Drilling Rig Commitments

The Company has eight drilling rigs in the Gulf Coast that are under contracts with initial terms of greater than one year. As of December 31, 2008,2010, the Company is obligated under these contracts to pay $44.3 million over the next two years as follows:does not have any outstanding drilling commitments with initial terms greater than one year.

    (In thousands)

2009

  $42,021

2010

   2,250
    
  $44,271
    

Lease Commitments

The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. The lease for the Company’s existing office in Houston expires in 2009. During 2008, the Company entered into a lease for new office space in Houston. The new lease will commence in August 2009 and will expire approximately six years from commencement. All other operating leases expire within the next five years, and some of these leases may be renewed. Rent expense under suchthese arrangements totaled $14.6$18.3 million, $12.3$17.4 million and $10.7$14.6 million for the years ended December 31, 2010, 2009 and 2008, 2007 and 2006, respectively.

- 85 -


Future minimum rental commitments under non-cancelable leases in effect at December 31, 20082010 are as follows:

 

    (In thousands)

2009

  $6,335

2010

   4,859

2011

   4,169

2012

   3,863

2013

   3,534

Thereafter

   5,926
    
  $28,686
    

Index to Financial Statements

(In thousands)

    

2011

   5,414  

2012

   5,133  

2013

   4,769  

2014

   4,211  

2015

   2,631  

Thereafter

   —    
     
  $22,158  
     

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of its business. When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities are accrued based on management’s best estimatean estimation process that includes the advice of the potential loss.legal counsel and subjective judgment of management. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.flows.

West Virginia Royalty LitigationEnvironmental Matters

In December 2001,On November 4, 2009, the Company was suedand the Pennsylvania Department of Environmental Protection (PaDEP) entered into a single settlement agreement (Consent Order) covering a number of separate, unrelated environmental issues occurring in 2008 and 2009, including releases of drilling mud and other substances, record keeping violations at various wells and alleged natural gas contamination of 13 water wells in Susquehanna County, Pennsylvania. The Company paid an aggregate $120,000 civil penalty with respect to all the matters covered by two royalty owners in West Virginia state court for an unspecified amountthe Consent Order, which were consolidated at the request of damages. The plaintiffs requested class certificationthe PaDEP.

On April 15, 2010, the Company and allegedPaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, PaDEP and the Company agreed that the Company failedwill provide a permanent source of potable water to pay royalty based upon14 households, most of which the wholesale market valueCompany has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the gas, thathouseholds and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company had taken improper deductions fromagreed to take certain other actions if requested by PaDEP, which could include the royaltyplugging and that it failedabandonment of up to properly inform royalty owners of10 additional wells. Under the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings. The Court entered an order on June 1, 2005 granting the motion for class certification.

The parties reached a tentative settlement pursuant to whichFirst Modified Consent Order, the Company paid a total$240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

On July 19, 2010, the Company and the PaDEP entered a Second Modification to Consent Order (Second Modified Consent Order) under which the Company and the PaDEP agreed that the Company has satisfactorily plugged and abandoned the three vertical wells and brought the fourth well into compliance. As a result, the Company and the PaDEP agreed that the PaDEP will commence the processing and issuance of $12.0new well drilling permits outside the area of concern so long as the Company continues to provide temporary potable water and offers to provide gas/water separators to the 14 households. No penalties were assessed under the Second Modified Consent Order.

- 86 -


As required by the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to the 14 households. As required by the First Modified Consent Order, on August 5, 2010 the Company filed with the PaDEP its report, prepared by its experts, finding that the Company’s well drilling and development activities are not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

Despite the Company’s vigorous efforts to comply with the various consent orders, in a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and determined that the Company’s drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company, in accordance with the First Modified Consent Order, to plug or take other remedial actions at the remaining 10 wells and to contact the PaDEP to discuss connecting the impacted water supplies into a community public water system to permanently eliminate the continuing adverse affect to those water supplies.

The Company believed that it was in full compliance with the various consent orders. In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. It was the Company’s position that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company’s obligations under these consent orders.

On December 15, 2010, the Company entered a global settlement agreement and new consent order with the PaDEP (Global Settlement Agreement), which supersedes the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the Global Settlement Agreement, among other things, the Company agreed to pay $4.2 million into a trust fundseparate escrow accounts for disbursementthe benefit of each affected household, pay $500,000 to the class members upon final approval ofPaDEP to reimburse the settlement byPaDEP for its costs, remediate two wells in the Court. The court held the final fairness hearing on February 12, 2008affected area, provide pressure, water quality and approved the settlement, authorized the distribution of the fundswell headspace data to the class membersPaDEP and dismissedoffer water treatment to the affected households. The Global Settlement Agreement settles all outstanding issues and claims that are known and that could have been brought against the Company with prejudice. These funds were disbursed in April 2008. Priorby the PaDEP relating to the datewells in the affected area and the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to begin hydraulic fracturing in the affected areas after providing the PaDEP with well pressure data and to commence drilling new wells in the affected area in the second quarter of 2011. Under the Global Settlement Agreement, the Company has no obligation to connect the impacted water supplies to a community public water system.

On January 11, 2011, certain of the Court’s final order approvingaffected households appealed the settlement, these restricted cash funds were held by a financial institutionGlobal Settlement Agreement to the Pennsylvania Environmental Hearing Board. A hearing on the merits of this appeal is not expected to occur until 2012.

As of December 31, 2010, the Company has paid $1.3 million in West Virginia underfines and penalties to the joint custodyPaDEP paid $0.6 million to two of the plaintiffsaffected households and the Company. The Company had providedaccrued a reserve sufficient$3.6 million settlement liability related to cover the amount agreed upon to settle this litigation. As of June 30, 2008, these funds had been paid out to the class members or were controlled by the Court. Accordingly, the Company had reducedmatter which is included in Other Current AssetsLiabilities in the Consolidated Balance Sheet. In the settlement, the Company and the class members also agreed to a methodology for payment of future royalties and the reporting format such methodology will take.

Commitment and Contingency Reserves

When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur approximately $2.1 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position or cash flow of the Company. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Settlement of Dispute

In December 2008, the Company settled a dispute with a third party resulting in the Company’sCompany recording a gain of $51.9 million,million. The dispute involved the propriety of possession of the Company’s intellectual property by a third party. The settlement was comprised of $20.2 million in cash paid by the third party to the Company and $31.7 million related to the fair value of unproved property rights received.transferred by the third party to the Company. The fair market value of the unproved property rights was determined based on observable market costs and conditions over a recent time period. Values were pro-rated by property based on the primary term remaining on the properties.

Index

- 87 -


9. Asset Retirement Obligation

The following table provides a rollforward of the asset retirement obligation. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Liabilities incurred include additions to Financial Statements

obligations as well as obligations that were assumed by the Company related to acquired properties. Activity related to the Company’s asset retirement obligation during the year ended December 31, 2010 is as follows:

(In thousands)

    

Carrying amount of asset retirement obligation at December 31, 2009

  $29,676  

Change in estimate

   40,443  

Liabilities incurred

   966  

Liabilities settled

   (693

Accretion expense

   1,919  
     

Carrying amount of asset retirement obligation at December 31, 2010

  $72,311  
     

The change in estimate during 2010 is attributable to additional regulatory requirements in east Texas and increased costs for services and equipment to plug and abandon wells in all of our areas of operations.

Accretion expense for the years ended December 31, 2010, 2009 and 2008 was $1.9 million, $1.3 million and $1.2 million, respectively.

8.10. Supplemental Cash Flow Information

Cash paid / (received) for interest and income taxes is as follows:

 

  Year Ended December 31,  Year Ended December 31, 
  2008 2007 2006
  (In thousands)

(In thousands)

  2010 2009   2008 

Interest

  $23,089  $20,257  $24,088  $64,342   $56,301    $23,089  

Income Taxes

   (33,753)  (20,099)  128,752   (1,050  27,080     (33,753

9.11. Capital Stock

Incentive Plans

Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards. In the first quarter of 2007, the Board of Directors eliminated the automatic award of an option to purchase 30,000 shares of common stock on the date the non-employee directors first join the Board of Directors. In its place, the Board of Directors considers an annual fixed dollar stock award which is competitive with the Company’s peer group. A total of 5,100,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 1,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 3,000,000 shares may be issued pursuant to incentive stock options.

Stock Issuance

On June 20, 2008, the Company entered into an underwriting agreement, pursuant to which the Company sold an aggregate of 5,002,500 shares of common stock at a price to the Company of $62.66 per share. This aggregate share amount included 652,500 shares of common stock that were issued as a result of the exercise of the underwriters’ option to purchase additional shares. On June 25, 2008, the Company closed the public offering and received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used temporarily to reduce outstanding

- 88 -


borrowings under the Company’s revolving credit facility prior to funding a portion of the purchase price of the Company’s east Texas acquisition, which closed in the third quarter of 2008.

Immediately prior to (and in connection with) this issuance, the Company retired 5,002,500 shares of its treasury stock, which had a weighted-average purchase price of $16.46, representing $82.3 million. In accordance with the Company’s policy, the excess of cost of the treasury stock over its par value was charged entirely to additional paid-in capital.

Stock Split

On February 23, 2007, the Board of Directors declared a 2-for-1 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 30, 2007 to stockholders of record on March 16, 2007. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company’s common stock.

Increase in Authorized Shares

On May 4, 2006,In April 2009, the stockholders of the Company approved an increase in the authorized number of shares of common stock from 80120 million to 120240 million shares. The Company correspondingly increased the number of shares of Series A Junior Participating Preferred Stock reserved for issuance from 800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to the Preferred Stock Purchase Rights Plan described below.

Index to Financial Statements

Treasury Stock

The Board of Directors has authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company.

During the year ended December 31, 2008,2010, the Company did not repurchase any shares of common stock. Since the authorization date, the Company has repurchased 5,204,700 shares or 52% of the 10 million total shares authorized for repurchase at December 31, 2008, for a total cost of approximately $85.7 million. The repurchased shares were held as treasury stock. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. In connection with the June 2008 common stock issuance, the Company retired 5,002,500 shares of its treasury stock as discussed above under the heading “Stock Issuance.” As of December 31, 2010, 202,200 shares were held as treasury stock.

Dividend Restrictions

The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the common stock depending on, among other things, the Company’s financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision or other provision limiting dividends.

Expired Purchase Rights Plan

On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of common stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. Each right becomes exercisable when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15% or more of the Company’s outstanding common stock. Each right entitles the holder, other than the acquiring person or group, to purchase a fraction of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock). After a person or group acquires beneficial ownership of 15% of the common stock, each right entitles the holder to purchase common stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of common stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of Directors may opt to exchange one share of common stock for each exercisable right. If there is a 15% holder and the Company is acquired in a merger or other business combination in which it is not the survivor, or 50% or more of the Company’s assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 20082010 and 2009 there were no shares of Junior Preferred Stock issued or outstanding.

The rights expireplan expired on January 21, 2010, and may be redeemed by the Company at any time before a person or group acquires beneficial ownership of 15% of the common stock.2010.

As a result of stock splits in 2005 and 2007, each share of common stock continues to include one right under the Company’s Preferred Stock Purchase Rights Plan, and each right now provides for the purchase, upon the occurrence of the conditions set forth in the plan, of one-third of one one-hundredth of a share of preferred stock at a purchase price of approximately $18.33 per one-third of one one-hundredth of a share (or $55 for each one one-hundredth of a share). The redemption price of each right is now one-third of a cent.

Index to Financial Statements

10.12. Stock-Based Compensation

Adoption of SFAS No. 123(R)

Beginning January 1, 2006, the Company began accounting for stock-based compensation under SFAS No. 123(R), which applies to new awards and to awards modified, repurchased or cancelled after December 31, 2005. The Company recorded compensation expense based on the fair value of awards as described below.

Compensation expense charged against income for stock-based awards (including the supplemental employee incentive plans discussed below)plan) for the years ended December 31, 2010, 2009 and 2008 2007was $14.4 million, $25.1 million and 2006 was $34.5 million, $15.3 million and $21.2 million, pre-tax, respectively, and is included in General and Administrative Expense in the Consolidated Statement of Operations.

