Back to GetFilings.com

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2005

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

1200 Enclave Parkway, Houston, Texas 77077

(Address of principal executive offices including Zip Code)

(281) 589-4600

(Registrant’s telephone number)

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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  x    No  ¨

As of April 27, 2005, there were 48,922,599 shares of Common Stock, Par Value $.10 Per Share, outstanding.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)

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

- 3 -

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

(In thousands, except share amounts)

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

- 4 -

CABOT OIL & GAS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

(In thousands)

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

- 5 -

CABOT OIL & GAS CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies used in its Annual Report to Stockholders and its Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission. People using financial information produced for interim periods are encouraged to refer to the footnotes in the Annual Report on Form 10-K for the year ended December 31, 2004 when reviewing interim financial results. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.

Our independent registered public accounting firm has performed a review of these condensed consolidated interim financial statements in accordance with standards established by the Public Company Accounting Oversight Board (United States). Pursuant to Rule 436(c) under the Securities Act of 1933, this report should not be considered a part of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meanings of Sections 7 and 11 of the Act.

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the Common Stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.

Recently Issued Accounting Pronouncements

In December 2004, the Financial Accounting Standard Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123R, “Share-Based Payment.” SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the SEC approved a new rule for public companies which delays the adoption of this standard. The provisions of SFAS 123R are now effective for annual rather than interim periods that begin after June 15, 2005. As a result, the Company will not adopt this SFAS until the first quarter of 2006. The Company is currently evaluating the method of adoption and the impact on the Company’s operating results. Future cash flows of the Company will not be impacted by the adoption of this standard. See “Stock Based Compensation” below for further information.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures

- 6 -

should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in this FSP is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The Company provided the disclosure requirements of this FSP in its Annual Report on Form 10-K for the year ended December 31, 2004 and will continue to provide the disclosures required by the FSP in the interim filings with the SEC. For interim financial statements, only information about significant changes from the information presented in the most recent annual financial statements is required. As of March 31, 2005, the Company did not have any significant changes as defined in the Staff Position from year end.

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a Company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company does not believe that its financial position, results of operations or cash flows will be impacted by this Interpretation.

Stock Based Compensation

The Company accounts for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Under the intrinsic value based method, compensation cost is the excess, if any, of the quoted market price of the stock at grant date over the amount an employee must pay to acquire the stock.

SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments.

The following table illustrates the effect on Net Income and Earnings per Share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation. The Earnings per Share amounts for prior periods have been retroactively adjusted to reflect the 3-for-2 split of the Company’s Common Stock effective March 31, 2005.

- 7 -

The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.

The fair value of stock options included in the pro forma results for each of the periods presented is not necessarily indicative of future effects on Net Income and Earnings per Share.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:

3. INVENTORIES

Inventories are comprised of the following:

Natural gas and oil in storage is valued at average cost. Tubular goods and well equipment is valued at historical cost. All inventory balances are carried at the lower of cost or market.

- 8 -

4. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

- 9 -

5. LONG–TERM DEBT

At March 31, 2005, the Company did not have any debt outstanding under its Revolving Credit Agreement (Credit Facility), which provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. To expand the credit line, the Company must seek prior approval from the administrative agent and the bank whose commitment is increasing. The term of the Credit Facility expires in December 2009. The Credit Facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.

The Company has the following debt outstanding at March 31, 2005:

6. EARNINGS PER SHARE

Basic Earnings per Share (EPS) is computed by dividing Net Income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated using the treasury stock method except that the denominator is increased to reflect the potential dilution that could occur if outstanding stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.

The following is a calculation of basic and diluted weighted average shares outstanding for the three months ended March 31, 2005 and 2004.

- 10 -

7. COMMITMENTS AND CONTINGENCIES

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are fully accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s consolidated financial position. Operating results and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Wyoming Royalty Litigation

In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification. The plaintiffs alleged that the Company improperly deducted costs from their overriding royalty interests. Further, the suit alleged the Company had failed to properly report information required to be reported by a Wyoming statute. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. The Company settled the case on a class basis for a total of $2.25 million. The State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. The class included all private fee royalty and overriding royalty owners of the Company in the State of Wyoming except those in the suit discussed below and one owner who opted out of the settlement. The settlement included provisions for the method of valuation of gas for royalty payment purposes going forward and for reporting of royalty payments, which should prevent further litigation of these issues by the class members.

