Form 10-K for the Fiscal Year Ended December 31, 2008
Table of Contents
Index to Financial Statements

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, 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, 2008

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, Houston, Texas 77077

(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.    Yes x    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 ¨    No x

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.    Yes x    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-K x.

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 ¨    No x

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) was approximately $7.0 billion.

As of February 19, 2009, there were 103,447,221 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, 2009 are incorporated by reference into Part III of this report.

 

 

 


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

PART I         Page
ITEM 1    Business    2
ITEM 1A    Risk Factors    19
ITEM 1B    Unresolved Staff Comments    25
ITEM 2    Properties    25
ITEM 3    Legal Proceedings    26
ITEM 4    Submission of Matters to a Vote of Security Holders    26
   Executive Officers of the Registrant    26
PART II      
ITEM 5    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    27
ITEM 6    Selected Financial Data    29
ITEM 7    Management’s Discussion and Analysis of Financial Condition and Results of Operations    29
ITEM 7A    Quantitative and Qualitative Disclosures about Market Risk    52
ITEM 8    Financial Statements and Supplementary Data    56
ITEM 9    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    109
ITEM 9A    Controls and Procedures    109
ITEM 9B    Other Information    110
PART III      
ITEM 10    Directors, Executive Officers and Corporate Governance    110
ITEM 11    Executive Compensation    110
ITEM 12    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    110
ITEM 13    Certain Relationships and Related Transactions, and Director Independence    110
ITEM 14    Principal Accountant Fees and Services    111
PART IV      
ITEM 15    Exhibits and Financial Statement Schedules    111


Table of Contents
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, 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.

CERTAIN DEFINITIONS

The following is a list of commonly used terms and their definitions included within this Annual Report on Form 10-K:

 

Abbreviated Term

   Definition
Mcf    Thousand 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

 

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Index to Financial Statements

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 North America. Our four principal areas of operation are the Appalachian Basin, onshore Gulf Coast, including south and east Texas and north Louisiana, the Rocky Mountains and the Anadarko Basin. We also operate in the deep gas basin of Western Canada. Operationally, we have four regional offices located in Houston, Texas; Charleston, West Virginia; Denver, Colorado; and Calgary, Alberta.

In 2008, energy commodity prices increased to all-time high levels for the first half of the year and then quickly declined to 2007 levels during the second half of 2008. Our 2008 average realized natural gas price was $8.39 per Mcf, 16% higher than the 2007 average realized price of $7.23 per Mcf. Our 2008 average realized crude oil price was $89.11 per Bbl, 33% higher than the 2007 average realized price of $67.16 per Bbl. These realized prices include realized gains and losses resulting from commodity derivatives (zero-cost collars or swaps). 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 largest investment program in our history, totaling $1,481.0 million. This included our largest producing property acquisition ($625.0 million), lease acquisition ($152.7 million) and drilling and facilities ($624.3 million) programs. The producing property and lease acquisition activity were funded by issuances of new long-term debt and common stock during the year. The capital spending (excluding the acquisition activity) was funded largely through cash flow from operations and, to a lesser extent, borrowings on our revolving credit facility.

We intend to manage our balance sheet in an effort to ensure that we have sufficient liquidity, and we intend to maintain spending discipline. We believe these strategies continue to be appropriate for our portfolio of projects and the current industry environment, and we believe our balance sheet and availability under our credit facility provide sufficient liquidity to pursue our 2009 program.

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). 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 senior unsecured fixed rate notes (see Note 4 of the Notes to the Consolidated Financial Statements for further details).

On an equivalent basis, our production level in 2008 increased by 11% from 2007. We produced 95.2 Bcfe, or 260.1 Mmcfe per day, in 2008, as compared to 85.5 Bcfe, or 234.1 Mmcfe per day, in 2007. Natural gas production increased to 90.4 Bcf in 2008 from 80.5 Bcf in 2007 primarily due to (1) increased natural gas production in the Gulf Coast region due to increased production in the Minden field, largely due to the properties we acquired in the east Texas acquisition in August 2008, and increased drilling in the County Line field, (2) increased production in the West region associated with an increase 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 increased drilling activity 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 in the Gulf Coast and West regions.

 

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For the year ended December 31, 2008, we drilled 432 gross wells (355 net) with a success rate of 97% compared to 461 gross wells (391 net) with a success rate of 96% for the prior year. In 2009, we plan to drill approximately 148 gross wells (122.3 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 our capital program for 2009 in east Texas and northeast Pennsylvania where opportunities for growth are currently concentrated.

Our 2008 capital and exploration spending was $1.5 billion compared to $636.2 million of total capital and exploration spending in 2007. In both 2008 and 2007, 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. Funding of the program is expected to be provided by operating cash flow, existing cash and increased 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. For 2009, the Gulf Coast and East regions are expected to receive approximately 90% of the anticipated capital program, with the majority of the remainder dedicated to the West 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, we plan to spend approximately $475 million on capital and exploration activities.

