The estimate of required purchase price adjustments shown in the preceding table and recorded in the Company’s September 30, 2006 balance sheet are expected to be settled in the fourth quarter of 2006. The net impact of the purchase price adjustments will be reflected in cash flows from investing activities when such settlements are made. In addition, a gain of approximately $12.0 million is expected to be recognized in the fourth quarter of 2006, in connection with the closing of certain property sales to Phoenix for which third party consents had not been obtained as of ~~September 30,~~December 31, 2006. In addition to the net gain of $231.2 million ($144.5 million, net of tax) recorded for the year ended December 31, 2006, the Company recorded a net gain $7.9 million ($4.9 million, net of tax) in the Condensed Consolidated Statement of Operations for the quarter ended March 31, 2007. This gain recorded in the first quarter of 2007 reflects cash proceeds of $5.8 million and a $2.1 million increase due to purchase price adjustments. During the second quarter of 2007, approximately a $4.4 million additional gain is expected to be recognized in connection with the closing of sales to other parties that ~~executed~~exercised their contractual preferential rights. This gain will be subject to customary purchase price adjustments.

At ~~September 30, 2006,~~March 31, 2007, the Company had ~~$150 million of debt outstanding~~no borrowings under its revolving credit facility. ~~Subsequent to the end of the third quarter, on October 2, 2006, the Company repaid the entire $150 million outstanding balance.~~ The credit facility 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. 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 either to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or to pay down one-sixth of the excess during each of the six months.

~~In addition to the $150 million of debt outstanding under the credit facility, the~~The Company had the following debt outstanding at ~~September 30, 2006:~~March 31, 2007:

$8060 million of 12-year 7.19% Notes due in November 2009, which consisted of ~~$60~~$40 million of long-term debt and $20 million of current portion of long-term debt, to be repaid in ~~four~~three remaining annual installments of $20 million in November of each year

$75 million of 10-year 7.26% Notes due in July 2011

$75 million of 12-year 7.36% Notes due in July 2013

$20 million of 15-year 7.46% Notes due in July 2016

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 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, 2007 and ~~nine months ended September 30, 2006 and 2005.~~2006:

The Company is a defendant in various legal proceedings arising in the normal course of its 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 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 condensed consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

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 itthe Company had taken improper deductions from the royalty and that it failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which ~~will result~~resulted in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and ~~that will limit~~limiting the claims to those arising on and after December 17, 1991. The Court ~~has~~ postponed ~~the~~a trial date ~~from~~of April 17, 2006, in light of the case involving an unrelated party pending before the West Virginia Supreme Court of Appeals described below. The Company intends to challenge the class certification order by filing a ~~Petition for Writ~~motion to decertify all or part of ~~Prohibition with~~the class, or by appeal to the West Virginia Supreme Court of Appeals.

The West Virginia Supreme Court of Appeals issued ~~its~~a decision in 2006 in a case ~~involving an unrelated party on June 15, 2006, which became final on July 15, 2006. The~~against another producer (the Tawney case) that raised some of the same issues as are raised in the Company’s case. This recent decision may negatively impact some of the defenses ~~raised on behalf of~~ the Company has raised in its litigation with respect to the issue of deductibility of post-production expenses under certain leases, but ~~the Company~~it believes that in a significant number of leases itthe Company has lease language, factual distinctions and defenses that are not implicated by the ruling. At

The Tawney case involves claims concerning the deductibility of post-production expenses and the failure to properly inform, issues shared with the Company’s case, but also involves additional claims not raised in its case. The most significant additional claims in the Tawney case are related to sales under long-term, fixed-price agreements at prices considered significantly below market value, as well as claims for certain volume reductions and unmetered production. The Tawney case went to trial in January 2007, and the jury returned a ~~status conference held on October 24, 2006, the case~~verdict against the ~~Company was re-activated to~~producer for $130 million in compensatory damages and $270 million in punitive damages. Judgment has not yet been entered in the ~~docket~~Tawney case, and ~~trial was set for August 13, 2007.~~an appeal is expected. The Company is closely monitoring developments in the Tawney case, and it continues to investigate how this recent ruling may impact its defense of the case. The case against the Company has been re-activated to the docket and trial is set for August 13, 2007.

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

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 filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs filed their Third Amended Original Petition on February 21, 2006, which incorporated all prior supplemental petitions. Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, a subsidiary of the Company, acquired certain leases and wells in 1997 and 1998.