The $0.6 Company did not recognize a tax benefit related to stock-based compensation in 2010 as a result of the tax net operating loss position for the year. For the year ended December 31, 2009, the Company realized a $13.8

- 89 -


million ($0.4 million,tax benefit related primarily to the federal tax deduction in excess of book compensation cost for employee stock-based compensation for 2008 and, to a lesser extent, state tax deductions for 2007. For regular federal income tax purposes, the Company was in a net of tax) cumulative effect charge at adoption thatoperating loss position in 2008. As the Company carried back net operating losses concurrent with its 2008 tax return filing, the income tax benefit related to stock-based compensation was recorded in 2009. In accordance with ASC 718, the first quarter of 2006 was due primarilyCompany is able to recognize this tax benefit only to the recording of the liability component ofextent it reduces the Company’s performance share awards at fair value, rather than intrinsic value.

income taxes payable. For the year ended December 31, 2008, the Company realized a $10.7 million tax benefit related to the 2007 federal tax deduction in excess of book compensation cost related to employee stock-based compensation. In accordance with SFAS No. 123(R), the Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable. Such income tax benefit related to the stock-based compensation was recorded in 2008 as the Company carried back net operating losses concurrent with the 2007 tax return filing. For regular tax purposes, the Company was in a net operating loss position in 2008; thus the entire tax benefit related to 2008 employee stock-based compensation will be recorded only when the tax net operating loss is utilized to reduce income taxes payable or claim a refund of taxes paid in prior years. The Company did not recognize a tax benefit related to stock-based compensation in 2007 as a result of the tax net operating loss position for the year under the Alternative Minimum Tax system. A benefit of $9.5 million was recorded for the year ended December 31, 2006 for tax deductions taken due to employee stock option exercises and restricted stock grant vesting.year. Under SFAS No. 123(R),ASC 718, the tax benefits resulting from tax deductions in excess of expense are reported as an operating cash outflow and a financing cash inflow. For the years ended December 31, 2010, 2009 and 2008, and 2006, $10.7$0.1 million, $13.8 million and $9.5$10.7 million were reported in these two separate line items in the Consolidated Statement of Cash Flows.

During the third quarter of 2006, the Company adopted the provisions outlined under FSP FAS No. 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which discusses accounting for taxes for stock awards using the APIC Pool concept. The Company was not required to adopt this provision until January 1, 2007, one year from the adoption of 123(R); however, it chose early adoption. The Company made a one time election as prescribed under the FSP to use the shortcut approach to derive the initial windfall tax benefit pool. The Company chose to use a one-pool approach which combines all awards granted to employees, including non-employee directors.

Restricted Stock Awards

Most restricted stock awards vest either at the end of a three year service period or on a graded-vesting basis of one-third at each anniversary date over a three or four year service period. Under the graded-vesting approach, the Company recognizes compensation cost over the three year requisite service period for each separately vesting tranche as though the awards are, in substance, multiple awards. For awards that vest at the end of the three year service period, expense is recognized ratably using a straight-line expensing approach over three years. A new award issued in 2008 partially vests atUnder the end of a onegraded-vesting approach, the Company recognizes compensation cost ratably over the three or four year requisite service period, withas applicable, for each separately vesting tranche as though the remainder vesting at the end of four years.awards are, in substance, multiple awards. For all restricted stock awards, vesting is dependantdependent upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or retirement.

The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is four years. In accordance with SFAS No. 123(R),ASC 718, the Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation

Index to Financial Statements

expense in accordance with the vesting provisions of the Company’s stock-based compensation programs for awards issued after the adoption of SFAS No. 123(R).ASC 718. The Company used an annual forfeiture rate ranging from 0% to 7.2%7.0% based on approximately ten years of the Company’s history for this type of award to various employee groups.

The following table is a summary of restricted stock award activity for the year ended December 31, 2008:2010:

 

Restricted Stock Awards

  Shares Weighted-
Average
Grant
Date Fair
Value per
share
  Weighted-
Average
Remaining
Contractual
Term
(in years)
  Aggregate
Intrinsic Value
(in thousands)(1)
  Shares Weighted-
Average Grant
Date Fair Value
per Share
   Weighted-
Average
Remaining
Contractual
Term (in years)
   Aggregate
Intrinsic Value
(in thousands)(1)
 

Non-vested shares outstanding at December 31, 2007

  483,494  $18.44    

Outstanding at December 31, 2009

   185,923   $34.62      

Granted

  13,000   40.93       23,800    34.87      

Vested

  (400,454)  16.24       (46,350  32.61      

Forfeited

  (5,100)  25.94       (31,210  33.93      
                  

Non-vested shares outstanding at December 31, 2008

  90,940  $30.92  2.3  $2,364

Non-vested shares outstanding at December 31, 2010

   132,163   $35.53     1.7    $5,002  
                           

 

(1)

The aggregate intrinsic value of restricted stock awards is calculated by multiplying the closing market price of the Company’s stock on December 31, 20082010 by the number of non-vested restricted stock awards outstanding.

As shown in the table above, there were 13,00023,800 shares of restricted stock granted to employees during 2008. Awards totaling 8,000 shares vest at the end2010 with a weighted-average grant date fair value per share of a one year service period, and awards totaling 5,000 shares vest at the end of a four year service period, both commencing in September 2008. This grant is amortized using a graded-vesting schedule.$34.87. During the year ended December 31, 2007, 51,9002009, 145,060 shares of restricted stock were granted to employees with a weighted-average grant date fair value per share of $32.92.$34.95. During 2006, 93,700the year ended December 31, 2008, 13,000 shares of restricted stock awards were granted to

- 90 -


employees with a weighted-average grant date fair value per share of $23.80.$40.93. The total fair value of shares vested during 2010, 2009 and 2008 2007 and 2006 was $6.5$1.5 million, $5.2$1.2 million and $5.0$6.5 million, respectively.

Compensation expense recorded for all unvested restricted stock awards for the years ended December 31, 2010, 2009 and 2008 2007 and 2006 was $1.5$1.8 million, $3.4$1.2 million and $6.1$1.5 million, respectively. Included in 2007 and 20062010 restricted stock expense was $0.1$1.1 million and $0.6 million, respectively related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 20082010 for all outstanding restricted stock awards was $1.2$2.1 million and will be recognized over the next 2.31.8 years.

Restricted Stock Units

Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are paid outissued when the director ceases to be a director of the Company. Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table below.

Index to Financial Statements

The following table is a summary of restricted stock unit activity for the year ended December 31, 2008:2010:

 

Restricted Stock Units

  Shares Weighted-
Average Grant
Date Fair
Value per
share
  Aggregate
Intrinsic Value
(in thousands)(1)
  Units   Weighted-
Average
Grant Date
Fair Value

per Unit
   Weighted-
Average
Remaining
Contractual
Term
(in years)(2)
   Aggregate
Intrinsic
Value
(in thousands)(1)
 

Outstanding at December 31, 2007

  85,052  $23.97  

Outstanding at December 31, 2009

   115,165    $26.86      

Granted and fully vested

  16,565   49.17     26,961     40.07      

Issued

  (19,602)  26.02     —       —        

Forfeited

  —     —       —       —        
                 

Outstanding at December 31, 2008

  82,015  $28.57  $2,132

Outstanding at December 31, 2010

   142,126    $29.37     —      $5,379  
                         

 

(1)

The intrinsic value of restricted stock units is calculated by multiplying the closing market price of the Company’s stock on December 31, 20082010 by the number of outstanding restricted stock units.

(2)

Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table below.

As shown in the table above, 16,565 restricted stock units were granted during 2008. During 2007, 24,65426,961 restricted stock units were granted with a weighted-average grant date fair value per share of $35.49.$40.07 during 2010. During 2006, 34,4402009, 33,150 restricted stock units were granted with a weighted-average grant date fair value per share of $25.41.$22.63. During 2008, 16,565 restricted stock units were granted with a weighted-average grant date fair value per share of $49.17.

The compensation cost, which reflects the total fair value of these units, recorded in 20082010 was $0.8$1.1 million. Compensation expense recorded during the years ended December 31, 20072009 and 20062008 for restricted stock units was $0.9$0.8 million for both years.and $0.8 million, respectively.

Stock Options

Stock option awards are granted with an exercise price equal to the market price (defined as the average of the high and low trading pricesprice of the Company’s stock at the date of grant) of the Company’s stock on the date of grant. During the years ended December 31, 20082010, 2009 and 2007,2008, there were no stock options granted. During 2006, 60,000

The Company uses a Black-Scholes model to calculate the fair value of stock options, with an exercise price of $23.80 per share, were granted to two incoming non-employee directors of the Company in the first quarter of 2006.

options. Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with

- 91 -


one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options granted to directors due to the forfeiture rate history for these types of awards for this group of individuals. During 2010 there was no compensation expense recorded. Compensation expense recorded during 2008, 2007 and 2006 for these stock options for 2009 was $0.1 million,less than $0.1 million and $0.3 million, respectively. Unamortizedfor 2008 was $0.1 million. There was no unamortized expense as of December 31, 20082010 for all outstanding stock options.

The following table is a summary of stock option activity for the years ended December 31, 2010, 2009 and 2008:

   2010   2009   2008 

Stock Options

  Shares  Weighted-
Average
Exercise
Price
   Shares  Weighted-
Average
Exercise
Price
   Shares  Weighted-
Average
Exercise
Price
 

Outstanding at Beginning of Year

   50,000   $23.80     60,500   $21.69     388,950   $10.38  

Granted

   —        —      —       —      —    

Exercised

   (35,000  23.80     (10,500  11.66     (328,450  8.30  

Forfeited or Expired

   —      —       —      —       —      —    
                  

Outstanding at December 31(1)

   15,000   $23.80     50,000   $23.80     60,500   $21.69  
                           

Options Exercisable at December 31(2)

   15,000   $23.80     50,000   $23.80     40,500   $20.65  
                           

(1)

The intrinsic value of a stock option is the amount which the current market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of options outstanding at December 31, 2010 was $0.2 million. The weighted-average remaining contractual term is less than one year.

(2)

The aggregate intrinsic value of options exercisable at December 31, 2010 was $0.2 million. The weighted-average remaining contractual term is less than one year.

The total intrinsic value of options exercised during the years ended December 31, 2010, 2009 and 2008 was less than $0.5 million, $0.1 million. The weighted-average periodmillion and $12.2 million, respectively.

Stock Appreciation Rights

Beginning in 2006, the Compensation Committee has granted SARs to employees. These awards allow the employee to receive any intrinsic value over which this compensation will be recognized is approximately 0.2 years.

Index to Financial Statements

Thethe grant date market price that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. The Company calculates the fair value of a stock option is calculated by using a Black-Scholes model.

The assumptions used in the Black-Scholes fair value calculation on the date of grant for stock optionsSARs are as follows:

 

  Year Ended
December 31,
   Year Ended December 31, 
  2008  2007  2006   2010 2009 2008 

Weighted-Average Value per Option Granted

      

During the Period(1)

  $—    $—    $7.32 

Weighted-Average Value per Stock Appreciation Rights

    

Granted During the Period

  $18.96   $9.35   $15.18  

Assumptions

          

Stock Price Volatility

   —     —     31.5%   52.9  50.5  34.4

Risk Free Rate of Return

   —     —     4.6%   2.4  1.7  2.8

Expected Dividend

   —     —     0.3%

Expected Dividend Yield

   0.3  0.5  0.2

Expected Term (in years)

   —     —     4.0    5.0    4.5    4.3  

 

(1)

Calculated using the Black-Scholes fair value based method.

- 92 -


The expected term was derived by reviewing minimum and maximum expected term outputs from the Black-Scholes model based on award type and employee type. This term represents the period of time that awards granted are expected to be outstanding. The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the USU.S. Treasury (Nominal 10) within the expected term as measured on the grant date. The expected dividend percentage assumes that the Company will continue to pay a consistent level of dividend each quarter.