Our proved reserves totaled approximately 1,942 Bcfe at December 31, 2008, of which 97% were natural gas. This reserve level was up by 20% from 1,616 Bcfe at December 31, 2007 on the strength of results from our drilling program, the increase in our capital spending and the east Texas acquisition.

The following table presents certain reserve, production and well information as of December 31, 2008.

 

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

Proved Reserves at Year End (Bcfe)

             

Developed

  613.4     317.3     201.9     178.4     380.3     37.5     1,348.5  

Undeveloped

  258.4     237.3     69.5     25.5     95.0     2.8     593.5  
                                         

Total

  871.8     554.6     271.4     203.9     475.3     40.3     1,942.0  

Average Daily Production (Mmcfe per day)

  69.1     104.1     41.3     33.9     75.2     11.7     260.1  

Reserve Life Index (In years)(1)

  34.4     14.6     18.0     16.4     17.3     9.5     20.4  

Gross Wells

  3,382     844     716     844     1,560     43     5,829  

Net Wells(2)

  3,162.6     592.2     329.4     594.5     923.9     16.2     4,694.9  

Percent Wells Operated (Gross)

  96.6 %   75.0 %   52.0 %   78.1 %   66.1 %   58.1 %   85.0 %

 

(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 3.0 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our ten largest fields, which are fields with 2.5% or greater of total company proved reserves, make up approximately 53% of total company proved reserves.

 

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

 

    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

EAST REGION

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

Capital and exploration expenditures for 2008 were $369.6 million, or 24% of our total 2008 capital and exploration expenditures, compared to $178.6 million for 2007, or 28% of our total 2007 capital and exploration expenditures. This increase was substantially driven by a $103.1 million increase in lease acquisition costs year-over-year. For 2009, we have budgeted approximately $200 million for capital and exploration expenditures in the region.

At December 31, 2008, we had 3,382 wells (3,162.6 net), of which 3,268 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian (including Marcellus) Shale formations at depths primarily ranging from 1,100 to 9,500 feet, with an average depth of approximately 4,100 feet. Average net daily production in 2008 was 69.1 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2008 was 25.2 Bcf and 23 Mbbls, respectively.

While natural gas production volumes from East reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of East region reserves is relatively long. At December 31, 2008, we had 871.8 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 45% of our total proved reserves. Developed and undeveloped reserves made up 613.4 Bcfe and 258.4 Bcfe of the total proved reserves for the East 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.

 

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In 2008, we drilled 212 wells (205.4 net) in the East region, of which 208 wells (201.4 net) were development and extension wells. In 2009, we plan to drill approximately 63 wells (62.8 net), primarily in the Dimock field.

In 2008, we produced and marketed approximately 62 barrels of crude oil/condensate/NGL per day in the East region at market responsive prices.

Ancillary to our exploration, development and production operations, we operated a number of gas gathering and transmission pipeline systems, made up of approximately 3,200 miles of pipeline with interconnects to three interstate transmission systems, seven local distribution companies and numerous end users as of the end of 2008. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.

We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The storage fields also enable us to increase for shorter intervals of time the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the East region. The pipeline systems and storage fields are fully integrated with our operations.

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

Approximately 70% of our natural gas sales volume in the East region is sold at index-based prices under contracts with a term of one year or greater. In addition, spot market sales are made at index-based prices under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts. Approximately one percent of East production is sold on fixed price contracts that typically renew annually.

GULF COAST REGION

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in east and south Texas and north Louisiana. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Haynesville and James Lime formations in north Louisiana and east Texas and the Frio, Vicksburg and Wilcox formations in south Texas at depths ranging from 2,200 to 17,400 feet, with an average depth of approximately 10,900 feet.

Capital and exploration expenditures were $962.0 million for 2008, or 64% of our total 2008 capital and exploration expenditures, compared to $291.5 million for 2007, or 46% of our total 2007 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 attributable to an increase in the Gulf Coast region spending. For 2009, we have budgeted approximately $230

 

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million for capital and exploration expenditures in the region. Our 2009 Gulf Coast drilling program will emphasize activity primarily in east Texas.

We had 844 wells (592.2 net) in the Gulf Coast region as of December 31, 2008, of which 633 wells are operated by us. Average daily production in 2008 was 104.1 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2008 was 34.6 Bcf and 585 Mbbls, respectively.