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 and conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties were allowed to amend pleadings or add additional parties to the litigation. Plaintiffs did not join additional parties by the abatement deadline. Defendants, including the Company, re-urged its motion to dismiss, and on April 5, 2006, the Court granted the motion, dismissing the oil company defendants, without prejudice. Because all defendants were not dismissed at that time, the order dismissing the Company was not then final. A motion to finalize the proceedings in the trial court via severance of the dismissed defendants was filed April 25, 2006, and the remaining defendants moved to join the motions that led to the dismissal of the Company. At a hearing on June 23, 2006, the Court dismissed the remaining defendants, and effectively denied the plaintiffs’ attempt to modify the prior dismissal order, which is now final.

Plaintiffs filed a Notice of Appeal on July 17, 2006. Although the record is not yet complete and, therefore, specific appellate deadlines have not been set, the Company expects that, following briefing and oral argument, the appellate court will issue its decision by the end of 2007 or early 2008.

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 had 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. The defendants filed a counter claim against Cody, and one of the defendants filed a lien against Cody’s interest in the leases in the Raymondville area.

Cody has signed a settlement agreement with certain of the defendants representing approximately 3% of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August 2005, the trial judge entered an order granting Cody’s Motion for Summary Judgment requiring the remaining defendant to assign to Cody all of its interest in the prospect and to remove the lien filed against Cody’s interest. The defendant filed a Motion for Reconsideration and Opposition to Proposed Order. The Court, on March 24, 2006, denied the Motion.

On July 12, 2006, Cody entered into a Purchase and Sale Agreement to acquire all of the defendant’s interest in the Raymondville Field. The agreement would make the summary judgment ruling by the trial judge a final order, dismiss, with prejudice, all pending counter claims filed by such defendant and remove the lien against Cody’s properties filed by such defendant. Cody completed the acquisition in the third quarter of 2006. The lien has been removed and the parties filed a joint motion to make the summary judgment a final order and dismiss all other claims. The order making the summary judgment final and dismissing all of the defendant’s claims was signed by the judge on September 7, 2006.

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 ~~$8.8~~$9.1 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

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

The Company has ~~entered into~~incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. The agreements ~~that~~ provide firm transportation capacity rights on pipeline systems in Canada, the West region and the East ~~regions.~~region. The remaining terms on these agreements range from less than one year to 21 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company.

The amount of demand charges on firm gas transportation agreements has decreased by approximately ~~$3.8~~$2.4 million ~~over the total length of these contracts~~ from the amount previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2005.~~2006. This is due to ~~rate changes and~~ released volumes on ~~certain contracts, partially offset by increased charges as a result of new contracts entered into~~one contract in ~~Canada.~~the West region. As of ~~September 30, 2006,~~March 31, 2007, demand charges for ~~2006~~2007 and 2008, respectively, are expected to be ~~$7.1~~$8.2 million and $7.5 million, a decrease of ~~$4.6~~$1.7 million and $0.7 million from the ~~$11.7 million figure~~figures previously disclosed.

~~Future~~ For further information on these future obligations, ~~under firm gas transportation agreements in effect at September 30, 2006 are as follows:~~

~~During~~please refer to Note 7 of the ~~second quarter of 2006,~~Notes to the Company entered into a long-term contract for the use of an additional land drilling rig in the Gulf Coast with an existing contracted rig provider. The Company is obligated to pay $8.0 million over the one year contract starting on the delivery date in September 2006. Additionally, commitments on two rigs with existing contracted rig providers disclosedConsolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, ~~2005 have been renewed for an additional $1.8 million expected to be paid in 2008.~~2006.

In its Annual Report on Form 10-K for the year ended December 31, ~~2005,~~2006, the Company ~~also~~ disclosed that it had commitments on ~~four~~seven drilling rigs under contract in the Gulf Coast and that ~~were not yet delivered. During October 2006, two~~one of these rigs ~~were~~had not yet been delivered. This rig was delivered in April 2007. In addition, the total commitment increased by $0.7 million in the aggregate ($0.2 million, $0.3 million and ~~it is expected that a third will be delivered by October~~$0.2 million in each of 2007, 2008 and 2009, respectively) as of March 31, ~~2006. The~~2007. This increase was due to an increase in the daily rig rates on two ~~of these~~ rigs ~~have increased in accordance with the contracts~~ as a result of ~~increased contractor expenses. The Company expects to pay~~ an ~~additional $1.5 million over approximately the next three years.~~

~~On June 28, 2006, the Company announced the commencement~~increase of ~~an offering under its Mineral, Royalty and Overriding Royalty Interest Plan. The Company assisted certain non-executive employees in obtaining loans to purchase an interest~~5% in the ~~offering by providing a guarantee~~U.S. Department of ~~repayment should~~Labor Wholesale Price Index for Oilfield Machinery and Tools from the ~~non-executive employee fail~~base index, as required in the commitment agreement. For further information on these future obligations, please refer to ~~repay~~Note 7 of the ~~loan. The repayment term for all of these loans is five years. The outstanding loan balances and fair value of these guarantees are immaterial~~Notes to the ~~Company’s financial statements. All loans are collateralized by the interests transferred to the employees~~Consolidated Financial Statements in the ~~producing properties.~~Annual Report on Form 10-K for the year ended December 31, 2006.