In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court. The plaintiffs in the case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court but have not asked for class certification. The federal district court judge certified two questions of state law for decision by the Wyoming State Supreme Court, which recently answered both questions. The Wyoming Supreme Court ruled that certain deductions taken by the Company from the plaintiffs were not proper and that the statutes of limitations advanced by the Company are discovery statutes and accordingly do not begin to run until the plaintiffs knew, or had reason to know, of the violation. The Company believes it has properly reported to the plaintiffs, and that if it did not, the plaintiffs knew or should have known the reporting was improper and the nature of the deductions, thus triggering the statute of limitations. The Company is vigorously defending the alleged failure to report claims and the deduction claims. There is also a dispute as to how the interest should be calculated.

Based upon recent communication from the plaintiffs they are claiming $26.2 million in total damages which consists of $20.3 million for alleged violations of the check stub reporting statute and $5.9 million for all other damages. A motion was made to strike Plaintiffs’ expert witness on damages. The judge issued the order to strike the witness’s report and not allow his testimony. This case was set for trial beginning May 2, 2005, but the judge recently continued this case indefinitely.

In the opinion of our outside counsel, Brown, Drew & Massey, LLP, the likelihood of the plaintiffs recovering $20.3 million for the check stub reporting statute is remote. However, a reserve that management believes is adequate to provide for the check stub reporting statute and all other damages has been established based on management’s estimate at this time of the probable outcome of this case.

West Virginia Royalty Litigation

In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification and allege that the Company failed to pay royalty based upon the wholesale market value of the gas, that it had taken improper deductions from the royalty and failed to properly inform royalty owners of the deductions. The plaintiffs have also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.

- 11 -

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The court has not yet ruled on the class certification motion. Discovery cutoff and the deadline for dispositive motions has been extended to June 1, 2005, and the trial is currently scheduled for August 15, 2005. If a class is certified, it is expected this trial date will be continued to a later date.

The Company is vigorously defending the case. It has a reserve that management believes is adequate based on its estimate of the probable outcome of this case.

Texas Title Litigation

On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs have amended their petition several times. The plaintiffs now allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998, and the Company subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. The Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title and since the Company acquired its lease is approximately $15.1 million, and that the carrying value of this property is approximately $34 million.

Although the investigation into this claim is in its early stages, the Company intends to vigorously defend the case. Should the Company receive an adverse ruling in this case, an impairment review would be assessed to ensure the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

Raymondville Area

In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody proposed a new prospect under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

The working interest owners who elected not to participate notified Cody that they believed that they had the right to participate in wells drilled after the initial well. Cody contends that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. Alternatively, Cody contends that such owners lost their right to participate in subsequent wells within a 1,200 foot radius of the initial well.

Cody and the defendants have each filed motions for summary judgment. The Company is awaiting a ruling by the Court. Trial has been set for mid-November.

Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

- 12 -

Commitment and Contingency Reserves

The Company has established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur approximately $12.5 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position of the Company. Operating results and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. At March 31, 2005, the Company had 13 cash flow hedges open: 5 natural gas price collar arrangements, 1 crude oil price collar and 7 natural gas price swap arrangements. Additionally, the Company had 2 crude oil financial instruments open at March 31, 2005, that did not qualify for hedge accounting. At March 31, 2005, a $59.4 million ($36.8 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $73.6 million derivative liability. The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. 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.

Assuming no change in commodity prices, after March 31, 2005, the Company would reclassify to earnings, over the next 12 months, $36.8 million in after-tax expenditures associated with commodity derivatives. This reclassification represents the net liability associated with open positions currently not reflected in earnings at March 31, 2005 related to remaining anticipated 2005 production.

From time to time, the Company enters into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At March 31, 2005, the fair value of the Company’s 2 open crude oil swap arrangements was $12.4 million, and is reported as a component of Derivative Contracts in the liability section of the accompanying Condensed Consolidated Balance Sheet. The change in fair value of these oil swaps totaling $6.8 million for the three months ended March 31, 2005 has been reported as a component of Operating Revenues in the accompanying Condensed Consolidated Statement of Operations.

- 13 -

9. COMPREHENSIVE INCOME

Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the three month periods ended March 31, 2005 and 2004.