At December 31, 2008, we had 554.6 Bcfe of proved reserves (93% natural gas) in the Gulf Coast region, which represented 29% of our total proved reserves. Developed and undeveloped reserves made up 317.3 Bcfe and 237.3 Bcfe of the total proved reserves for the Gulf Coast 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, we drilled 94 wells (63.9 net) in the Gulf Coast region, of which 83 wells (57.1 net) were development and extension wells. In 2009, we plan to drill 65 wells (47.4 net), primarily in east Texas, including the Minden and County Line fields.

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

In 2008, we produced and marketed approximately 1,598 barrels of crude oil/condensate/NGL per day in the Gulf Coast region at market responsive prices.

WEST REGION

Our activities in the West region, which is comprised of the Rocky Mountains and Mid-Continent areas, are managed by a regional office in Denver, Colorado. At December 31, 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.

 

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Rocky Mountains

Activities in the Rocky Mountains are concentrated in the Green River and Washakie Basins in Wyoming and Paradox Basin in Colorado. At December 31, 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 2008 was 41.3 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2008 was 14.5 Bcf and 95 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

 

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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 2008 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 2007 and 2006, we primarily employed price collars to hedge our price exposure on our production. 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 for the period is greater or less than the fixed price established for that period when the swap is put in place.

For 2008, collars covered 60% 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% 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 per Mcf and $11.43 per Mcf, respectively. For 2008, a swap covered 12% 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 in the benefit of high 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).

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.

 

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Index to Financial Statements

RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2008.

 

    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
                                   

 

(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.

The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents concluded the following: In their judgment we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues; we used appropriate engineering, geologic and evaluation principles and techniques in accordance with practices generally accepted in the petroleum industry in making our estimates and projections and our total proved reserves are reasonable. For additional information regarding estimates of proved reserves, the review 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 review letter by Miller and Lents, Ltd. 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 economic producing rates. Our reserves are based on oil and gas index prices in effect on the last day of December 2008.

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.

 

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Historical Reserves

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

 

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

December 31, 2005

   1,262,096     11,463     1,330,874  
                  

Revision of Prior Estimates(2)

   (17,675 )   673     (13,640 )

Extensions, Discoveries and Other Additions

   246,197     1,066     252,594  

Production

   (79,722 )   (1,415 )   (88,212 )

Purchases of Reserves in Place

   1,946     38     2,176  

Sales of Reserves in Place

   (44,549 )   (3,852 )   (67,663 )
                  

December 31, 2006

   1,368,293     7,973     1,416,129  
                  

Revision of Prior Estimates

   2,604     771     7,228  

Extensions, Discoveries and Other Additions

   265,830     1,381     274,114  

Production

   (80,475 )   (830 )   (85,451 )

Purchases of Reserves in Place

   3,701     33     3,899  

Sales of Reserves in Place

   —       —       —    
                  

December 31, 2007

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

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 )
                  

December 31, 2008

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

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  

December 31, 2008

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

 

(1)

Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas 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.

 

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Volumes and Prices: Production Costs

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

 

(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, but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration and development expenditures.

 

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Acreage

The following tables summarize our gross and net developed and undeveloped leasehold and mineral acreage at December 31, 2008. 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
                             

 

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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
              

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. 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
              

Well Summary

The following table presents our ownership at December 31, 2008, in productive natural gas and oil wells in the East 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). 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
                             

 

(1)

Total does not include service wells of 54 (52.2 net).

 

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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
     East    Gulf Coast    West    Canada    Total
     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

Dry

   1    1.0    4    3.8    3    2.5    1    0.6    9    7.9

Extension Wells

                             

Successful

   3    3.0    1    1.0    1    0.7    —      —      5    4.7

Dry

   1    1.0    —      —      —      —      —      —      1    1.0

Exploratory Wells

                             

Successful

   3    3.0    11    6.8    —      —      2    0.8    16    10.6

Dry

   1    1.0    —      —      2    0.5    —      —      3    1.5
                                                 

Total

   212    205.4    94    63.9    120    81.9    6    3.4    432    354.6
                                                 

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

 

     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

 

     Year Ended December 31, 2006
     East    Gulf Coast    West    Canada    Total
     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

Dry

   2    2.0    2    1.9    3    2.3    1    0.2    8    6.4

Extension Wells

                             

Successful

   —      —      10    9.7    1    0.1    —      —      11    9.8

Dry

   —      —      —      —      —      —      1    0.7    1    0.7

Exploratory Wells

                             

Successful

   2    2.0    8    6.2    —      —      2    0.8    12    9.0

Dry

   1    0.7    4    3.2    2    1.7    1    1.0    8    6.6
                                                 

Total

   200    190.7    64    50.8    113    60.1    10    5.4    387    307.0
                                                 

Wells Acquired

   5    5.0    —      —      —      —      1    0.4    6    5.4

Wells in Progress at End of Year

   —      —      4    3.9    1    0.5    2    1.3    7    5.7

 

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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 East region our extensive acreage position, existing natural gas gathering and pipeline systems, services and equipment that we have secured for the upcoming year and storage fields enhance our competitive position over other producers who do not have similar systems or facilities in place. We also actively compete against other companies with substantially larger financial and other resources.