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. Under the Company’s revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At ~~September 30, 2006,~~March 31, 2007, the Company had 2622 cash flow hedges open: 2421 natural gas price collar arrangements and ~~two~~one crude oil collar ~~arrangements.~~arrangement. At ~~September 30, 2006,~~March 31, 2007, a ~~$68.1~~$29.4 million ($~~42.2~~18.3 million, net of tax) unrealized gain was recorded in Accumulated Other Comprehensive Income, along with a ~~$58.4~~$30.4 million short-term derivative receivable, a $1.8 million short-term derivative liability (included within Accrued Liabilities on the Balance Sheet) and a ~~$9.7~~$0.8 million long-term derivative ~~receivable.~~receivable (included within Other Assets on the Balance Sheet). 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. During the first three months of 2007 and 2006, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations.

Assuming no change in commodity prices, after ~~September 30, 2006~~March 31, 2007 the Company would expect to reclassify to the Condensed Consolidated Statement of Operations, over the next 12 months, ~~$36.2~~$17.8 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 ~~September 30, 2006~~March 31, 2007 related to anticipated ~~2006~~2007 and ~~2007~~2008 production.

During the first ~~nine~~three months of ~~2006,~~2007, the Company entered into ~~one new oil collar contract and 16~~two new natural gas collar contracts covering a portion of its ~~2007~~2008 production. As of ~~September 30, 2006,~~March 31, 2007, natural gas price collars for ~~2007~~2008 cover ~~34,246~~6,584 Mmcf of production at a weighted average floor of ~~$9.09~~$8.62 per Mcf and a weighted average ceiling of ~~$12.45. The oil price collar for 2007 covers 365 Mbbl of production at a floor of $60.00 and a ceiling of $80.00.~~$11.15 per Mcf.

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 ~~and nine~~ month periods ended ~~September 30, 2006~~March 31, 2007 and ~~2005.~~2006:

Changes in the components of accumulated other comprehensive income, net of taxes, for the ~~nine~~three months ended ~~September 30, 2006 are~~March 31, 2007 were as follows:


Accumulated Other Comprehensive Income(In thousands)	Net Gains / (Losses) on Cash Flow Hedges			Defined Benefit Pension and Postretirement Plans			Foreign Currency Translation Adjustment		Total
Balance at December 31, 2006	$	51,239		$	(14,168	)	$	89	$	37,160

Net change in unrealized gains on cash flow hedges, net of taxes of $19,623		(32,942	)		—			—		(32,942	)
Change in foreign currency translation adjustment, net of taxes of $(282)		—			—			465		465

Balance at March 31, 2007	$	18,297		$	(14,168	)	$	554	$	4,683

The following table reflects the changes in the asset retirement obligations during the ~~nine~~three months ended ~~September 30, 2006.~~March 31, 2007:

Accretion expense ~~is $1.1~~was $0.2 million and $0.3 million, respectively, for ~~both~~ the ~~nine~~three months ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ and is included within Depreciation, Depletion and Amortization expense on the Company’s Condensed Consolidated Statement of Operations.

The components of net periodic benefit costs for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005 are~~were as follows:

The funding levels of the pension and postretirement plans are in compliance with standards set by applicable law or regulation. The Company previously disclosed in its financial statements for the year ended December 31, ~~2005~~2006 that it expected to contribute less than $0.1 million to its non-qualified pension plan and approximately $0.6 million to the postretirement benefit plan during ~~2006.~~2007. It is anticipated that these contributions will be made prior to December 31, ~~2006.~~2007. The Company does not have any required minimum funding obligations for its qualified pension plan in ~~2006. The Company made a $2.0 million contribution to the qualified pension plan during the second quarter of 2006.~~2007. Management has not determined if any ~~additional~~ discretionary funding will be made to the qualified pension plan during the remainder of ~~2006.~~2007.