The following table is a summary of stock option activity for the years ended December 31, 2008, 2007 and 2006:

   2008  2007  2006

Stock Options

  Shares  Weighted-
Average
Exercise
Price
  Shares  Weighted-
Average
Exercise
Price
  Shares  Weighted-
Average
Exercise
Price

Outstanding at Beginning of Year

  388,950  $10.38  1,007,950  $9.03  1,826,696  $7.66

Granted

  —     —    —     —    60,000   23.80

Exercised

  (328,450)  8.30  (619,000)  8.18  (876,946)  7.20

Forfeited or Expired

  —     —    —     —    (1,800)  9.10
               

Outstanding at December 31(1)

  60,500  $21.69  388,950  $10.38  1,007,950  $9.03
                     

Options Exercisable at December 31(2)

  40,500  $20.65  348,950  $8.84  947,950  $8.09
                     

(1)

The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of options outstanding at December 31, 2008 was $0.3 million. The weighted-average remaining contractual term is 1.8 years.

(2)

The aggregate intrinsic value of options exercisable at December 31, 2008 was $0.2 million. The weighted-average remaining contractual term is 1.7 years.

The total intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006 was $12.2 million, $19.9 million and $17.7 million, respectively.

Stock Appreciation Rights

Beginning in 2006, the Compensation Committee has granted SARs to employees. These awards allow the employee to receive any intrinsic value over the grant date market price that may result from the price

Index to Financial Statements

appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. As these SARs are paid out in stock, rather than in cash, the Company calculates the fair value in the same manner as stock options, by using a Black-Scholes model.

The assumptions used in the Black-Scholes fair value calculation for SARs are as follows:

   Year Ended December 31, 
   2008  2007  2006 

Weighted-Average Value per Stock Appreciation Right

    

Granted During the Period(1)

  $15.18  $11.26  $7.09 

Assumptions

    

Stock Price Volatility

   34.4%  32.6%  31.6%

Risk Free Rate of Return

   2.8%  4.6%  4.6%

Expected Dividend

   0.2%  0.2%  0.3%

Expected Term (in years)

   4.25   4.00   3.75 

(1)

Calculated using the Black-Scholes fair value based method.

These assumptions were derived using the same process as described in the “Stock Options” section above.

The following table is a summary of SAR activity for the years ended December 31, 2008, 20072010, 2009 and 2006:2008:

 

  2008  2007  2006  2010   2009   2008 

Stock Appreciation Rights

  Shares  Weighted-
Average
Exercise
Price
  Shares  Weighted-
Average
Exercise
Price
  Shares  Weighted-
Average
Exercise
Price
  Shares Weighted-
Average
Exercise
Price
   Shares Weighted-
Average
Exercise
Price
   Shares   Weighted-
Average
Exercise
Price
 

Outstanding at Beginning of Year

  372,800  $27.08  265,600  $23.80  —    $—     673,100   $29.27     491,930   $32.26     372,800    $27.08  

Granted

  119,130   48.48  107,200   35.22  265,600   23.80   79,550    40.53     221,780    22.63     119,130     48.48  

Exercised

  —     —    —     —    —     —     (17,000  27.16     (20,366  26.19     —       —    

Forfeited or Expired

  —     —    —     —    —     —     —        (20,244  32.19     —      
                               

Outstanding at December 31(1)

  491,930  $32.26  372,800  $27.08  265,600  $23.80   735,650   $30.54     673,100   $29.27     491,930    $32.26  
                                        

SARs Exercisable at December 31(2)

  212,790  $25.72  88,526  $23.80  —    $—  

Exercisable at December 31(2)

   532,222   $29.63     354,252   $28.58     212,790    $25.72  
                                        

 

(1)

The intrinsic value of a SAR is the amount by which the current market value of the underlying stock exceeds the exercise price of the SAR. The aggregate intrinsic value of SARs outstanding at December 31, 20082010 was $0.6$6.8 million. The weighted-average remaining contractual term is 4.93.5 years.

(2)

The aggregate intrinsic value of SARs exercisable at December 31, 20082010 was $0.4$5.3 million. The weighted-average remaining contractual term is 4.32.8 years.

As shown in the table above, the Compensation Committee granted 119,13079,550 SARs to employees during 20082010 with ana weighted-average exercise price equal to the grant date market price of $48.48. The grant date fair value of these SARs was $15.18 per share.$40.53. Compensation expense recorded during the years ended December 31, 2008, 20072010, 2009 and 20062008 for all outstanding SARs was $1.6 million, $1.8 million and $1.7 million, $1.5respectively. In 2010, there was no expense related to the immediate expensing of shares granted to retirement-eligible employees. Included in 2009 and 2008 expense was $0.7 million and $1.0$0.5 million, respectively. Included in both 2008 and 2007 expense was $0.5 millionrespectively, related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 20082010 for all outstanding SARs was $0.7$0.6 million. The weighted-average period over which this compensation will be recognized is approximately 1.91.1 years.

Index to Financial Statements

Performance Share Awards

During 2008,2010, the Compensation Committee granted three types of performance share awards to employees for a total of 383,065347,170 performance shares. TheFor all performance periodshare awards granted to employees in 2010, an annual forfeiture rate ranging from 0% to 7.0% has been assumed based on the Company’s history for twothis type of the three types of these awards commenced on January 1, 2008 and ends December 31, 2010. Both of these types of awards vest at the end of the three year performance period.award to various employee groups.

Awards totaling 101,830180,180 performance shares are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year performance period. The grant date per share value of the equity portion of this award was $41.53. Depending on the Company’s performance, employees may receive an aggregate of up to 100% of the fair market value of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash.

Awards totaling 191,400 performance shares were granted andconditions are earned, or not earned, based on the Company’s internal performance metrics rather than performance compared to a peer group. Asmetrics. Fair value is measured based on the average of December 31, 2008, 175,500 sharesthe high and low stock price of this award are outstanding.the Company on the grant date and expense is amortized straight-line over the three year period. The grant date per share value of this award was $48.48.$40.53. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three internal performance criteria set by the Company’s Compensation Committee. The performance period for the awards granted in 2010 commenced

- 93 -


on January 1, 2010 and ends December 31, 2012. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at December 31, 2008,2010, it is considered probable that these three criteria will be met.met for all outstanding awards.

The thirdsecond type of performance share award, totaling 89,83582,520 performance shares based on performance conditions, with a grant date per share value of $48.48,$40.53, has a three-year graded vesting schedule, vesting one-third on each anniversary date following the date of grant, provided that the Company has positive operating income for the year preceding the vesting date. If the Company does not have positive operating income for the year preceding a vesting date, then the portion of the performance shares that would have vested on that date will be forfeited. As of December 31, 2008, it is considered probable that this performance metric will be met.

For all awards granted to employees after January 1, 2006, an annual forfeiture rate ranging from 0% to 4.5% has been assumed based on the Company’s history for this type of award to various employee groups.

For awards that are based on the internal metrics (performance condition) of the Company and for awards that were granted prior to the adoption of SFAS No. 123(R) on January 1, 2006, fairperiod. Fair value is measured based on the average of the high and low stock price of the Company on the grant date and expense is amortized straight-line over the three year vesting period. On each anniversary date following the date of grant, one-third of the shares are issued, provided that the Company has $100 million or more of operating cash flow for the year preceding the performance period. If the Company does not have $100 million or more of operating cash flow for the year preceding a performance period, then the portion of the performance shares that would have been issued on that date will be forfeited. As of December 31, 2010, it is considered probable that this performance metric will be met.

Awards totaling 84,470 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year performance period. The performance period for the awards granted in 2010 commenced on January 1, 2010 and ends December 31, 2012. To determine the fair value for awards that were granted after January 1, 2006 that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components are bifurcated. On the grant date, the equity component was valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model. Depending on the Company’s performance, employees may receive an aggregate of up to 100% of the fair market value of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash.

The four primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns, correlation in movement of total shareholder return and the expected dividend. TheAn interpolated risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for onetwo and twothree year bonds and is(as of the reporting date) set equal to the yield, for the period over the remaining duration of the performance period, on treasury securities as of the reporting date.period. Volatility was set equal to the annualized daily volatility measured over a historic one and two yearfor the remaining duration of the performance period ending on the reporting date. Correlation in movement of total shareholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Company. The paired returns in the correlation matrix ranged from approximately 71%60.48% to approximately 89%85.65% for the Company and its peer group. The expected dividend is calculated using the total Company annual dividends expected to be paid ($0.12 for 2008) divided by the December 31, 2008 closing

Index to Financial Statements

price of the Company’s stock ($26.00).at the valuation date. Based on these inputs discussed above, a ranking was projected identifying the Company’s rank relative to the peer group for each award period.

The following assumptions were used as of December 31, 2008 for the Monte Carlo model to valuedetermine the liability componentsgrant date fair value of the peer group measuredequity component of the performance share awards. awards based on market conditions for the respective periods:

    Year Ended December 31, 
    2010  2009  2008 

Weighted-Average Fair Value per Performance Share

    

Award Granted During the Period

  $13.00   $17.63   $41.53  

Assumptions

    

Stock Price Volatility

   61.8  57.6  37.7

Risk Free Rate of Return

   1.4  1.3  1.7

Expected Dividend Yield

   0.3  0.5  0.2

- 94 -


The equity portion of the award was valued on the date of grant usingfollowing assumptions were used in the Monte Carlo model and this portion was not marked to market.

December 31,
2008

Risk Free Ratedetermine the fair value of Return

0.4% -   0.8%

Stock Price Volatility

61.8% - 81.9%

Expected Dividend

0.5%

The Monte Carlo value per share for the liability component for all outstanding market conditionof the performance share awards ranged from $9.84 to $17.42 at December 31, 2008. based on market conditions for the respective periods:

   December 31, 
   2010   2009 

Fair Value per Performance Share Award at the End of the Period

  $0.00 - $6.15    $14.38 - 16.24  

Assumptions

    

Stock Price Volatility

   70.7% - 71.7%     57.7% - 70.8%  

Risk Free Rate of Return

   0.3% - 0.4%     0.5% - 1.4%  

Expected Dividend Yield

   0.4%     0.3%  

The long-term liability for all market condition performance share awards, included in Other Liabilities in the Consolidated Balance Sheet, at December 31, 20082010 and 20072009 was $0.3$0.6 million and $0.2$1.1 million, respectively. The short-term liability, included in Accrued Liabilities in the Consolidated Balance Sheet, at December 31, 20082010 and 2007,2009 was 2.4 million for certain market condition performance share awards was $2.5 million and $5.5 million, respectively.both periods.

On December 31, 2008,2010, the performance period ended for two types of performance shares awarded in 2006,2008, including 155,800143,800 shares measured based on internal performance metrics of the Company and 105,80096,680 shares measured based on the Company’s performance against a peer group. For the internal performance metric awards, the calculation of the average of the three years of the Company’s three internal performance metrics was completed in the first quarter of 20092011 and was certified by the Compensation Committee in February 2009.2011. As the Company achieved the three internal performance metrics, 100% of the award, valued at $3.7$6.9 million based on the average of the high and low stock price on the grant date, was payable in 155,800143,800 shares of common stock. For the peer group awards, due to the ranking of the Company compared to its peers in its predetermined peer group, 100%75% of the award, valued at $1.7$3.0 million based on the Monte Carlo value on the grant date, was payable in 105,80072,512 shares of common stock and an additional 67%, equal to two-thirds of the total value of the award, calculated by using the high and low stock price on December 31, 2008 multiplied by the number of performance shares earned, or $1.8 million, was payable in cash. This cash amount was paid in January 2009. The calculation of the award payout was certified by the Compensation Committee on January 5, 2009.stock. The vesting of both types of shares discussed above will be reported in the first quarter of 2009.2011.

The following table is a summary of performance share award activity for the year ended December 31, 2008:2010:

 

Performance Share Awards

 Shares Weighted-Average
Grant Date Fair
Value per share(1)
 Weighted-Average
Remaining
Contractual Term
(in years)
 Aggregate
Intrinsic Value
(in thousands)(2)
  Shares Weighted-
Average Grant
Date Fair Value
per Share(1)
   Weighted-
Average
Remaining
Contractual
Term (in years)
   Aggregate
Intrinsic
Value (in
thousands)(2)
 

Non-vested shares outstanding at December 31, 2007

 867,700  $25.38  

Outstanding at December 31, 2009

   1,296,393   $29.74      

Granted

 383,065   46.63     347,170    38.48      

Vested

 (249,990)  18.55  

Issued and Fully Vested

   (410,269  32.28      

Forfeited

 (37,000)  36.60     (40,180  32.82      
               

Non-vested shares outstanding at December 31, 2008

 963,775  $35.17 1.6 $25,058

Outstanding at December 31, 2010

   1,193,114   $31.31     1.0    $45,159  
                        

 

(1)

The fair value figures in this table represent the fair value of the equity component of the performance share awards.