OTHER BUSINESS MATTERS

Major Customer

In 2008, one customer accounted for approximately 16% of our total sales. In 2007 and 2006, no customer accounted for more than 10% of our 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 provisions of the Energy Policy Act of 2005, the NGA has been amended to prohibit any forms of market

 

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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.

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. We have completed 100% of the required initial inspection (baseline assessment) 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. In September 2008, as mandated by this statute, DOT issued a Notice of Proposed Rulemaking to establish new rules that would require pipeline operators 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.

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

 

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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, 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 1.3 percent should be the oil pricing index for the five-year period beginning July 1, 2006. 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 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.

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. 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

 

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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 strict 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. 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. 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. 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. 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 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.

Employees

As of December 31, 2008, we had 560 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

 

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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 at www.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 at www.cabotog.com, under the “Corporate Governance” section of “Investor Relations” and a copy will be provided, without charge, to any shareholder upon request. Requests can also be made in writing to Investor Relations at our corporate headquarters at 1200 Enclave Parkway, 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.

 

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 price have declined from approximately $13 per Mmbtu in July 2008 to approximately $4.50 per Mmbtu as of February 1, 2009. Oil prices have declined from record levels in July 2008 of approximately $145 per barrel to approximately $40 per barrel as of February 1, 2009. 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;

 

   

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;

 

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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.

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

 

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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 prices 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 in Statement of Financial Accounting Standards No. 69 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, 2008 will decline at estimated rates of 21%, 17%, 12% and 11% during 2009, 2010, 2011 and 2012, 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.

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

 

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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.

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 risks. As of December 31, 2008, we owned or operated approximately 3,500 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.

 

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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.

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% of our total owned gross wells, or approximately 4.8% of our owned net wells, as of December 31, 2008. 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.

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.

 

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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 2008 we employed natural gas and crude oil price collar and swap agreements covering portions of our 2008 production and anticipated 2009 and 2010 production to attempt to manage price risk more effectively. 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 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.

 

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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 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.

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 incorporation 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.”

 

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ITEM 3. LEGAL PROCEEDINGS

We are a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings 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 impacted in the reporting periods in which such matters are resolved.

Commitment and Contingency Reserves

When deemed necessary, we establish 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 we 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 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 impacted in the reporting periods in which such matters are resolved.

 

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

No matters were submitted to a vote of security holders during the fourth quarter of 2008.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information as of February 15, 2009 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

Dan O. Dinges

   55    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

J. Scott Arnold

   55    Vice President, Land and General Counsel    1998

Robert G. Drake

   61   

Vice President, Information Services and Operational Accounting

   1998

Abraham D. Garza

   62    Vice President, Human Resources    1998

Jeffrey W. Hutton

   53    Vice President, Marketing    1995

Thomas S. Liberatore

   52    Vice President, Regional Manager, East Region    2003

Lisa A. Machesney

   53   

Vice President, Managing Counsel and Corporate Secretary

   1995

Henry C. Smyth

   62    Vice President, Controller and Treasurer    1998

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.

 

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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

2008

        

First Quarter

   $ 53.41    $ 37.67    $ 0.03

Second Quarter

   $ 71.11    $ 51.48    $ 0.03

Third Quarter

   $ 68.58    $ 33.58    $ 0.03

Fourth Quarter

   $ 33.83    $ 21.31    $ 0.03

2007

        

First Quarter

   $ 35.29    $ 28.06    $ 0.02

Second Quarter

   $ 41.88    $ 34.55    $ 0.03

Third Quarter

   $ 38.39    $ 31.55    $ 0.03

Fourth Quarter

   $ 40.90    $ 33.59    $ 0.03

As of January 31, 2009, there were 544 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, we did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of shares that may yet be purchased under the plan as of December 31, 2008 was 4,795,300.

 

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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 2003 through December 2008. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2003 and that all dividends were reinvested.

LOGO

 

Calculated Values

   2003    2004    2005    2006    2007    2008

S&P 500

   100.0    110.9    116.3    134.7    142.1    89.5

COG

   100.0    151.4    232.4    313.5    418.7    270.5

Dow Jones US Exploration & Production

   100.0    141.9    234.5    247.1    355.1    212.6

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.