On April 29, 2004, the 2004 Incentive Plan was approved by the stockholders. Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, ~~SARs,~~stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock ~~awards, in addition to~~awards. In the first quarter of 2007, the Compensation Committee eliminated the automatic award of an option to purchase 15,000 shares (pre 2-for-1 split) of common stock on the date the non-employee directors first join the board of directors. A total of ~~2,550,000~~5,100,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than ~~900,000~~1,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than ~~1,500,000~~3,000,000 shares may be issued pursuant to incentive stock options.

Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by APB No. 25. Under the intrinsic value based method, no compensation expense was recorded for stock options granted when the exercise price for options granted was equal to or greater than the fair value of the Company’s common stock on the date of the grant.

Beginning January 1, 2006, the Company began accounting for stock-based compensation under SFAS No. 123(R), which applies to new awards and to awards modified, repurchased or cancelled after December 31, 2005. The Company records compensation expense based on the fair value of awards as described below. Additionally, compensation expense for the portion of the awards for which the requisite service period has not been rendered that are outstanding at December 31, 2005 is recognized as the requisite service is rendered on or after January 1, 2006.

Compensation expense ~~that has been~~ charged against income for stock-based awards in the ~~third~~first quarter of 2007 and 2006 ~~and 2005 is $3.2~~was $6.6 million and ~~$4.3~~$4.9 million, pre-tax, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations.

For further information regarding Stock-Based Compensation, please refer to Note 10 of the ~~first nine months of 2006 and 2005, stock-based compensation expense is $11.8 million and $6.8 million, respectively. In~~Notes to the ~~first nine months of 2006, compensation expense includes amortization of restricted stock grants, stock options, SARs and performance shares at fair value. Compensation expense~~Consolidated Financial Statements in the ~~first nine months of 2005 only includes amortization of restricted stock grants and compensation expense related to performance shares.~~

Prior to the adoption of SFAS No. 123(R), the Company presented tax benefits resulting from tax deductions related to stock-based compensation as an operating cash flow. Under SFAS No. 123(R), the tax benefits resulting from tax deductions in excess of expense is reported as an operating cash outflow and a financing cash inflow. For the first nine months of 2006, $5.8 million is reported in these two separate line items in the Condensed Consolidated Statement of Cash Flows.

The cumulative effect of adoption that is recorded in the first quarter of 2006 is due primarily to the recording of the liability component of the Company’s performance share awards at fair value, rather than intrinsic value.

~~During the third quarter of 2006, the Company adopted the provisions outlined under FSP FAS No. 123(R)-3, “Transition Election Related to Accounting~~Annual Report on Form 10-K for the Tax Effects of Share-Based Payment Awards,” which discusses accounting for taxes for stock awards using the APIC Pool concept. The Company is not required to adopt this provision until January 1, 2007, one year from the adoption of 123(R); however, it chose early adoption. The Company has made a one time election as prescribed under the FSP to use the shortcut approach to derive the initial windfall tax benefit pool. The Company has chosen to use a one pool approach which combines all awards granted to employees, including non-employee directors.

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 No. 123(R) to stock-based employee compensation during the three and nine months ended ~~September 30, 2005:~~December 31, 2006.

Restricted stock awards vest either at the end of a three year service period, or on a graded-vesting basis ~~for awards that vest~~of one-third at each anniversary date over a three year service period. Under the graded-vesting approach, the Company recognizes compensation cost over the three year requisite service period for each separately vesting tranche as though the awards are, in substance, multiple awards. For awards that vest at the end of the three year service period, expense is recognized ratably using a straight-line expensing approach over three years. For all restricted stock awards, vesting is dependant upon the employees’ continued service with the ~~Company.~~Company, with the exception of employment termination due to death, disability or retirement.

The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is three years. In accordance with SFAS No. 123(R), the Company ~~accelerates~~accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs for awards issued after the adoption of SFAS No. 123(R). The Company used an annual forfeiture rate ranging from 0% to 3.3% based on the Company’s ten year history for this type of award to various employee groups.

~~There were 46,850 restricted stock awards granted to employees in the first nine months of 2006. All of these awards were granted in~~During the first quarter of ~~2006.~~2007, there were 92,400 shares of restricted stock granted to employees with a grant date per share value of $35.22. These awards vest over a three year service period on a graded-vesting schedule. Compensation expense recorded for all unvested restricted stock awards for the first ~~nine~~three months of 2007 and 2006 ~~and 2005 is $4.8~~was $2.0 million and ~~$4.2~~$2.4 million, respectively. Included in the 2007 and 2006 expense isfigures were $0.9 million and $0.5 million, respectively, related to the immediate expensing of shares granted to retirement-eligible employees. ~~Unamortized expense as of September 30, 2006 for all outstanding restricted stock awards is $5.5 million.~~

~~The following table is a summary of activity of restricted stock awards for the nine months ended September 30, 2006:~~

Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are paid out when the director ceases to be a director of the Company. ~~Due to~~

During the ~~immediate vesting~~first quarter of ~~the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table below.~~

~~The following table is a summary of activity of restricted stock units for the nine months ended September 30, 2006:~~

~~As shown in the table above, 17,220~~2007, 24,654 restricted stock units were granted ~~during the first nine months~~with a grant date per share value of ~~2006.~~$35.49. The compensation cost, which reflects the total fair value of these units, recorded in the ~~second~~first quarter of ~~2006~~2007 is $0.9 million. During the first three months of 2006, the Company did not have any expense related to restricted stock units.