(2)

The aggregate intrinsic value of performance share awards is calculated by multiplying the closing market price of the Company’s stock on December 31, 20082010 by the number of non-vested performance share awards outstanding.

Index to Financial Statements

Of the performance shares that vested during 20082010 shown in the table above, 92,400 shares were granted in 2007. These shares (valued at $2.8 million) were measured based on the Company’s performance against a peer group and were issued in addition to cash of $1.3 million. A total of 150,100 shares (valued at $5.3 million) measured based on internal performance metrics of the Company were also issued. During 2010, 167,769

- 95 -


shares vested (valued at $5.1 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2009, 2008 and 2007 with a grant date per share value of $22.63, $48.48 and $35.22, respectively.

During the year ended December 31, 2009, 785,350 performance share awards were granted to employees with a weighted-average grant date fair value per share of $21.30. Of the 332,642 performance shares that vested during 2009, 105,800 shares were granted in 2006. These shares (valued at $1.7 million) were measured based on the Company’s performance against a peer group and were issued in addition to cash of $1.8 million. A total of 155,800 shares (valued at $3.8 million) measured based on internal performance metrics of the Company were also issued. During 2009, 60,740 shares vested (valued at $2.5 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2008 and 2007 with a grant date per share value of $48.48 and $35.22, respectively. In addition, 10,302 performance shares vested as a result of early vesting schedules for certain employees. These awards met the performance criteria that the Company had positive operating income for 2008 and 2007.

During the year ended December 31, 2008, 383,065 performance share awards were granted with a weighted-average grant date fair value per share of $46.63. Of the 249,990 performance shares that vested during 2008, 207,800 shares were granted in 2005 and were market condition awards which provided that employees may receive an aggregate of up to 100% of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash. As a result of the Company’s ranking on the vesting date, 100% of the shares were paid in common stock and an additional 67% of the fair market value of each share of common stock, or $7.9 million, was paid in cash during the second quarter of 2008. Another 30,790 shares vested during 2008 and represent one-third of the three-year graded vesting schedule performance share awards granted in 2007 with a grant date per share value of $35.22. These awards met the performance criteria that the Company had positive operating income for the 2007 year. The remaining 11,400 shares vested as a result of the death of an employee of the Company.

During the year ended December 31, 2007, 387,100 performance share awards were granted with a weighted-average grant date fair value per share of $34.08. During the year ended December 31, 2006, 285,500 performance share awards were granted with a weighted-average grant date fair value per share of $21.07. During the year ended December 31, 2007, 450,000 performance shares vested related to the performance period commencing on January 1, 20042010, 2009 and ending on December 31, 2007. During the year ended December 31, 2006, 30,600 performance shares vested as a result of the death of one of the Company’s officers. During 20072008, 40,180, 120,090 and 2006, 9,500 and 7,10037,000 performance shares, respectively, were forfeited.

Total unamortized compensation cost related to the equity component of performance shares at December 31, 20082010 was $13.5$11.5 million and will be recognized over the next 1.61.9 years, computed by using the weighted-average of the time in years remaining to recognize unamortized expense. Total compensation cost recognized for both the equity (including the cumulative effect) and liability components of all performance share awards during the years ended December 31, 2010, 2009 and 2008 2007 and 2006 was $14.5$12.4 million, $9.4$15.6 million and $12.9$17.5 million, respectively.

Deferred Performance Shares

As of December 31, 2010, 174,318 shares of the Company’s common stock representing vested performance share awards were deferred into the Rabbi Trust Deferred Compensation Plan. A total of 51,482 shares were sold out of the plan in 2010. During 2010, an increase to the rabbi trust deferred compensation liability of $2.5 million was recognized, representing the increase in the investment excluding the Company’s common stock, offset by the decrease in the closing price of the Company’s common stock from December 31, 2009 to December 31, 2010 and the reduction in the liability due to shares that were sold out of the rabbi trust. This increase in stock-based compensation expense was included in General and Administrative expense in the Consolidated Statement of Operations.

Supplemental Employee Incentive Plans

On January 16, 2008, the Company’s Board of Directors adopted a Supplemental Employee Incentive Plan. The plan was intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price.

- 96 -


The bonus payout was triggered if, for any 20 trading days (which need not be consecutive) that fell within a period of 60 consecutive trading days occurring on or before November 1, 2011, the closing price per share of the Company’s common stock equaled or exceeded the price goal of $60 per share. In such event, the 20th trading day on which such price condition was attained is the “Final Trigger Date.” Under the plan, each eligible employee would receive a minimum distribution of 50% of his or her base salary as of the Final Trigger Date, as adjusted for persons hired after December 31, 2007 to reflect calendar quarters of service, reduced by any interim distribution previously paid to such employee upon the achievement of the interim price goal discussed below. The Committee was authorized, in its discretion, to allocate to eligible employees additional distributions, subject to limitations of the plan.

The plan also provided that an interim distribution would be paid to eligible employees upon achieving the interim price goal of $50 per share prior to December 31, 2009. Interim distributions were determined as described above except that interim distributions were based on 10%, rather than 50%, of salary.

On the January 16, 2008 adoption date of the plan, the Company’s closing stock price was $40.71. On April 8, 2008 and subsequently on June 2, 2008, the Company achieved the interim and final target goals and total distributions of $15.7 million were paid in 2009. No further distributions will be made under this plan.

Index to Financial Statements

On July 24, 2008, the Company’s Board of Directors adopted a second Supplemental Employee Incentive Plan (“Plan II”). Plan II is also intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price.

Plan II provides for a final payout if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days ending on or before June 20, 2012, the closing price per share of the Company’s common stock equals or exceeds the price goal of $105 per share. In such event, the 20th trading day on which such price condition is attained is the “Final Trigger Date.” The price goal is subject to adjustment by the Compensation Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders. Under Plan II, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 50% of his or her base salary as of the Final Trigger Date (or 30% of base salary if the Company paid interim distributions upon the achievement of the interim price goal discussed below).

Plan II provides that a distribution of 20% of an eligible employee’s base salary as of the Interim Trigger Date will be made (upon approval by the Compensation Committee) upon achieving the interim price goal of $85 per share on or before June 30, 2010. The Company did not meet this interim trigger and therefore no distribution was made as of the Interim distributions are determined as described above except that interim distributions will be based on 20%, rather than 50%, of salary. The Compensation Committee can increase the 50% or 20% payment as it applies to any employee.Trigger Date.

Payments under either the interim or final distribution will occur as follows:

 

 

 

25% of the total distribution paid on the 15th business day following the interim or final trigger date, as applicable,date; and

 

75% of the total distribution paid based on the following deferred payment dates in the table below:

 

Period During which the Trigger Date Occurs

  

Deferred Payment Date

July 1, 2008 to June 30, 2009

  The business day on or next following the 18 month anniversary of the applicable Trigger Date

July 1, 2009 to June 30, 2010

  The business day on or next following the 12 month anniversary of the applicable Trigger Date

July 1, 2010 to December 31, 2010

  The business day on or next following the 6 month anniversary of the applicable Trigger Date

January 1, 2011 to June 30, 2012

  No deferral; entire payment is made on the 15th business day following the applicable Trigger Date

- 97 -


Any deferred portion will only be paid if the participant is employed by the Company, or has terminated employment by reason of retirement, death or disability (as provided in Plan II). Payments are subject to certain other restrictions contained in Plan II.

These awards under both plans discussed above have been accounted for as liability awards under SFAS No. 123(R),ASC 718. The Company recognized a benefit of $0.9 million for 2010 and expense of $1.2 million for 2009, which is included in General and Administrative Expense in the Consolidated Statement of Operations.

13. Derivative Instruments and Hedging Activities

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. As of December 31, 2010, the Company had 11 derivative contracts open: four natural gas price swap arrangements, six natural gas basis swaps arrangements and one crude oil collar arrangement. During 2010, the Company entered into six new derivative contracts covering anticipated crude oil production for 2010 and natural gas and crude oil production for 2011.

As of December 31, 2010, the Company had the following outstanding commodity derivatives:

Commodity and Derivative Type

Weighted-Average
Contract Price

Volume

Contract Period

Derivatives Designated as Hedging Instruments

Natural Gas Swaps

$6.24 per Mcf12,909 MmcfJanuary - December 2011

Crude Oil Collars

$93.25 Ceiling / $80.00 Floor per Bbl365 MbblJanuary - December 2011

Derivatives Not Designated as Hedging Instruments

Natural Gas Basis Swaps

$(0.27) per Mcf16,123 MmcfJanuary - December 2012

The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated Other Comprehensive Income in Stockholders’ Equity in the Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges, and the total expensechange in fair value of derivatives not designated as hedges, are recorded currently in earnings as a component of Natural Gas Revenue and Crude Oil and Condensate Revenue, as appropriate, in the Consolidated Statement of Operations.

- 98 -


The following schedules reflect the fair value of derivative instruments on the Company’s consolidated financial statements:

Effect of Derivative Instruments on the Consolidated Balance Sheet

      Fair Value Asset (Liability) 

(In thousands)

  

Balance Sheet Location

  December 31,
2010
  December 31,
2009
 

Derivatives Designated as Hedging
Instruments

     

Natural Gas Commodity Contracts

  Derivative Contracts (current assets)  $18,669   $99,151  

Crude Oil Commodity Contracts

  Derivative Contracts (current assets)   —      15,535  

Natural Gas Commodity Contracts

  Accrued Liabilities   —      (425

Crude Oil Commodity Contracts

  Derivative Contracts (current assets)   (1,743  —    
           
     16,926    114,261  

Derivatives Not Designated as Hedging
Instruments

     

Natural Gas Commodity Contracts

  Other Liabilities   (2,180  (1,954
           
    $14,746   $112,307  
           

At December 31, 2010 and 2009, unrealized gains of $16.9 million ($10.5 million, net of tax) and $114.3 million ($71.9 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income. Based upon estimates at December 31, 2010, the Company expects to reclassify $10.5 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income to the Consolidated Statement of Operations over the next 12 months.

Effect of Derivative Instruments on the Consolidated Statement of Operations

Derivatives Designated as
Hedging Instruments
(In thousands)

 Amount of Gain (Loss)
Recognized in OCI on Derivative
(Effective Portion)
   

Location of Gain (Loss)
Reclassified from
Accumulated OCI into
Income
(In thousands)

 Amount of Gain (Loss)
Reclassified from Accumulated
OCI into Income (Effective
Portion)
 
 Twelve Months Ended
December 31,
    Twelve Months Ended
December 31,
 
 2010  2009  2008    2010  2009  2008 

Natural Gas Commodity

        

Contracts

 $74,903   $161,330   $314,738    

Natural Gas Revenues

 $154,960   $371,915   $17,972  

Crude Oil Contracts

  752    (7,244  46,213    

Crude Oil and Condensate Revenues

  18,030    23,112    (4,951
                          
 $75,655   $154,086   $360,951     $172,990   $395,027   $13,021  
                          

For the years ended December 31, 2010, 2009 and 2008, respectively, there was no ineffectiveness recorded in our Consolidated Statement of Operations related to our derivative instruments.

Derivatives Not Designated as Hedging
Instruments
  Location of Gain  (Loss)
Recognized in Income on
Derivative
  Twelve Months Ended
December 31,
 

(In thousands)

    2010  2009  2008 

Natural Gas Commodity Contracts

  Natural Gas Revenues  $(226 $(1,954 $—    

- 99 -


Additional Disclosures about Derivative Instruments and Hedging Activities

The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligation under the agreement. The Company enters into derivative contracts with multiple counterparties in order to limit its exposure to individual counterparties. The Company also has netting arrangements with all of its counterparties that allow it to offset payables against receivables from separate derivative contracts with that counterparty.