 

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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,  
      2008    2007    2006    2005    2004  
     (In thousands, except per share amounts)  

Statement of Operations Data

              

Operating Revenues

   $ 945,791    $ 732,170    $ 761,988    $ 682,797    $ 530,408  

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

     35,700      4,614      3,886      —        3,458  

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

     1,143      13,448      232,017      74      (124 )

Gain on Settlement of Dispute(3)

     51,906      —        —        —        —    

Income from Operations

     372,012      274,693      528,946      258,731      160,653  

Net Income

     211,290      167,423      321,175      148,445      88,378  

Basic Earnings per Share(4)

   $ 2.10    $ 1.73    $ 3.32    $ 1.52    $ 0.91  

Diluted Earnings per Share(4)

   $ 2.08    $ 1.71    $ 3.26    $ 1.49    $ 0.90  

Dividends per Common Share(4)

   $ 0.120    $ 0.110    $ 0.080    $ 0.074    $ 0.054  

Balance Sheet Data

              

Properties and Equipment, Net

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

Total Assets

     3,701,664      2,208,594      1,834,491      1,495,370      1,210,956  

Current Portion of Long-Term Debt

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

Long-Term Debt

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

Stockholders’ Equity

     1,790,562      1,070,257      945,198      600,211      455,662  

 

(1)

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

(2)

Gain on Sale of Assets for 2007 and 2006 reflects $12.3 million and $231.2 million, respectively, related to disposition 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 dispute settlement includes the value of cash and properties received. See Note 7 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.

 

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.

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.

 

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OVERVIEW

Cabot Oil & Gas and its subsidiaries are a leading independent oil and gas company engaged in the development, exploitation, exploration, production and marketing of natural gas, and to a lesser extent, crude oil and natural gas liquids from its properties in North America. 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 are 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 per Mcf and $89.11 per Bbl, respectively, in 2008. These realized prices include the realized impact of derivative instruments. In an effort to manage commodity price risk, we entered into a series of crude oil and natural gas price swaps and collars. These financial instruments are an important element of our risk management strategy and assisted in the increase in our realized natural gas price from 2007 to 2008.

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 tables below illustrate how natural gas prices have fluctuated by month over 2007 and 2008. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2007” and “2008” 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, as applicable:

 

     Natural Gas Prices by Month - 2008
     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

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
     Natural Gas Prices by Month - 2007
     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

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

 

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Prices for crude oil maintained strength in 2007 and rose to record high levels in 2008, but experienced significant declines in the fourth quarter of 2008. The tables below contain the NYMEX monthly average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 2007 and 2008. The “2007” and “2008” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative arrangements:

 

    Crude Oil Prices by Month - 2008
    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

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
    Crude Oil Prices by Month - 2007
    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

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

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 increased from 2007 to 2008 as a result of favorable natural gas hedge settlements, increased commodity market prices and increased natural gas production. Crude oil revenues increased from 2007 to 2008 primarily due to increased realized prices, partially offset by a reduction in crude oil production. Prices, including the realized impact of derivative instruments, increased by 16% for natural gas and 33% for oil.

We drilled 432 gross wells with a success rate of 97% in 2008 compared to 461 gross wells with a success rate of 96% in 2007. Total capital and exploration expenditures increased by $844.8 million to $1,481.0 million (including the east Texas acquisition) in 2008 compared to $636.2 million in 2007. We believe our cash on hand and operating cash flow in 2009 will be sufficient to fund our budgeted capital and exploration spending of approximately $475 million. Any additional needs will 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 2009 strategy will remain consistent with 2008. 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 manage our balance sheet in an effort to ensure that we have sufficient liquidity, and we intend to maintain spending discipline. In the current year we have allocated our planned program for capital and exploration expenditures primarily to the East and Gulf Coast regions. 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 2008 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, borrowings under our revolving credit facility and asset sales. 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 dividends and debt issuance costs. See below for additional discussion and analysis of cash flow.

 

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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.

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, we believe we have adequate liquidity available to meet our working capital requirements.

 

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

Cash Flows Provided by Operating Activities

   $ 634,447     $ 462,137     $ 357,104  

Cash Flows Used in Investing Activities

     (1,452,289 )     (589,922 )     (187,353 )

Cash Flows 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  
                        

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 increased by $172.3 million over 2007. This increase was mainly due to an increase in net income, the receipt of cash of $20.2 million in 2008 in connection with the settlement of a dispute and an increase of $13.7 million in cash received for income tax refunds. In addition, cash flows from operating activities increased as a result of other working capital changes. Average realized natural gas prices increased by 16% in 2008 over 2007 and average realized crude oil prices increased by 33% over the same period. Equivalent production volumes increased by 11% in 2008 compared to 2007 as a result of 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 be lower in 2009.