~~During~~Option awards are granted with an exercise price equal to the ~~first nine months of 2006, 30,000 stock options were granted to two incoming non-employee directors~~fair market price (defined as the average of the ~~Company. All~~high and low trading prices of ~~these~~the Company’s stock ~~options were granted in~~at the ~~first quarter~~date of ~~2006.~~grant) of the Company’s stock at the date of grant. The grant date fair value of a stock option is calculated by using a Black-Scholes model. Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options

granted to directors due to the forfeiture rate history for these types of awards for this group of individuals. ~~Option awards are generally granted with an exercise price equal to~~During the ~~fair market price~~first quarter of ~~the Company’s stock at the date of grant. No~~2007, there were no stock options ~~were granted in the first nine months of 2005.~~granted.

Compensation expense recorded during the first ~~nine~~three months of 2007 and 2006 for these stock options is $0.2 million. Since the Company had not yet adopted SFAS No. 123(R) in the first nine months of 2005, stock options were not expensed through the statement of operations during 2005 and no compensation expense was recorded. Unamortized expense as of September 30, 2006 for all outstanding stock options is $0.3 million. The weighted average period over which this compensation will be recognized is approximately 2.4 years.

~~The assumptions used in the Black-Scholes fair value calculation for stock options are as follows:~~

~~The following table is a summary of activity~~amortization of stock options was $0.1 million for ~~the nine months ended September 30, 2006:~~

~~At September 30, 2006, the exercise price range for outstanding options is $12.84 to $47.60 per share. The following tables provide more information about the options by exercise price.~~

~~None of the options with exercise prices between $30.01 and $47.60 are exercisable as of September 30, 2006.~~

In September 2006, the SEC Staff issued a letter summarizing their views regarding the backdating of stock options. The letter discusses the date that is to be used as the measurement date for options in order to value the exercise price of the options. It also discusses the documentation that should be available to support award grant dates. The Company has reviewed its stock option granting practices and has found no instances of backdating. Further, as required under the Company’s incentive plans, the stock option grant date is the date on which the Compensation Committee and/or Board of Directors approves the award. Company management is given no discretion to choose the grant date. The Company maintains Compensation Committee and/or Board of Directors minutes and other records to support the grant dates of its options.each period.

~~On February 23, 2006,~~During the ~~Company~~first quarter of 2007, the Compensation Committee granted ~~132,800 stock appreciation rights (SARs)~~107,200 SARs to employees. These awards allow the employee to receive any intrinsic value over the ~~$47.60~~$35.22 grant date fair market value that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. As ~~of September 30, 2006, there are 132,800 SARs outstanding. The aggregate intrinsic value of~~

~~these awards is less than $0.1 million at September 30, 2006. As~~ these SARs are paid out in stock, rather than in cash, the Company calculates the fair value in the same manner as stock options, by using a Black-Scholes model.

The assumptions used in the Black-Scholes fair value calculation for SARs are as follows:

Compensation expense recorded during the first ~~nine~~three months of 2007 and 2006 for ~~these~~ SARs ~~is $0.7 million. As no SARs were outstanding~~was $0.8 million and $0.1 million, respectively. Included in the ~~first nine months~~2007 amount was $0.5 million related to the immediate expensing of 2005, no compensation expense was recorded for this type of award. In addition, all SARs were unvested at September 30, 2006. Unamortized expense as of September 30, 2006 for all outstanding SARs is $1.2 million which will be recognized over the next 2.4 years.shares granted to retirement-eligible employees.

~~The Company grants~~During 2007, the Compensation Committee granted two types of performance share awards to ~~employees.~~employees for a total of 294,700 performance shares. The performance period for both of these awards commences January 1, 2007 and ends December 31, 2009. Certain of these awards, totaling 98,200 performance shares, are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year vesting performance period. The grant date per share value of the equity portion of this award was $30.72. Depending on the Company’s performance, employees may earn up to 100% of the award in common stock, and an additional 100% of the award in cash. ~~A new type of award has been granted in 2006 that measures~~In addition, 196,500 performance shares are earned, or not earned, based on the Company’s internal performance ~~based on internal~~ metrics rather than a peer group. The grant date per share value of the equity portion of this award was $35.22. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal ~~metric~~ performance ~~criteria~~metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at March 31, 2007, it is currently considered probable that these three criteria will be met.