The counterparties to the Company’s derivative instruments are also lenders under its credit facility. The Company’s credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of its derivative liability in certain situations.

14. Fair Value Measurements

Effective January 1, 2009, the Company applied all of the provisions of ASC 820 and there was not a material impact on the Company’s financial statements except for 2008 was $15.9 million.

11. Financial Instruments

Adoptionthe Company’s impairment of SFAS No. 157

In September 2006,oil and gas properties. The Company previously adopted the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for measuring fair values ofguidance as it relates to financial assets and liabilities in financial statements that are already required by United States generally accepted accounting principles to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement (CON) No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. SFAS

Index to Financial Statements

No. 157 ison a recurring basis effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which granted a one year deferral (to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years) for certain non-financial assets and liabilities to comply with SFAS No. 157. The Company adopted the provisions of FAS No. 157 covered under FSP No. 157-2 on January 1, 2009. The Company is currently evaluating2008. In the future, areas that could cause an impact of implementation with respect to nonfinancial assets and liabilities measured on a nonrecurring basis on its consolidated financial statements, which willwould primarily be limited to asset impairments, including goodwill, other long-lived assets, asset retirement obligations and assets acquired and liabilities assumed in a business combination, if any. Additionally, in February 2008, the FASB issued FSP No. FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which amends SFAS No. 157 to exclude SFAS No. 13 and related pronouncements that address fair value measurements for purposes of lease classification and measurement. FSP No. FAS 157-1 is effective upon the initial adoption of SFAS No. 157. The Company has adopted SFAS No. 157 and FSP No. FAS 157-1 discussed above, and there was no impact on its financial position or results of operations for the year ended December 31, 2008.

In October 2008, the FASB issued FSP No. FAS 157-3, “Estimating the Fair Value of a Financial Asset in a Market That Is Not Active” to amend SFAS No. 157 to provide guidance regarding how to determine the fair value of a financial asset when there is no active market for the asset at the measurement date. FSP No. FAS 157-3 clarifies how management’s internal assumptions, such as internal cash flow and discount rate assumptions, should be considered in measuring fair value when observable data are not present. In addition, observable market information from an inactive market should be considered to determine fair value, and it is inappropriate to conclude that all market activity represents forced liquidations or distressed sales or to conclude that any transaction price can determine fair value. The use of broker quotes and pricing services should also be considered to assess the relevance of observable and unobservable data. When valuing financial assets, significant judgment is required. FSP No. FAS 157-3 was effective upon issuance and has been considered in conjunction with the Company’s 2008 financial reporting and results; there was no material impact on the Company’s financial position or results of operations for the year ended December 31, 2008.

As defined in SFAS No. 157,ASC 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The valuation techniques that can be used under SFAS No. 157ASC 820 are the market approach, income approach or cost approach. The market approach uses prices and other information for market transactions involving identical or comparable assets or liabilities, such as matrix pricing. The income approach uses valuation techniques to convert future amounts to a single discounted present value amount based on current market conditions about those future amounts, such as present value techniques, option pricing models (i.e. Black-Scholes model) and binomial models (i.e. Monte-Carlo model). The cost approach is based on current replacement cost to replace an asset.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. SFAS No. 157ASC 820 establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to levelLevel 1 measurements and the lowest priority to levelLevel 3 measurements, and accordingly, levelLevel 1 measurements should be used whenever possible.

Index to Financial Statements

The three levels of the fair value hierarchy as defined by SFAS No. 157ASC 820 are as follows:

 

Level 1: Valuations utilizing quoted, unadjusted prices for identical assets or liabilities in active markets that the Company has the ability to access. This is the most reliable evidence of fair value and does not require a significant degree of judgment. Examples include exchange-traded derivatives and listed equities that are actively traded.

 

Level 2: Valuations utilizing quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability. Financial instruments that are valued using models or other valuation methodologies are included. Models used should primarily be industry-standard models that consider various assumptions and economic measures, such as interest rates, yield curves, time value, volatilities, contract terms, current market prices, credit risk or other market-corroborated inputs. Examples include most over-the-counter derivatives (non-exchange traded), physical commodities, most structured notes and municipal and corporate bonds.

- 100 -


the full term of the asset or liability. Financial instruments that are valued using models or other valuation methodologies are included. Models used should primarily be industry-standard models that consider various assumptions and economic measures, such as interest rates, yield curves, time value, volatilities, contract terms, current market prices, credit risk or other market-corroborated inputs. Examples include most over-the-counter derivatives (non-exchange traded), physical commodities, most structured notes and municipal and corporate bonds.

 

Level 3: Valuations utilizing significant, unobservable inputs. This provides the least objective evidence of fair value and requires a significant degree of judgment. Inputs may be used with internally developed methodologies and should reflect an entity’s assumptions using the best information available about the assumptions that market participants would use in pricing an asset or liability. Examples include certain corporate loans, real-estate and private equity investments and long-dated or complex over-the-counter derivatives.

Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under SFAS No. 157,ASC 820, the lowest level that contains significant inputs used in valuation should be chosen. Per SFAS No. 157,In accordance with ASC 820, the Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets, at fair valuesvalue on a nonrecurring basis. During the year ended December 31, 2010, the Company recorded impairment charges related to certain assets. Refer to Note 2 for additional disclosures related to fair value associated with the impaired assets. As none of the Company’s natural gasother non-financial assets and crude oil price collarsliabilities were impaired as of December 31, 2010 and swaps2009 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.

Financial Assets and Liabilities

Our financial assets and liabilities are designated as Level 3.

measured at fair value on a recurring basis. The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2008:2010 and 2009:

 

  Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
  Significant
Other
Observable
Inputs
(Level 2)
  Significant
Unobservable
Inputs
(Level 3)
  Balance as of
December 31,
2008
  (In thousands)

(In thousands)

  Quoted Prices
in Active
Markets for
Identical Assets
(Level  1)
   Significant
Other
Observable
Inputs
(Level 2)
   Significant
Unobservable
Inputs
(Level 3)
 Balance as of
December 31,
2010
 

Assets

               

Rabbi Trust Deferred Compensation Plan

  $8,651  $—    $—    $8,651  $15,788    $—      $—     $15,788  

Derivative Contracts

   —     —     355,202   355,202   —       —       16,926    16,926  
                           

Total Assets

  $8,651  $—    $355,202  $363,853  $15,788    $—      $16,926   $32,714  
                           

Liabilities

               

Rabbi Trust Deferred Compensation Plan

  $14,531  $—    $—    $14,531  $21,600    $—      $—     $21,600  

Derivative Contracts

   —     —     —     —     —       —       (2,180  (2,180
                           

Total Liabilities

  $14,531  $—    $—    $14,531  $21,600    $—      $(2,180 $19,420  
                           

- 101 -


(In thousands)

  Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
   Significant
Other
Observable
Inputs
(Level 2)
   Significant
Unobservable
Inputs
(Level 3)
   Balance as of
December 31,
2009
 

Assets

        

Rabbi Trust Deferred Compensation Plan

  $10,031    $—      $—      $10,031  

Derivative Contracts

   —       —       114,686     114,686  
                    

Total Assets

  $10,031    $—      $114,686    $124,717  
                    

Liabilities

        

Rabbi Trust Deferred Compensation Plan

  $19,087    $—      $—      $19,087  

Derivative Contracts

   —       —       2,379     2,379  
                    

Total Liabilities

  $19,087    $—      $2,379    $21,466  
                    

The determinationCompany’s investments associated with its Rabbi Trust Deferred Compensation Plan consist of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s Consolidated Balance Sheet, but also the impactmutual funds and deferred shares of the Company’s nonperformance risk on its liabilities.

Index to Financial Statements

The following table sets forth a reconciliation of changescommon stock that are publicly traded and for year ended December 31, 2008 in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

    (In thousands) 

Balance as of December 31, 2007

  $7,272(1)

Total Gains or (Losses) (Realized or Unrealized):

  

Included in Earnings(2)

   13,021 

Included in Other Comprehensive Income

   347,930 

Purchases, Issuances and Settlements

   (13,021)

Transfers In and/or Out of Level 3

   —   
     

Balance as of December 31, 2008

  $355,202 
     

(1)

Net derivatives for Level 3 at December 31, 2007 included derivative assets of $12.7 million and derivative liabilities of $5.4 million.

(2)

All gains included in earnings were realized.

which market prices are readily available. The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using a Black-Scholes modelvaluation models that considersconsider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term. Although the Company utilizesterm as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes to assess the reasonableness of its values, the Company has not attempted to obtain sufficient corroborating market evidence to support classifying these derivative contracts as Level 2.obtained from counterparties for reasonableness. The Company measured the nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions. The resulting reduction to the net receivable derivative contract position was $5.1$0.1 million. In times where the Company has net derivative contract liabilities, the nonperformance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

The following table sets forth a reconciliation of changes for the years ended December 31, 2010 and 2009 in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

   December 31, 

(In thousands)

  2010  2009  2008 

Balance at beginning of period

  $112,307   $355,202   $7,272  

Total Gains or (Losses) (Realized or Unrealized):

    

Included in Earnings(1)

   172,764    393,073    13,021  

Included in Other Comprehensive Income

   (97,335  (240,941  347,930  

Purchases, Issuances and Settlements

   (172,990  (395,027  (13,021

Transfers In and/or Out of Level 3

   —      —      —    
             

Balance at end of period

  $14,746   $112,307   $355,202  
             

(1)

A loss of $0.2 million and $2.0 million for the years ended December 31, 2010 and 2009, respectively was unrealized and included in Natural Gas Revenues in the Statement of Operations. All gains included in earnings for the year ended December 31, 2008 were realized.

There were no transfers between Level 1 and Level 2 measurements for the year ended December 31, 2010.

Fair Market Value of Other Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value. value due to the short-term maturities of these instruments.

- 102 -


The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the yearperiod end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuesissuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes excluding theand credit facility areis based on interest rates currently available to the Company. The credit facility approximates fair value because this instrument bears interest at rates based on current market rates.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, “Disclosures about Fair ValueThe carrying amounts and fair values of Financial Instruments” as well as SFAS No. 157, “Fair Value Measurements” and does not impact the Company’s financial position, results of operations or cash flows.

Index to Financial Statements
   December 31, 2008  December 31, 2007 
    Carrying
Amount
  Estimated
Fair Value
  Carrying
Amount
  Estimated
Fair Value
 
   (In thousands) 

Long-Term Debt

  $867,000  $807,508  $350,000  $364,500 

Current Maturities

   (35,857)  (35,796)  (20,000)  (20,466)
                 

Long-Term Debt, excluding Current Maturities

  $831,143  $771,712  $330,000  $344,034 
                 

Derivative Instruments and Hedging Activity

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. At December 31, 2008, the Company had 26 cash flow hedges open: 14 natural gas price collar arrangements, 10 natural gas price swap arrangements and two crude oil price swap arrangements. At December 31, 2008, a $355.2 million ($223.1 million, net of tax) unrealized gain was recorded in Accumulated Other Comprehensive Income / (Loss), along with a $264.7 million short-term derivative receivable and a $90.5 million long-term derivative receivable. The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income / (Loss). The ineffective portion of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives,debt are recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate. For the years ended December 31, 2008, 2007 and 2006, there was no ineffectiveness recorded in the Consolidated Statement of Operations.

During the second quarter of 2008, in anticipation of the east Texas acquisition, the Company entered into 12 contracts for natural gas price swaps and three contracts for crude oil swaps (2009 and 2010 contracts included in the amounts discussed above) for the remainder of 2008 and extending through 2010 for the purpose of reducing commodity price risk associated with anticipated production after the transaction closing.

Based upon estimates at December 31, 2008, the Company would expect to reclassify to the Consolidated Statement of Operations, over the next 12 months, $166.2 million in after-tax income associated with commodity hedges. This reclassification represents the net short-term receivable associated with open positions currently not reflected in earnings at December 31, 2008 related to anticipated 2009 production.