Net cash provided by operating activities in 2007 increased by $105.0 million over 2006. This increase 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 Louisiana and offshore properties sale, as well as our 2007 tax net operating loss position and the receipt in 2007 of $29.6 million in federal tax refunds relating to our 2006 tax return. Average realized natural gas prices increased by one percent in 2007 over 2006 and average realized crude oil prices increased by three percent over the same period. Equivalent production decreased by three percent in 2007 compared to 2006 as a result of a decrease in 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. Due to the volatility of commodity prices and new opportunities which may arise, our capital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased by $862.4 million from 2007 to 2008 and increased by $402.6 million from 2006 to 2007. The increase from 2007 to 2008 was due

 

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to an increase of $866.0 million in capital expenditures, including an increase of approximately $601.8 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.

The increase in cash flows used in investing activities from 2006 to 2007 was due to a decrease of $322.4 million in 2007 in proceeds from the sale of assets and an increase of $89.8 million in 2007 in capital expenditures, partially offset by reduced exploration expenses of $9.6 million.

Financing Activities. Cash flows provided by financing activities increased by $723.0 million from 2007 to 2008. This was primarily due to an increase in debt consisting of our July 2008 and December 2008 private placements of debt ($492 million) and an increase of $45 million in borrowings under our revolving credit facility. Additionally, net proceeds from the sale of common stock increased by $311.1 million primarily due to the June 2008 issuance of common stock. The tax benefit for stock-based compensation increased by $10.7 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 $243.0 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 for stock-based compensation, lower proceeds from the exercise of stock options and higher dividend payments.

At December 31, 2008, we had $185 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of 3.7%. In December 2008, the revolving credit facility was amended to extend the commitment period for lenders holding approximately 90% of the aggregate commitments from December 2009 to October 2010. The December amendment added an accordion feature to allow us, if the existing banks or new banks agree, to increase the available credit line from $350 million to $450 million. 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) and other assets. 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 that we have the capacity to finance our spending plans and maintain our liquidity. At the same time, we will closely monitor the capital markets. As a result of market conditions and our increased level of borrowings, we may experience increased costs associated with future debt.

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.

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.

 

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Capitalization

Information about our capitalization is as follows:

 

     December 31,  
      2008     2007  
     (Dollars in millions)  

Debt(1)

   $ 867.0     $ 350.0  

Stockholders’ Equity

     1,790.6       1,070.3  
                

Total Capitalization

   $ 2,657.6     $ 1,420.3  
                

Debt to Capitalization

     33 %     25 %

Cash and Cash Equivalents

   $ 28.1     $ 18.5  

 

(1)

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

For the year ended December 31, 2008, we paid dividends of $12.1 million 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, 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.

 

      2008    2007    2006
     (In millions)

Capital Expenditures

        

Drilling and Facilities(1)

   $ 624.3    $ 539.7    $ 405.5

Leasehold Acquisitions

     152.7      22.2      42.6

Acquisitions

     625.0      4.0      6.7

Pipeline and Gathering

     36.9      28.2      24.2

Other

     10.9      2.3      9.1
                    
     1,449.8      596.4      488.1

Exploration Expense

     31.2      39.8      49.4
                    

Total

   $ 1,481.0    $ 636.2    $ 537.5
                    

 

(1)

Includes Canadian currency translation effects of $(27.7) million, $15.0 million and $(1.4) million in 2008, 2007 and 2006, respectively.

We plan to drill approximately 148 gross wells (122.3 net) in 2009 compared with 432 gross wells (355 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. This 2009 drilling program includes approximately $475 million in total capital and exploration expenditures, down from $1,481 million in 2008. 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.

 

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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, management expects an increase in our DD&A rate due to higher capital costs, partially as a result of inflationary cost pressures in the industry over the last four years. This change is currently estimated to be approximately 13% greater than 2008 levels. This increase will 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, 2008 are set forth in the following table:

 

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

Long-Term Debt(1)

   $ 867,000    $ 35,857    $ 244,143    $ 75,000    $ 512,000

Interest on Long-Term Debt(2)

     460,624      63,124      99,602      82,469      215,429

Firm Gas Transportation Agreements(3)

     94,670      13,218      23,935      13,374      44,143

Drilling Rig Commitments(3)

     44,271      42,021      2,250      —        —  

Operating Leases(3)

     28,686      6,335      9,028      7,397      5,926
                                  

Total Contractual Cash Obligations

   $ 1,495,251    $ 160,555    $ 378,958    $ 178,240    $ 777,498
                                  

 

(1)

Including current portion. At December 31, 2008, we had $185 million of debt outstanding under our revolving credit facility. See Note 4 of the Notes to the Consolidated Financial Statements for details of long-term debt.