Both of these types of awards vest at the end of a designated three year performance period. For all awards granted to employees before and after January 1, 2006, an annual forfeiture rate ranging from 0% to 5.0% has been assumed based on the Company’s history for this type of award to various employee groups.

On February 23, 2006, the Board of Directors granted a series of 89,850 performance share awards with performance conditions and 52,900 performance share awards with market conditions to employees of the Company. The performance period for both of these awards commences January 1, 2006 and ends December 31, 2008.

For awards that are based on the internal metrics (performance condition) of the Company and for awards that were granted prior to the adoption of SFAS No. 123(R) on January 1, 2006, fair value is measured based on the average of the high and low stock price of the Company on grant date and expense is amortized over the three year vesting period. To determine the fair value for awards that were granted after January 1, 2006 that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components are bifurcated. On the grant date, the equity component iswas valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model.

The three primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns and correlation in stock price movement. The risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for six-month, one, two and three 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 iswas set equal to the annualized daily volatility measured over a historic four year period ending on the reporting date. A sample of correlation statistics were reviewed between the Company and its peers and the average ranged between 87% and 93%.

The following assumptions were used as of ~~September 30, 2006~~March 31, 2007 for the Monte Carlo model to value the liability ~~components~~component of the peer group measured performance share ~~awards.~~awards issued during the first quarter of 2007. The equity portion of the award ~~granted in 2006~~ has already been valued on the date of grant using the Monte Carlo model and this portion iswas not marked to market.

The Monte Carlo value per share for the liability component for this performance share award was $13.95 at March 31, 2007. The liability component for all outstanding market condition performance share awards ~~at September 30, 2006~~ ranged from ~~$1.91~~$13.95 to ~~$27.50.~~$30.86 at March 31, 2007. The long-term liability for all market condition performance share awards, included in Other Liabilities in the Condensed Consolidated Balance Sheet at March 31, 2007 and ~~short-term liability, included in Accrued Liabilities in the Condensed Consolidated Balance Sheet, for performance share awards at September 30,~~ 2006 ~~is $1.6~~was $5.3 million and ~~$0.4~~$1.1 million, respectively.

~~The following table is a summary of activity of performance share awards for the nine months ended September 30, 2006:~~

Total unamortized compensation cost related to the equity component of performance shares at September 30, 2006 is $6.1 million and will be recognized over the next 2.0 years, as computed by using the weighted average of the time in years remaining to recognize unamortized expense. Total compensation cost recognized for both the equity and liability components of all performance share awards during the ~~nine~~three months ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005 is $5.2~~was $2.8 million and ~~$2.6~~$2.3 million, respectively.

~~On May 4,~~In June 2006, the ~~stockholders~~FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.” This Interpretation provides guidance for recognizing and measuring uncertain tax positions as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the ~~Company approved an increase~~benefit of the uncertain tax position should be recognized in the ~~authorized number~~financial statements. If the recognition threshold is met, FIN No. 48 provides additional guidance on measuring the amount of ~~shares~~the uncertain tax position. Under FIN No. 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of ~~common stock~~the position. The tax benefits recognized in the financial statements from ~~80 million to 120 million shares.~~ such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and increased disclosure of these uncertain tax position. FIN No. 48 is effective for fiscal years beginning after December 15, 2006.

The Company ~~correspondingly increased~~adopted the ~~number~~provisions of shares of Series A Junior Participating Preferred Stock reserved for issuance from 800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to the Rights Agreement between the Company and The Bank of New York, as Rights Agent.

~~In August 1998, the Company announced that its Board of Directors authorized the repurchase of two million shares of the Company’s common stock in the open market or in negotiated transactions.~~FIN No. 48 on January 1, 2007. As a result of the ~~3-for-2 stock split effected~~implementation of FIN No. 48, the Company recognized no change to the liability for unrecognized tax benefits.

As of January 1, 2007, after the implementation of FIN No. 48, the Company’s unrecognized tax benefits are $1.0 million. This amount, if recognized, would not affect the effective tax rate.