Deferred income tax of $10.8 million at March 31, 2005 represents the net deferred tax liability of ($2.4) million on the Reclassification Adjustment for Settled Contracts, $14.0 million on the Changes in Fair Value of Hedge Positions, ($0.8) million on the minimum pension liability adjustment and less than $0.1 million on the Foreign Currency Translation Adjustment.

Deferred income tax of $8.8 million at March 31, 2004 represents the net deferred tax liability of ($2.4) million on the Reclassification Adjustment for Settled Contracts, $11.2 million on the Changes in Fair Value of Hedge Positions, and less than $0.1 million on the Foreign Currency Translation Adjustment.

10. ASSET RETIREMENT OBLIGATIONS

The following table reflects the changes of the asset retirement obligations during the three months ended March 31, 2005:

Accretion expense was $0.4 million and $0.5 million for the three months ended March 31, 2005 and 2004, respectively.

- 14 -

11. PENSION AND OTHER POSTRETIREMENT BENEFITS

The components of net periodic benefit costs for the three months ended March 31, 2005 and 2004 are as follows:

In 2005, the Company does not have any required minimum funding obligations for its qualified pension plan. Currently, management has not determined if a discretionary funding will be made in 2005.

- 15 -

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the Company) as of March 31, 2005, and the related condensed consolidated statement of operations for each of the three month periods ended March 31, 2005 and 2004 and the condensed consolidated statement of cash flows for the three month periods ended March 31, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated balance sheet as of December 31, 2004 and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report dated March 2, 2005, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

April 29, 2005

- 16 -

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following review of operations for the first quarter of 2005 and 2004 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Form 10-K for the year ended December 31, 2004.

Overview

In the first three months of 2005, we produced 21.1 Bcfe compared to production of 20.9 Bcfe for the comparable period of the prior year. Natural gas production was 18.4 Bcf and oil production was 450 Mbbls for the first three months of 2005. Natural gas production in the current period increased by 0.7 Bcf from the same period in 2004. The increase in our natural gas production is attributable to successful drilling efforts in our East region where we had a large 2004 drilling program. In addition, production in the first quarter of 2005 included the first production from our drilling activity in Canada. These increases are somewhat offset by reduced production in our Gulf Coast region due to the natural decline of gas production in Kent Bayou. Oil production decreased by 88 Mbbls from the comparable quarter of the prior year. The decrease in oil production is primarily the result of the continued natural decline of the CL&F and McIlhenny leases in south Louisiana.

Natural gas revenues increased by $13.9 million for the three months ended March 31, 2005 as compared to the quarter ended March 31, 2004. This is due to increases primarily in the East and Canada production, as discussed above, as well as increased natural gas sales prices. In addition, there was an increase due to a smaller unrealized loss in 2005 on derivatives related to natural gas. Oil revenues decreased by $0.7 million for the first quarter of 2005 as compared to the first quarter of 2004. This decrease is primarily due to the increased unrealized loss on crude oil derivatives of $3.1 million in 2005 from the comparable quarter of the prior year. Partially offsetting this decrease was the increase in crude oil revenues for all of the regions in which we operate, most notably in the Gulf Coast.

During the three months ended March 31, 2005, we drilled 44 gross wells (33 development, 9 exploratory and 2 extension wells) with a success rate of 86% compared to 38 gross wells (32 development and 6 exploratory wells) with a success rate of 100% for the comparable period of the prior year. For the full year of 2005, we plan to drill about 300 gross wells compared to 256 gross wells in 2004.

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the Common Stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.

We had net income of $20.8 million, or $0.43 per share, for the three months ended March 31, 2005 compared to net income of $19.0 million, or $0.39 per share, for the comparable period of the prior year. The increase in net income is primarily due to increased natural gas production revenues, as discussed above. Additionally, total operating expenses increased by $5.5 million in the first quarter of 2005 as compared to the first quarter of 2004.

In the first three months of 2005, natural gas prices were higher than the comparable period of the prior year and our financial results reflect their impact. Our realized natural gas price was $5.71 per Mcf, or 10% higher, than the $5.21 per Mcf price realized in the same period of the prior year. These realized prices are impacted by realized losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” sections. Commodity prices are determined by 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 demands, overall economic activity, weather, pipeline capacity constraints, storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGLs and crude oil prices, and therefore, cannot accurately predict 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. In 2005, excluding potential

- 17 -

acquisitions, we expect to spend approximately $280 million in capital and exploration expenditures, which includes a layer of investment for new projects or property acquisitions that may arise during 2005. For the three months ended March 31, 2005, $67.1 million of capital and exploration expenditures have been invested in our exploration and development efforts.