(2)

Interest payments have been calculated utilizing the fixed rates of our $682 million long-term debt outstanding at December 31, 2008. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2008 long-term outstanding balance of $169.1 million will be outstanding through the October 2010 maturity date and that the short-term outstanding balance of $15.9 million will be outstanding through December 2009. A constant interest rate of 4.8% was assumed, which was the 2008 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 7 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, 2008 was $28.0 million, up from $24.7 million at December 31, 2007, primarily due to $1.2 million of accretion expense during 2008 as well as $2.2 million of drilling additions.

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. The most significant policies are discussed below.

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,

 

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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% of our reserves have been reviewed by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm, 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 reserves, which is 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-economic 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 to $0.10 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 to $0.06 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.” 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-lease 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 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.

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 regional 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, commodity prices declined at a significant rate as the global economy struggled with a worldwide recession. This price environment has resulted in reduced capital available for exploration projects as well as development drilling. We have considered these impacts discussed above when assessing the impairment 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 million or decrease by approximately $10.7 million, respectively per year.

 

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In the past, the average leasehold life in the Gulf Coast region has been shorter than the average life in the East and West regions. Average property lives in the East, Gulf Coast and West regions have been five, four and seven 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 program.

Accounting for Derivative Instruments and Hedging Activities

We follow the accounting prescribed in SFAS No. 133. Under SFAS No. 133, 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, 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, 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 balance 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. Such quotes have been derived using a Black-Scholes model for the active oil and gas commodities market that considers 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 utilize 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 our counterparties to take into account either the counterparties’ nonperformance risk or our own nonperformance

 

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risk. We measured the nonperformance risk of our counterparties by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions and made a reduction to our derivative receivable. 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.

Long-Term Employee Benefit Costs

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 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 value our 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 assumed 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 from the expected rate due 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. One 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.

 

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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.

Stock-Based Compensation

We account for stock-based compensation under a fair value based method of accounting for stock options and similar equity instruments. Under the fair value method, compensation cost is measured at the grant date based on the 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.

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

 

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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 Note 10 of the Notes to the Consolidated Financial Statements.

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

 

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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. Our senior notes require us to maintain a ratio of cash and proved reserves to indebtedness and other liabilities of 1.5 to 1.0. At December 31, 2008, 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, 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.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results.

The majority of our production is sold at market responsive prices. Generally, if the commodity indexes fall, 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 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

In December 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” which amends the oil 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 price 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 our financial position, results of operations or cash flows.

 

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In June 2008, 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 rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. FSP No. EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and 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 03-6-1 will have a material 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 our financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2008.

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,”

 

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“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 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

2008 and 2007 Compared

We reported net income for the year ended December 31, 2008 of $211.3 million, or $2.10 per share. During 2007, we reported net income of $167.4 million, or $1.73 per share. This increase of $43.9 million in net income was primarily due to an increase in operating revenues and gains on asset sales and settlements, partially offset by increased operating, interest and income tax expenses. Operating revenues increased by $213.6 million, largely due to increases in both natural gas production revenues and brokered natural gas revenues and crude oil and condensate revenues. Operating expenses increased by $155.9 million between periods due to increases in all categories of operating expenses other than exploration expense. In addition, net income was impacted by an increase in gain on sale of assets 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.

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 %
                       

 

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     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 increase in Natural Gas Production Revenue of $177.1 million is due to the increase in realized natural gas sales prices in addition to an increase in natural gas production. Natural gas production in the Gulf Coast region increased due to increased production in the Minden field, largely due to the properties we acquired in east Texas in August 2008, as well as increased drilling 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.

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)

   x 10,996     x 11,101      (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)

   x 10,996     x 11,101      (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 )       
               

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

 

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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.

 

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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.

Operating Expenses

Total costs and expenses from operations increased by $155.9 million in 2008 from 2007. The primary reasons for this fluctuation are as follows:

 

   

Depreciation, Depletion and Amortization increased by $41.5 million from 2007 to 2008. This is primarily due to the impact on the DD&A rate of higher capital costs and higher natural gas production volumes, including the east Texas acquisition.

 

   

Impairment of Oil & Gas Properties and Other Assets increased by $31.1 million from 2007 to 2008 primarily 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 prices 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.

 

   

General and Administrative expenses increased by $23.4 million from 2007 to 2008. This is primarily due to increased 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 costs in several exploratory and developmental areas, as well as a $17.0 million charge for the impairment of three exploratory oil and gas prospects located 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.

 

   

Brokered Natural Gas Cost increased by $18.6 million from 2007 to 2008. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

 

   

Direct Operations expenses increased by $14.6 million from 2007 to 2008 primarily due to higher personnel and labor expenses, maintenance expenses, treating, compressor, pipeline and workover costs and vehicle and fuel expenses, partially offset by lower insurance costs.

 

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Taxes Other Than Income increased by $12.8 million from 2007 to 2008 due to higher production taxes as a result of higher operating revenues and, to a lesser extent, higher ad valorem taxes, partially offset by lower franchise taxes.