The Company recognizes interest accrued related to uncertain tax positions in ~~March 2005, this figure was adjusted to three million shares. All purchases executed to date have been through open market transactions. There~~the Interest Expense and Other line and penalties accrued in the General and Administrative line in the Condensed Consolidated Statement of Operations, which is ~~no expiration date associated~~consistent with the ~~authorization~~recognition of these items in prior reporting periods. During the first quarter of 2007, the Company recorded a $0.1 million increase to ~~repurchase securities~~interest expense. As of January 1, 2007, the Company had recorded a liability of approximately $0.9 million for interest. As of March 31, 2007, the Company determined that no accrual for penalties was appropriate.

As of January 1, 2007, it is reasonably possible that the 2001-2004 years currently pending before the IRS Appeals Division will be settled within the next twelve months. However, no increase or decrease to the total amount of unrecognized tax benefits can be anticipated. All issues pending before Appeals relate to the proper timing of deductions for tax purposes.

It is possible that the amount of unrecognized tax benefits will change in the next twelve months. The Company does not expect that a change would have a significant impact on the results of operations, financial position or cash flows.

The U.S. federal statute of limitations remains open for years 2001 and onward. State income tax returns are generally subject to examination for a period of three to four years after filing of the ~~Company.~~

~~During the nine months ended September 30, 2006, the Company repurchased 1,088,500 shares with a weighted average price per share~~respective return. The state impact of ~~$42.71~~any federal changes remains subject to examination by various states for a ~~total cost~~period of ~~approximately $46.5 million. All~~up to one year after formal notification to the states. Years still open to examination by state authorities in major jurisdictions include Texas and West Virginia (2001 onward). The Company is not currently under examination, nor has it been notified of ~~the repurchases occurred during the second and third quarters.~~an upcoming examination, by West Virginia. The ~~repurchased shares are held as treasury stock. Since the authorization date, the~~ Company is not currently under examination by Texas; however, it has ~~repurchased 2,602,350 shares, or 87%~~been notified of ~~the total shares authorized for repurchase at September 30, 2006, for a total cost of approximately $85.7 million.~~

~~On October 26, 2006, the Company announced that its Board of Directors increased the number of shares of the Company’s common stock authorized for repurchase by~~ an ~~additional two million shares.~~upcoming routine examination.

We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the Company) as of ~~September 30, 2006,~~March 31, 2007, and the related condensed consolidated ~~statement~~statements of operations ~~for each of the three~~ and ~~nine month periods ended September 30, 2006 and 2005 and the condensed consolidated statement~~ of cash flows for the ~~nine~~three month periods ended ~~September 30, 2006~~March 31, 2007 and ~~2005.~~2006. 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 have previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated balance sheet as of December 31, ~~2005~~2006 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, ~~2005~~2006 and the effectiveness of the Company’s internal control over financial reporting as of December 31, ~~2005;~~2006; and in our report dated ~~March 6, 2006,~~February 28, 2007, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. ~~143, “Accounting~~158, “Employers’ Accounting for ~~Asset Retirement Obligations,~~Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” 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 condensed consolidated balance sheet information as of December 31, ~~2005,~~2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

As discussed in Notes 1 and 11 to the condensed consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share Based Payment (revised 2004).”/s/ PricewaterhouseCoopers LLP

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

The following review of operations for the three ~~and nine~~ month periods ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~ 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 Annual Report on Form 10-K for the year ended December 31, ~~2005.~~2006.

Operating revenues decreased by $23.2 million, or 11%, from the three months ended March 31, 2006 compared to the three months ended March 31, 2007 due to decreased realized commodity prices as well as decreased equivalent production that results from the disposition of assets substantially completed in the third quarter of 2006. Natural gas revenues ~~increased~~decreased by ~~$99.4~~$8.4 million, or ~~29%,~~five percent, for the ~~nine~~three months ended ~~September 30, 2006~~March 31, 2007 as compared to the ~~nine~~three months ended ~~September 30, 2005.~~March 31, 2006. The ~~increase~~decrease is due to ~~higher realized~~a 10% decrease in natural gas prices, ~~as well as increased production~~partially offset by a five percent increase in ~~the Gulf Coast, East and Canada.~~natural gas production. Oil revenues ~~increased~~decreased by ~~$23.0~~$13.3 million, or ~~40%~~55%, for the first ~~nine~~three months of ~~2006~~2007 as compared to the first ~~nine~~three months of ~~2005.~~2006. This ~~increase~~decrease is primarily due to a decrease in crude oil production as a result of the third quarter 2006 disposition of assets as well as a decrease in crude oil realized prices in the first three months of 2007 as compared to the first three months of 2006. After removing $27.3 million and $15.4 million, respectively, of natural gas and crude oil revenues attributable to properties sold from the first quarter 2006 revenues, natural gas revenues for the quarter increased by 15% and crude oil revenues increased by 25%. Brokered natural gas revenues increased by $0.4 million due to an increase in oil prices in the first nine months of 2006 as compared to the first nine months of 2005. Additionally, crude oil revenues for the first nine months of 2005 included an unrealized loss on crude oil derivatives of $1.9 million, and there is no unrealized impact in the first nine months of 2006. Somewhat offsetting the crude oil price increase and the change in the unrealized loss on crude oil derivatives is thebrokered volumes, partially offset by a decrease in ~~crude oil production of approximately 10% in the first nine months of 2006.~~sales price.