Hedges on Production—Swaps

From time to time, the Company enters into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of its production. These cash flow hedges are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

During 2008, natural gas price swaps covered 9,821 Mmcf, or 11%, of the Company’s 2008 gas production at an average price of $10.27 per Mcf. During 2008, the Company entered into natural gas price swaps covering a portion of its anticipated 2008, 2009 and 2010 production, including production related to the east Texas acquisition.

Index to Financial Statements

At December 31, 2008, the Company had open natural gas price swap contracts covering a portion of its anticipated 2009 and 2010 production as follows:

 

   Natural Gas Price Swaps

Contract Period

  Volume
in
Mmcf
  Weighted-
Average
Contract
Price
(per Mcf)
  Net
Unrealized
Gain
(In thousands)

Year Ended December 31, 2009

  16,079  $12.18  $90,267

Year Ended December 31, 2010

  19,295  $11.43  $70,345

The Company had one crude oil price swap covering 92 Mbbl, or 12%, of its 2008 production at a price of $127.15 per Bbl. During 2008, the Company entered into crude oil price swaps covering a portion of its anticipated 2008, 2009 and 2010 production. At December 31, 2008, the Company had open crude oil price swap contracts covering a portion of its anticipated 2009 and 2010 production as follows:

   Crude Oil Price Swaps

Contract Period

  Volume
in
Mbbl
  Contract
Price
(per Bbl)
  Net
Unrealized
Gain
(In thousands)

Year Ended December 31, 2009

  365  $125.25  $25,656

Year Ended December 31, 2010

  365  $125.00  $21,840
   December 31, 2010   December 31, 2009 

(In thousands)

  Carrying
Amount
   Estimated
Fair Value
   Carrying
Amount
   Estimated
Fair Value
 

Long-Term Debt

  $975,000    $1,100,830    $805,000    $863,559  

Hedges on Production—Options

From time to time, the Company enters into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of its production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index price falls below the floor price, the counterparty pays the Company. During 2008, natural gas price collars covered 54,173 Mmcf of the Company’s gas production, or 60% of gas production with a weighted-average floor of $8.53 per Mcf and a weighted-average ceiling of $10.70 per Mcf.

At December 31, 2008, the Company had open natural gas price collar contracts covering a portion of its anticipated 2009 production as follows:

   Natural Gas Price Collars

Contract Period

  Volume
in
Mmcf
  Weighted-
Average Ceiling/
Floor (per Mcf)
  Net
Unrealized
Gain
(In thousands)

Year Ended December 31, 2009

  47,253  $12.39 / $9.40  $152,191

During 2008, an oil price collar covered 366 Mbbls of the Company’s crude oil production, or 47% of its crude oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.

The Company is exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.

The amounts set forth under the net unrealized gain columns in the tables above represent the Company’s total unrealized gain position at December 31, 2008. Also impacting the total unrealized net gain (reflecting the net receivable position) in accumulated other comprehensive income / (loss) in the Consolidated Balance Sheet is a reduction of $5.1 million related to the Company’s assessment of its counterparties’ nonperformance risk. This risk was evaluated by reviewing credit default swap spreads for the various financial institutions in which the Company has derivative transactions.

Index to Financial Statements

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

Market Risk

The Company’s primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The debt and equity markets have recently experienced unfavorable conditions, which may affect the Company’s ability to access those markets. As a result of the volatility and disruption in the capital markets and the Company’s increased level of borrowings, it may experience increased costs associated with future borrowings and debt issuances. At this time, the Company does not believe its liquidity has been materially affected by the recent market events. The Company will continue to monitor events and circumstances surrounding each of its lenders in its revolving credit facility.

Credit Risk

Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

In 2008, one customer accounted for approximately 16% of the Company’s total sales. In 2007 and 2006, no customer accounted for more than 10% of the Company’s total sales.

12. Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities are also recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2008, there were no assets legally restricted for purposes of settling asset retirement obligations.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense for the years ended December 31, 2008, 2007 and 2006 was $1.2 million, $1.1 million and $1.4 million, respectively, and was included within Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Operations.

The following table reflects the changes of the asset retirement obligations during the current period.

    (In thousands) 

Carrying amount of asset retirement obligations at December 31, 2007

  $24,724 

Liabilities added during the current period

   2,157 

Liabilities settled during the current period

   (101)

Current period accretion expense

   1,198 
     

Carrying amount of asset retirement obligations at December 31, 2008

  $27,978 
     

Index to Financial Statements

13.15. Earnings per Common Share

Basic earnings per common share (EPS)EPS is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options and stock appreciation rights were exercised and stock awards outstandingwere vested at the end of the applicable period were exercised for common stock.period.

The following is a calculation of basic and diluted weighted-average shares outstanding for the years ended December 31, 2008, 20072010, 2009 and 2006:2008:

 

   December 31,
   2008  2007  2006

Weighted-Average Shares—Basic

  100,736,562  96,977,634  96,803,283

Dilution Effect of Stock Options and Awards at End of Period

  989,936  1,152,673  1,797,700
         

Weighted-Average Shares—Diluted

  101,726,498  98,130,307  98,600,983
         

Weighted-Average Stock Awards and Shares

      

Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect

  258,074  21,639  —  
         
   December 31, 
   2010   2009   2008 

Weighted-Average Shares—Basic

   103,911,431     103,615,971     100,736,562  

Dilution Effect of Stock Options, Stock Appreciation Rights and Stock Awards at End of Period

   1,283,354     1,066,776     989,936  
               

Weighted-Average Shares—Diluted

   105,194,785     104,682,747     101,726,498  
               

Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect

   283,566     260,818     258,074  
               

- 103 -


14.16. Accumulated Other Comprehensive Income / (Loss)

Changes in the components of accumulated other comprehensive income / (loss), net of taxes, for the years ended December 31, 2008, 20072010, 2009 and 20062008 were as follows:

 

Accumulated Other Comprehensive Income / (Loss), net of taxes
(In thousands)

 Net
Gains /(Losses)
on Cash Flow
Hedges
  Defined
Benefit
Pension and
Postretirement
Plans
  Foreign
Currency
Translation
Adjustment
  Total 

Balance at December 31, 2005

 $(12,860) $(3,170) $915  $(15,115)
                

Net change in unrealized gains on cash flow hedges, net of taxes of $(38,625)

  64,099   —     —     64,099 

Net change in minimum pension liability, net of taxes of $(1,848)

  —     3,081   —     3,081 

Effect of adoption of SFAS No. 158, net of taxes of $8,447

  —     (14,079)  —     (14,079)

Change in foreign currency translation adjustment, net of taxes of $507

  —     —     (826)  (826)
                

Balance at December 31, 2006

 $51,239  $(14,168) $89  $37,160 
                

Net change in unrealized gains on cash flow hedges, net of taxes of $28,024

  (46,686)  —     —     (46,686)

Net change in defined benefit pension and postretirement plans, net of taxes of $(100)

  —     141   —     141 

Change in foreign currency translation adjustment, net of taxes of $(5,072)

  —     —     8,491   8,491 
                

Balance at December 31, 2007

 $4,553  $(14,027) $8,580  $(894)
                

Net change in unrealized gain on cash flow hedges, net of taxes of $(129,415)

  218,515   —     —     218,515 

Net change in defined benefit pension and postretirement plans, net of taxes of $9,235

  —     (15,581)  —     (15,581)

Change in foreign currency translation adjustment, net of taxes of $9,292

  —     —     (15,614)  (15,614)
                

Balance at December 31, 2008

 $223,068  $(29,608) $(7,034) $186,426 
                
   Net
Gains / (Losses)
on Cash Flow
Hedges
  Defined
Benefit
Pension and
Postretirement
Plans
  Foreign
Currency
Translation
Adjustment
  Total 

Balance at December 31, 2007

  $4,553   $(14,027 $8,580   $(894
                 

Net change in unrealized gain on cash flow hedges, net of taxes of $(129,415)

   218,515    —      —      218,515  

Net change in defined benefit pension and postretirement plans, net of taxes of $9,235

   —      (15,581  —      (15,581

Change in foreign currency translation adjustment, net of taxes of $9,292

   —      —      (15,614  (15,614
                 

Balance at December 31, 2008

  $223,068   $(29,608 $(7,034 $186,426  
                 

Net change in unrealized gain on cash flow hedges, net of taxes of $89,745

   (151,196  —      —      (151,196

Net change in defined benefit pension and postretirement plans, net of taxes of $(162)

   —      259    —      259  

Change in foreign currency translation adjustment, net of taxes of $(4,116)

   —      —      6,947    6,947  
                 

Balance at December 31, 2009

  $71,872   $(29,349 $(87 $42,436  
                 

Net change in unrealized gain on cash flow hedges, net of taxes of $35,957

   (61,378  —      —      (61,378

Net change in defined benefit pension and postretirement plans, net of taxes of (9,088)

   —      15,227    —      15,227  

Change in foreign currency translation adjustment, net of taxes of ($20)

   —      —      32    32  
                 

Balance at December 31, 2010

  $10,494   $(14,122 $(55 $(3,683
                 

Index to Financial Statements

- 104 -


CABOT OIL & GAS CORPORATION

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.

Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

Estimates of total proved and proved developed reserves at December 31, 2008, 2007,2010, 2009 and 20062008 were based on studies performed by the Company’s petroleum engineering staff. The 2010 and 2009 estimates were computed using the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year, as prescribed under the revised rules codified in ASC 932, “Extractive Activities—Oil and Gas”. The 2008 estimates were computed based on year end prices for oil natural gas, and natural gas liquids.gas. The estimates were reviewedaudited by Miller and Lents, Ltd., who indicated in their letter dated January 30, 2009, that based on their investigation and subject to the limitations described in their audit letter, they believe the results of those estimates and projections were reasonable in the aggregate.

No major discovery or other favorable or unfavorable event after December 31, 2008,2010, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

As of December 31, 2009, the Company adopted the guidance in ASC 932 related to oil and gas reserve estimation and disclosures in conjunction with the year-end reserve reporting as a change in accounting principle that is inseparable from a change in accounting estimate. The impact of the adoption of this guidance on the Company’s financial statements was not practicable to estimate due to the challenges associated with computing a cumulative effect of adoption by preparing reserve reports under both the old and new guidance.

- 105 -


The following table illustratestables illustrate the Company’s net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company’s engineering staff. All reserves are located within the continental United States in 2010 and 2009 and, to a lesser extent, Canada in 2008.

 

  Natural Gas   Natural  Gas
(Mmcf)
 Oil &  Liquids
(Mbbl)
 Total
(Mmcfe)(1)
 

December 31, 2007(5)

   1,559,953    9,328    1,615,919  
  December 31,           

Revision of Prior Estimates(2)

   (47,745  (1,593  (57,302

Extensions, Discoveries and Other Additions

   297,089    1,134    303,895  

Production.

   (90,425  (794  (95,191

Purchases of Reserves in Place

   167,262    1,268    174,872  

Sales of Reserves in Place

   (141  (2  (156
  2008 2007 2006           

December 31, 2008(5)

   1,885,993    9,341    1,942,037  
  (Millions of cubic feet)           

Proved Reserves

    

Beginning of Year

  1,559,953  1,368,293  1,262,096 

Revisions of Prior Estimates(1)

  (47,745) 2,604  (17,675)

Revision of Prior Estimates(3)

   (193,767  (1,062  (200,143

Extensions, Discoveries and Other Additions

  297,089  265,830  246,197    459,612    544    462,880  

Production

  (90,425) (80,475) (79,722)   (97,914  (844  (102,976

Purchases of Reserves in Place

  167,262  3,701  1,946    9    —      9  

Sales of Reserves in Place

  (141) —    (44,549)   (40,771  (196  (41,949
                    

End of Year

  1,885,993  1,559,953  1,368,293 

December 31, 2009

   2,013,162    7,783    2,059,858  
          

Revision of Prior Estimates(4)

   139,016    (379  136,742  

Extensions, Discoveries and Other Additions

   632,980    2,944    650,644  

Production

   (125,474  (858  (130,622

Purchases of Reserves in Place

   593    4    617  

Sales of Reserves in Place

   (16,119  (3  (16,137
          

December 31, 2010

   2,644,158    9,491    2,701,102  
          
          

Proved Developed Reserves

  1,308,155  1,133,937  996,850     

December 31, 2007

   1,133,937    7,026    1,176,091  

December 31, 2008

   1,308,155    6,728    1,348,521  

December 31, 2009

   1,288,169    6,082    1,324,663  

December 31, 2010

   1,681,451    7,129    1,724,225  
          

Percentage of Reserves Developed

  69.4% 72.7% 72.9%
          

Proved Undeveloped Reserves

    

December 31, 2007

   426,016    2,302    439,828  

December 31, 2008

   577,838    2,613    593,516  

December 31, 2009

   724,993    1,701    735,199  

December 31, 2010

   962,707    2,362    976,877  

 

(1)

Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of naturalgas to 1 Bbl of crude oil, condensate or natural gas liquids.