 

   

Exploration expense decreased by $8.6 million from 2007 to 2008 primarily due to fewer dry holes, partially offset by increased geological and geophysical costs.

Interest Expense, Net

Interest expense, net increased by $19.2 million in 2008 compared to 2007 primarily due to increased interest expense related to the debt we issued 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 were approximately $172 million during 2008 compared to approximately $52 million during 2007. The weighted-average effective interest rate on the credit facility decreased to 4.8% during 2008 from 7.2% during 2007.

Income Tax Expense

Income tax expense increased by $34.2 million due to a comparable increase in our pre-tax income. The effective tax rates for 2008 and 2007 were 37.0% and 35.0%, respectively. The increase in the effective tax rate is primarily due to a one time benefit for state taxes in 2007 of approximately $2.8 million attributable to favorable treatment of the gain from the sale of south Louisiana 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 income of $254.2 million resulting from the gain on sale of assets of $231.2 million included in 2006 related to the 2006 south Louisiana and offshore properties sale, partially offset by a $99.2 million decrease in income tax expense and 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 an 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. The increase in operating expenses was primarily the result of increased DD&A and impairment expenses, offset in part by reduced exploration and general and administrative expenses.

 

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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 is due to an increase in realized natural gas sales prices as well as increased natural gas production. Natural gas revenues increased in 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 with 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.

 

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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)

   x 11,101     x 11,502      (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)

   x 11,101     x 11,502      (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         
               

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

 

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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 the 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.

 

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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,
     2007    2006
      Realized     Unrealized    Realized    Unrealized
     (In thousands)

Operating Revenues—Increase / (Decrease) to Revenue

          

Cash Flow Hedges

          

Natural Gas Production

   $ 79,838     $ —      $ 28,266    $ —  

Crude Oil

     (796 )     —        —        —  
                            

Total Cash Flow Hedges

   $ 79,042     $ —      $ 28,266    $ —  
                            

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.

Operating Expenses

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

 

   

Depreciation, Depletion and Amortization increased by $14.9 million in 2007 over 2006. 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 of production in an east Texas field.

 

   

Exploration expense decreased by $9.6 million from 2006 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, primarily due to a decrease in the Gulf Coast region, 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 2006 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 change in the liability component of the awards resulting from the variance in our relative ranking from 2006 to 2007 as well as a reduction 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.

 

   

Taxes Other Than Income decreased by $1.5 million for 2007 compared to 2006, primarily due to decreased production taxes of $3.3 million as a result of decreased commodity volumes and prices as well as decreased franchise taxes, partially offset by an increase in ad valorem taxes.

 

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Impairment of Oil & Gas Properties and Other Assets increased by $0.7 million for the year ended December 31, 2007 compared to the year ended December 31, 2006, due to an impairment recorded in 2007 in the Gulf Coast region resulting from two non-commercial development completions in a small field in north Louisiana.

Interest Expense, Net

Interest expense, net decreased by $1.1 million in 2007 compared to 2006 due to a lower weighted-average interest rate on borrowings under our revolving credit facility, a lower outstanding principal amount of our 7.19% fixed rate debt 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. Weighted-average borrowings under our credit facility based on daily balances were approximately $52 million during 2007 compared to approximately $61 million during 2006. The weighted-average effective interest rate on the credit facility decreased to 7.2% during 2007 from 7.9% 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.

Income Tax Expense

Income tax expense decreased by $99.2 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. The effective tax rates for 2007 and 2006 were 35.0% and 37.1%, respectively. The decrease in the effective tax rate is primarily due to a reduction in our overall state income tax rate for 2007.

 

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 debt and equity markets have recently experienced unfavorable conditions, which may affect our ability to access those markets. As a result of the volatility and disruption in the capital markets and our increased level of borrowings, we may experience increased costs associated with future borrowings and debt issuances. 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 11 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

 

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management policies and not subjecting us to material speculative risks. At December 31, 2008, we 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, 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, we 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, 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—Swaps

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, natural gas price swaps covered 9,821 Mmcf, or 11%, of our 2008 gas production at an average price of $10.27 per Mcf. During 2008, we entered into natural gas price swaps covering a portion of our anticipated 2008, 2009 and 2010 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.

 

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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 to 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.

We are 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 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 reduction of $5.1 million related to our assessment 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.

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. 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

 

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and the year- 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 to new issues (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 the credit facility, are based on interest rates currently available to 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.

Long-Term Debt

 

     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  
                                

 

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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

 

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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”) at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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, 2008, based on criteria established in Internal 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.

As discussed in Note 11 to the consolidated financial statements, the Company changed the manner in which it accounts for 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.

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 27, 2009

 

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

 

     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.

 

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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.

 

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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.

 

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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