We remain focused on our strategies of balancing our capital investments between acceptable risk and strongest economics, along with balancing longer life investments with impact exploration opportunities. In the current year we have allocated our planned $280 million in capital and exploration expenditures among our various operating regions. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See “Forward-Looking Information” on page 27.

- 18 -

Financial Condition

Capital Resources and Liquidity

Our primary source of cash for the three months ended March 31, 2005, was from funds generated from operations. The Company generates 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 subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout the recent years. Working capital is substantially influenced by these variables. Fluctuation 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. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures and pay dividends. See below for additional discussion and analysis of cash flow.

Operating Activities. Net cash provided by operating activities in 2005 increased $10.4 million over 2004. This increase is primarily due to higher commodity prices. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 10% over the first quarter of 2004, while crude oil realized prices increased 36% over the same period. Production volumes increased slightly, with a 1% increase of equivalent production from the first quarter of 2004. 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.

Investing Activities. The primary driver of cash used by investing activities is capital spending and exploration expense. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices our budget may be periodically adjusted during any given year. Cash flows used in investing activities increased by $8.0 million for the three months ended March 31, 2005, compared to the same period in 2004. The increase from 2004 to 2005 is primarily due to an increase in drilling activity as a result of higher commodity prices. This increase largely occurred in our East region coupled with our initial drilling activity in Canada.

Financing Activities. Cash flows provided by financing activities were $1.4 million for the three months ended March 31, 2005. This is the result of proceeds from the exercise of stock options, partially offset by dividend payments. Cash flows provided by financing activities for the three months ended March 31, 2004, was $5.4 million. During the first quarter of 2004, there was a greater amount of cash proceeds received from the exercise of stock options.

The available credit line under our revolving credit facility, which was $250 million at March 31, 2005, but can be expanded up to $350 million, 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. At March 31, 2005, we had no outstanding balance on the credit facility. The revolving term of the credit facility ends in December 2009. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.

- 19 -

On August 13, 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our Common Stock in the open market or in negotiated transactions. Subsequent to this announcement, there was a 3-for-2 stock split of the Company’s Common Stock. As a result of this stock split, this figure has been adjusted to three million shares. During the first three months of 2005, we did not repurchase any shares of our Common Stock. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The approximate number of shares that may yet be purchased under the plan is 1,938,450. This figure has also been adjusted for the 3-for-2 stock split. See “Issuer Purchases of Equity Securities” in Item 2 “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information.

Capitalization

Our capitalization information is as follows:

During the first three months of 2005, we paid dividends of $1.3 million on our Common Stock. A regular dividend of $0.04 per share of Common Stock has been declared for each quarter since we became a public company in 1990. We expect to pay additional incremental dividends of approximately $2.0 million in 2005 as a result of the 3-for-2 stock split.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding major 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.

- 20 -

The following table presents major components of capital and exploration expenditures:

We plan to drill approximately 300 gross wells in 2005. This drilling program includes approximately $280 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.

Critical Accounting Policies and Estimates

The Company’s discussion and analysis of its financial condition and results of operation are based upon condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no changes to the Company’s critical accounting policies from those described in the 2004 Form 10-K. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, for further discussion.

- 21 -

Results of Operations

First Quarters of 2005 and 2004 Compared

We reported Net Income in the first quarter of 2005 of $20.8 million, or $0.43 per share. During the corresponding quarter of 2004, we reported Net Income of $19.0 million, or $0.39 per share. Operating Income increased $1.9 million compared to the prior year, from $36.1 million to $38.0 million. The increase in current year operating income was substantially due to an increase in natural gas production revenues partially offset by an increase in total operating expenses. Net income increased in the current year by $1.8 million due to an increase in operating income partially offset by an increase of $0.6 million in income tax expense.

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.71 per Mcf for the three months ended March 31, 2005 compared to $5.21 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.34 per Mcf in 2005 and $0.38 per Mcf in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $0.6 million and $1.7 million for the three months ended March 31, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item on the Statement of Operations.

- 22 -