(2)

The majority of the revisions were the result of the decrease in the natural gas price.

(3)

The net downward revision of 200.1 Bcfe was primarily due to (i) downward revisions of 101.6 Bcfedue to lower 2009 oil and natural gas prices compared to 2008 and (ii) downward revisions of 120.4Bcfe due to the removal of proved undeveloped reserves scheduled for development beyond five yearsprimarily due to the application of the SEC’s oil and gas reserve calculation methodology effectivebeginning in 2009, partially offset by 21.9 Bcfe of positive performance revisions.

(4)

The net upward revision of 136.7 Bcfe was primarily due to (i) an upward performance revision of284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and (ii) an upward revision of 35.0Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of182.7 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

(5)

Prior to 2009, reserve estimates were based on year end prices.

Index to Financial Statements
   Liquids 
   December 31, 
   2008  2007  2006 
   (Thousands of barrels) 

Proved Reserves

    

Beginning of Year

  9,328  7,973  11,463 

Revisions of Prior Estimates(1)

  (1,593) 771  673 

Extensions, Discoveries and Other Additions

  1,134  1,381  1,066 

Production

  (794) (830) (1,415)

Purchases of Reserves in Place

  1,268  33  38 

Sales of Reserves in Place

  (2) —    (3,852)
          

End of Year

  9,341  9,328  7,973 
          

Proved Developed Reserves

  6,728  7,026  5,895 
          

Percentage of Reserves Developed

  72.0% 75.3% 73.9%
          

- 106 -

(1)

The majority of the revisions were the result of the decrease in the crude oil price.


Capitalized Costs Relating to Oil and Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.

 

  December 31,  December 31, 
  2008  2007  2006
  (In thousands)

(In thousands)

  2010   2009   2008 

Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities

  $4,465,630  $3,007,849  $2,462,693  $5,598,842    $4,905,424    $4,465,630  

Aggregate Accumulated Depreciation, Depletion and Amortization

   1,331,243   1,100,369   983,079   1,840,091     1,550,837     1,331,243  
            

Net Capitalized Costs

   3,758,751     3,354,587     3,134,387  
            

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:

 

   Year Ended December 31,
    2008  2007  2006
   (In thousands)

Property Acquisition Costs, Proved

  $605,860  $3,982  $6,688

Property Acquisition Costs, Unproved

   152,666   22,186   42,551

Exploration Costs(1)

   89,020   70,242   109,525

Development Costs

   594,221   494,204   346,787
            

Total Costs

  $1,441,767  $590,614  $505,551
            

   Year Ended December 31, 

(In thousands)

  2010   2009   2008 

Property Acquisition Costs, Proved

  $801    $394    $605,860  

Property Acquisition Costs, Unproved

   130,675     145,681     152,666  

Exploration Costs

   66,368     68,196     82,972  

Development Costs

   630,511     379,140     600,269  
               

Total Costs

  $828,355    $593,411    $1,441,767  
               

(1)

Includes administrative exploration costs of $14,766, $13,761 and $13,486 for the years ended December 31, 2008,2007 and 2006, respectively.

Index to Financial Statements

Historical Results of Operations from Oil and Gasfor Producing Activities

The results of operations for the Company’s oil and gas producing activities were as follows:

 

  Year Ended December 31,  Year Ended December 31, 
  2008  2007  2006
  (In thousands)

(In thousands)

  2010   2009   2008 

Operating Revenues

  $829,208  $637,195  $659,884  $775,974    $800,464    $829,208  

Costs and Expenses

            

Production

   140,763   116,020   115,786   120,322     121,087     140,763  

Other Operating

   59,348   40,620   46,212

Exploration(1)

   31,200   39,772   49,397

Exploration

   42,725     50,784     31,200  

Depreciation, Depletion and Amortization

   259,399   164,613   139,207   364,452     265,402     259,399  
                     

Total Costs and Expenses

   490,710   361,025   350,602   527,499     437,273     431,362  
                     

Income Before Income Taxes

   338,498   276,170   309,282   248,475     363,191     397,846  

Provision for Income Taxes

   124,528   100,755   113,355   94,293     133,312     146,361  
                     

Results of Operations

  $213,970  $175,415  $195,927  $154,182    $229,879    $251,485  
                     

 

(1)

Includes administrative exploration costs of $14,766, $13,761 and $13,486 for the years ended December 31, 2008,2007 and 2006, respectively.

- 107 -


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing SFAS No. 69,“Disclosures about Oil and Gas Producing Activities,” proceduresthe guidance in ASC 932 and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

 

Future costs and selling prices will probably differ from those required to be used in these calculations.

 

Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.

 

Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.

 

Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows for 2010 and 2009 were estimated by using the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year, as prescribed under the revised rules codified in ASC 932 that the Company adopted on January 1, 2010, and by applying year end oil and gas prices to the estimated future production of year end proved reserves.reserves for 2008.

The average prices (adjusted for basis and quality differentials) related to proved reserves at December 31, 2008, 20072010, 2009 and 20062008 for natural gas ($ per Mcf) were $5.66, $6.91$4.33, $3.84 and $5.54,$5.66, respectively, and for oil ($ per Bbl) were $40.15, $94.94$74.25, $55.41 and $59.50,$40.15, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved. SFAS No. 69involved and utilization of available tax carryforwards related to oil and gas operations. ASC 932 requires the use of a 10% discount rate.

Index to Financial Statements

Management does not solely use only the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

Standardized Measure is as follows:

 

  Year Ended December 31,   Year Ended December 31, 
  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Future Cash Inflows

  $11,050,932  $11,671,078  $8,054,737   $12,147,617   $8,170,009   $11,050,932  

Future Production Costs

   (3,018,154)  (2,690,695)  (2,000,993)   (2,377,402  (2,353,974  (3,018,154

Future Development Costs

   (1,354,780)  (909,374)  (688,955)   (1,670,796  (1,234,203  (1,354,780

Future Income Tax Expenses

   (1,891,928)  (2,684,271)  (1,763,458)   (2,357,935  (1,089,282  (1,891,928
                    

Future Net Cash Flows

   4,786,070   5,386,738   3,601,331    5,741,484    3,492,550    4,786,070  

10% Annual Discount for Estimated Timing of Cash Flows

   (2,726,115)  (3,216,087)  (2,125,081)   (3,006,975  (1,860,815  (2,726,115
                    

Standardized Measure of Discounted Future Net Cash Flows(1)

  $2,059,955  $2,170,651  $1,476,250 

Standardized Measure of Discounted Future Net Cash Flows

  $2,734,509   $1,631,735   $2,059,955  
                    

 

(1)

The standardized measures of discounted future net cash flows before taxes were $2,365,208, $3,007,661 and $2,010,228 for the years ended December 31, 2008, 2007 and 2006, respectively.

- 108 -


Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure:

 

  Year Ended December 31,   Year Ended December 31, 
  2008 2007 2006 
  (In thousands) 

(In thousands)

  2010 2009 2008 

Beginning of Year

  $2,170,651  $1,476,250  $2,651,233   $1,631,735   $2,059,955   $2,170,651  

Discoveries and Extensions, Net of Related Future Costs

   341,156   430,918   278,258    780,917    381,691    341,156  

Net Changes in Prices and Production Costs

   (692,803)  864,630   (1,843,272)   991,942    (861,939  (692,803

Accretion of Discount

   300,766   201,023   400,177    164,189    236,520    300,766  

Revisions of Previous Quantity Estimates

   (69,788)  13,452   (19,362)   164,851    (159,531  (69,788

Timing and Other

   (157,194)  (136,360)  (86,891)   (105,331  (104,117  (157,194

Development Costs Incurred

   157,194   136,781   85,993    115,560    109,384    157,194  

Sales and Transfers, Net of Production Costs

   (688,657)  (521,558)  (544,650)   (481,556  (286,594  (688,657

Net Purchases / (Sales) of Reserves in Place

   166,873   8,548   (261,795)   (16,124  (38,730  166,873  

Net Change in Income Taxes

   531,757   (303,033)  816,559    (511,674  295,096    531,757  
                    

End of Year

  $2,059,955  $2,170,651  $1,476,250   $2,734,509   $1,631,735   $2,059,955  
                    

Index to Financial Statements

- 109 -


CABOT OIL & GAS CORPORATION

SELECTED DATA (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

 

  First  Second  Third  Fourth  Total
  (In thousands, except per share amounts)

2008

          

Operating Revenues

  $219,651  $248,854  $244,820  $232,466  $945,791

Impairment of Oil & Gas Properties and Other Assets(1)

   —     —     —     35,700   35,700

Operating Income

   76,072   94,086   114,717   87,137   372,012

Net Income

   45,975   54,625   66,990   43,700   211,290

Basic Earnings per Share

   0.47   0.55   0.65   0.42   2.10

Diluted Earnings per Share

   0.46   0.55   0.64   0.42   2.08

2007

          

(In thousands , except per share amounts )

  First   Second   Third   Fourth   Total 

2010

          

Operating Revenues

  $191,573  $175,832  $170,848  $193,917  $732,170  $212,556    $195,474    $219,130    $216,875    $844,035  

Impairment of Oil & Gas Properties and Other Assets(1)

   —     —     4,614   —     4,614   —       —       35,789     5,114     40,903  

Operating Income(2)

   79,185   70,245   55,521   69,742   274,693   60,589     52,068     22,274     131,508     266,439  

Net Income(2)

   48,547   41,376   35,453   42,047   167,423   28,696     21,682     3,899     49,109     103,386  

Basic Earnings per Share

   0.50   0.43   0.37   0.43   1.73   0.28     0.21     0.04     0.47     0.99  

Diluted Earnings per Share

   0.50   0.42   0.36   0.43   1.71   0.27     0.21     0.04     0.47     0.98  

2009

          

Operating Revenues

  $233,939    $204,824    $207,021    $233,492    $879,276  

Impairment of Oil & Gas Properties and Other Assets(1)

   —       —       —       17,622     17,622  

Operating Income(3)

   89,897     54,239     74,723     63,410     282,269  

Net Income(3)

   47,580     25,502     38,897     36,364     148,343  

Basic Earnings per Share

   0.46     0.25     0.38     0.34     1.43  

Diluted Earnings per Share

   0.46     0.24     0.37     0.35     1.42  

 

(1)

For discussion of impairment of oil and gas properties, refer to Note 2 of the Notes to the Consolidated Financial Statements.

(2)

Operating Income and Net Income in the second and fourth quarters of 2010 contain a $10.3 million gain on the disposition of the Woodford shale prospect and an impairment loss of $5.8 million associated with the third quarter sale of certain oil and gas properties in Colorado in the second quarter of 2010 and a gain of $11.4 million related to the sale of certain oil and gas properties in the Texas Panhandle as well as a gain of $49.3 million associated with the sale of the Pennsylvania gathering infrastructure and a $40.7 million gain from the sale of the Company’s investment in Tourmaline in the fourth quarter of 2010, respectively.

(3)

Operating Income and Net Income in the first and second quarters of 20072009 contain thea $12.7 million gain on the disposition of offshoreThornwood properties and certain south Louisianaa $16.0 million loss on the sale of Canadian properties, of $7.9 million and $4.4 million, respectively.

- 110 -


ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

 

ITEM 9A.CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Changes in Internal Control over Financial Reporting

As of the end of December 31, 2008,2010, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially effect, the Company’s internal control over financial reporting.

Index to Financial Statements

Management’s Report on Internal Control over Financial Reporting

The management of Cabot Oil & Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Cabot Oil & Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Cabot Oil & Gas Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008.2010. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of December 31, 2008,2010, the Company’s internal control over financial reporting is effective at a reasonable assurance level based on those criteria.

The effectiveness of Cabot Oil & Gas Corporation’s internal control over financial reporting as of December 31, 2008,2010, has been audited by Pricewaterhouse CoopersPricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

 

ITEM 9B.OTHER INFORMATION

None.

- 111 -


PART III

 

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20092011 annual stockholders’ meeting. In addition, the information set forth under the caption “Business—Other“Business-Other Business Matters—CorporateMatters-Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct is incorporated by reference in response to this Item.

 

ITEM 11.EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20092011 annual stockholders’ meeting.

 

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20092011 annual stockholders’ meeting.

 

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20092011 annual stockholders’ meeting.

Index to Financial Statements
ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20092011 annual stockholders’ meeting.

PART IV

 

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

A.INDEX

 

1.Consolidated Financial Statements

See Index on page 56.54.

 

2.Financial Statement Schedules

None.Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements.

 

- 112 -


3.Exhibits

The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. Our commission file number is 1-10447.

 

Exhibit

Number

 

Description

***2.1Purchase and Sale Agreement dated June 3, 2008 by and among Enduring Resources, LLC, Mustang Drilling, Inc., Minden Gathering Services, LLC and Cabot Oil & Gas Corporation (Form 10-Q for the quarter ended June 30, 2008).
3.1 Restated Certificate of Incorporation of the Company (Registration Statement No. 33- 32553)(Form 8-K for January 21, 2010).
3.2 Amended and Restated Bylaws of the Company amended May 2, 2007January 14, 2010 (Form 10-Q8-K for the quarter ended March 31, 2007)January 14, 2010).
3.3Certificate of Amendment of Certificate of Incorporation (Form 8-K for July 1, 2002).
3.4Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for July 1, 2002).
3.5Certificate of Amendment of Certificate of Incorporation (Form 8-K for June 1, 2006).
3.6Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for June 1, 2006).
4.1 Form of Certificate of Common Stock of the Company (Registration Statement No. 33- 32553)33-32553).
4.2Certificate of Designation for Series A Junior Participating Preferred Stock (Form 10-K for 1994).
4.3Rights Agreement, dated as of March 28, 1991, as amended and restated as of December 8, 2000 among the Company and Fleet National Bank formerly known as The First National Bank of Boston and as BankBoston, N.A. (Form 8-K for December 20, 2000).

(a)    Amendment to the Rights Agreement dated January 1, 2003 (The Bank of New York as rights agent) (Form 10-Q for the quarter ended March 31, 2003).

(b)    Amendment to the Rights Agreement dated March 30, 2007 (regarding uncertified shares) (Form 10-Q for the quarter ended March 31, 2007).

4.4Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997).

Index to Financial Statements

Exhibit
Number

Description

    4.5 Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001).
    4.6Credit

(a)    Amendment No. 1 to Note Purchase Agreement, dated as of October 28, 2002 among the Company, the Banks Parties Thereto and Fleet National Bank, as administrative agentJune 30, 2010 (Form 10-Q for the quarter ended SeptemberJune 30, 2002).

(a)    Amendment No. 1 to Credit Agreement dated December 10, 2004 (Form 10-K for 2004)2010).

 

(b)    Amendment No. 2 to CreditNote Purchase Agreement, dated June 18, 2008as of September 28, 2010 (Form 10-Q for the quarter ended JuneSeptember 30, 2008).

(c)    Amendment No. 3 to Credit Agreement dated June 18, 2008 (Form 10-Q for the quarter ended June 30, 2008).

(d)    Amendment No. 4 to Credit Agreement dated December 4, 2008 (Form 8-K for December 16, 2008)2010).

      4.74.3 Note Purchase Agreement dated as of July 16, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 8-K for July 16, 2008).
(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
      4.84.4 Note Purchase Agreement dated as of December 1, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 10-K for 2008).

(a)    Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).

      4.5Note Purchase Agreement dated as of December 30, 2010 among Cabot Oil & Gas Corporation and the Purchasers named therein.
*10.1      4.6Credit Agreement, dated as of September 22, 2010, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication Agent, Bank of Montreal, as Documentation Agent, and the Lenders party thereto (Form 10-Q for the quarter ended September 30, 2010).
  *10.1 Form of Change in Control Agreement between the Company and Certain Officers.Officers (Form 10-K for 2008).

(a)    Form of Change in Control Agreement between the Company and Certain Officers (Confirmation that Certain Benefits no Longer Apply).

*10.2  *10.2 Form of Supplemental Executive Retirement Agreement.Agreement (Form 10-K for 2008).

(a)    Agreement Concerning SERP.

*10.3  *10.3 1990 Non-employee Director Stock Option Plan of the Company (Form S-8) (Registration
No. 33-35478).
 

(a)    First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8) (Registration No. 33-35478).

 

(b)    Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995).

- 113 -


*10.4

Exhibit

Number

Description

    *10.4 Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001).
*10.5    *10.5 Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001).
*10.6    *10.6 Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997).
*10.7    *10.7 Deferred Compensation Plan of the Company, as Amended and Restated, Effective January 1, 2009.2009 (Form 10-K for 2008).

(a)    First amendment to the Deferred Compensation Plan of the Company, effective October 1, 2010.

(b)    Second amendment to the Deferred Compensation Plan of the Company, effective October 26, 2010.

      10.8 Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).
      10.9 Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998).
    10.10Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998).
*10.11*10.10 Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).
 

(a)    Amendment to Employment Agreement between the Company and Dan O. Dinges, effective December 31, 2008.2008 (Form 10-K for 2008).

*10.12    *10.11 2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).
 

(a)    First Amendment to the 2004 Incentive Plan effective February 23, 2007 (Form 10-Q for the quarter ended March 31, 2007).

 

(b)    Second Amendment to the 2004 Incentive Plan Amendment, effective as of January 1, 2009.2009 (Form 10-K for 2008).

Index to Financial Statements

Exhibit
Number

Description

*10.13    *10.12 2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).
*10.14    *10.13 2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
*10.15    *10.14
 

Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form

(Form 8-K for February 10, 2005).

*10.16    *10.15 2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005).
*10.17    *10.16 Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005).
 

(a)    First Amendment to the Savings Investment Plan effective January 1, 2002 (Form 10-K for 2005).

 

(b)    Second Amendment to the Savings Investment Plan effective January 1, 2003 (Form 10-K for 2005).

 

(c)    Third Amendment to the Savings Investment Plan effective January 1, 2005 (Form 10-K for 2005).

*10.18    *10.17 Forms of Award Agreements for Executive Officers under 2004 Incentive Plan (Form 10-K for 2006).
 

(a)    Form of Restricted Stock Award Agreement (Form 10-K for 2006).

 

(b)    Form of Stock Appreciation Rights Award Agreement (Form 10-K for 2006).

 

(c)    Form of Performance Share Award Agreement (Form 10-K for 2006).

- 114 -


  10.19

Exhibit

Number

Description

      10.18 Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (Registration Statement No. 333-135365).
 

(a)    Form of Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-135365).

 

(b)    Form of Conveyance of Overriding Royalty Interest (Registration Statement No. 333-135365).

      10.2010.19 Purchase and Sale Agreement dated August 25, 2006 between Cabot Oil & Gas Corporation, a Delaware corporation, Cody Energy LLC, a Colorado limited liability company, and Phoenix Exploration Company LP, a Delaware limited partnership (Form 8-K for September 29, 2006).
*10.21    *10.20 Form of Amendment of Employee Award Agreements (Form 8-K for December 19, 2006).
*10.22    *10.21 Savings Investment Plan of the Company, as amended and restated effective January 1, 2006 (Form 10-K for 2006).
 

(a)    First Amendment to the Savings Investment Plan of the Company effective January 1, 2006 (Form 10-K for 2007).

 

(b)    Second Amendment to the Savings Investment Plan of the Company effective April 23, 2008 (Form 10-Q for the quarter ended March 31, 2008).

 

(c)    Third Amendment to the Savings Investment Plan of the Company effective July 1, 2008.2008 (Form 10-K for 2008).

 

(d)    Fourth Amendment to the Savings Investment Plan of the Company effective January 1, 2008.2008 (Form 10-K for 2008).

*10.23    *10.22 Cabot Oil & Gas Corporation Pension Plan, as amended and restated effective September 30, 2010.
    *10.23Savings Investment Plan of the Company, as amended and restated effective January 1, 20062009 (Form 10-K for 2006)2009).
 

(a)    First Amendment to the PensionSavings Investment Plan of the Company effective January 1, 2006 (Form 10-K for 2007).2009.

(b)    Second Amendment to the Pension Plan of the Company effective April 23, 2008 (Form 10-Q for the quarter ended March 31, 2008).

(c)    Third Amendment to the Pension Plan of the Company effective July 1, 2008.

(d)    Fourth Amendment to the Pension Plan of the Company effective January 1, 2008.

Index to Financial Statements

Exhibit
Number

Description

  10.24Purchase and Sale Agreement dated June 3, 2008 by and among Enduring Resources, LLC, Mustang Drilling, Inc., Minden Gathering Services, LLC and Cabot Oil & Gas Corporation (Form 10-Q for the quarter ended June 30, 2008).
  14.1Amendment of Code of Business Conduct (as amended on July 28, 2005 to revise Section III. F. relating to Transactions in Securities and Article V. relating to Safety, Health and the Environment) (Form 10-Q for the quarter ended June 30, 2005).
  16.1Letter, dated March 12, 2007, from UHY Mann Frankfort Stein & Lipp CPAs, LLP to the Securities and Exchange Commission (Form 8-K for March 8, 2007).
      21.1 Subsidiaries of Cabot Oil & Gas Corporation.
      23.1 Consent of PricewaterhouseCoopers LLP.
      23.2 Consent of Miller and Lents, Ltd.
      31.1 302 Certification—Chairman, President and Chief Executive Officer.
      31.2 302 Certification—Vice President and Chief Financial Officer.
      32.1 906 Certification.
      99.1 Miller and Lents, Ltd. ReviewAudit Letter.
  **101.INSXBRL Instance Document.
  **101.SCHXBRL Taxonomy Extension Schema Document.
  **101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
  **101.LABXBRL Taxonomy Extension Label Linkbase Document.
  **101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
  **101.DEFXBRL Taxonomy Extension Definition Linkbase Document.

 

*Compensatory plan, contract or arrangement.
**Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
***Certain schedules to the exhibit are omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish to the SEC, upon request, copies of any such schedules.

Index to Financial Statements

- 115 -


SIGNATURES

Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 27th28th of February 2009.2011.

 

CABOT OIL & GAS CORPORATION
By: /S/    DAN O. DINGES        
 

Dan O. Dinges

Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature

  

Title

 

Date

/S/    DAN O. DINGES        

Dan O. Dinges

  Chairman, President and Chief Executive Officer (Principal Executive Officer) February 27, 200928, 2011

/S/    SCOTT C. SCHROEDER        

Scott C. Schroeder

  Vice President, and Chief Financial Officer and Treasurer (Principal Financial Officer) February 27, 200928, 2011

/S/    HTENRYODD C. SM. RMYTHOEMER        

Henry C. SmythTodd M. Roemer

  Vice President, Controller and Treasurer (Principal
(Principal Accounting Officer)
 February 27, 200928, 2011

/S/    RHYS J. BEST        

Rhys J. Best

  Director February 27, 200928, 2011

/S/    DAVID M. CARMICHAEL        

David M. Carmichael

  Director February 27, 200928, 2011

/S/    JAMES R. GIBBS        

James R. Gibbs

DirectorFebruary 28, 2011

/S/    ROBERT L. KEISER        

Robert L. Keiser

  Director February 27, 200928, 2011

/S/    ROBERT KELLEY        

Robert Kelley

  Director February 27, 200928, 2011

/S/    P. DEXTER PEACOCK        

P. Dexter Peacock

  Director February 27, 200928, 2011

/S/    WILLIAM P. VITITOE        

William P. Vititoe

  Director February 27, 200928, 2011

 

115- 116 -