Our realized natural gas price for the first ~~nine months~~quarter of ~~2006~~2007 was ~~$7.22~~$7.42 per Mcf, ~~17% higher~~10% lower than the ~~$6.16~~$8.22 per Mcf price realized in the same period of the prior year. Our realized crude oil price was ~~$66.42~~$53.36 per Bbl, ~~51% higher~~13% lower than the ~~$43.92~~$61.11 per Bbl price realized in the same period of the prior year. These realized prices are impacted by realized gains and losses resulting from commodity ~~derivatives.~~derivatives (costless collars). For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” section. 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, NGL and crude oil prices and, therefore, cannot accurately predict revenues.

On an equivalent basis, our production for the first three months of 2007 decreased by one percent from the first three months of 2006. For the ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, we produced ~~67.8~~21.0 Bcfe compared to production of ~~62.9~~21.3 Bcfe for the comparable period of the prior year. Natural gas production was ~~60.5~~19.8 Bcf and oil production was ~~1,209~~205 Mbbls. Natural gas production increased by approximately ~~10%~~five percent when compared to the comparable period of the prior year, which had production of ~~54.8~~18.9 Bcf. ~~Our East~~This increase was primarily a result of increased production in the West region, ~~improved natural gas production~~associated with an increase in the ~~success of our~~ drilling ~~program.~~program, and to a lesser extent an increase in Canada due to increased pipeline capacity in Canada for the Hinton field. The Gulf Coast region ~~also had increased~~experienced an overall decrease in natural gas production ~~from~~of 0.8 Bcf, or 11%. After removing 3.0 Bcf of first quarter 2006 natural gas production related to the ~~prior year period due to a successful 2006 drilling program as well as an offshore well that commenced production~~properties sold in the ~~second~~third quarter of ~~2006. In addition,~~2006, the Gulf Coast region experienced a 2.2 Bcf, or 52% increase in production, ~~in Canada increased~~primarily as a result of increased drilling in the ~~continued drilling success, with the initiation of~~Minden and McCampbell fields. Natural gas production in the ~~Narraway area and additional production volume from the Hinton field. These increases are partially offset by reduced production in our West~~East region ~~as a result of pipeline and compression curtailments and natural production declines.~~remained relatively flat quarter over quarter. Oil production decreased by ~~137~~191 Mbbls from ~~1,346~~396 Mbbls in the first ~~nine~~three months of ~~2005~~2006 to ~~1,209~~205 Mbbls produced in the first ~~nine~~three months of ~~2006.~~2007. This was primarily the result of a decrease of 182 Mbbls in the Gulf Coast region. After removing 250 Mbbls of first quarter 2006 crude oil production related to the properties sold in the third quarter of 2006, oil production increased by 84% due primarily to the increase in drilling and workover activity in the McCampbell field, and to a lesser extent, in the Minden field. Oil production ~~increased in the West,~~ remained relatively flat in the East ~~and~~region, decreased slightly in the ~~Gulf Coast~~West region and ~~Canada. The primary reason for the production decrease is from a decrease~~increased slightly in ~~Gulf Coast production due to the continued natural decline of the CL&F lease in south Louisiana, which was sold in September 2006.~~Canada.

We had net income of ~~$289.0~~$48.5 million, or ~~$5.95~~$0.50 per share, for the ~~nine~~three months ended ~~September 30, 2006~~March 31, 2007 compared to net income of ~~$89.9~~$53.2 million, or ~~$1.84~~$0.55 per share, for the comparable period of the prior year. The ~~increase~~decrease in net income is primarily due to the gain of $229.7 million ($143.6 million, net of tax) recorded in the third quarter of 2006 related to the disposition of our offshore and certain south Louisiana properties described below. In addition, net income is higher due to increaseddecreased natural gas and oil production revenues, as discussed above. ~~Offsetting these increases in income were increases in the first nine months of 2006 as compared to the first nine months of 2005~~Partially offsetting this revenue decrease was a decrease in total operating expenses of ~~$47.0~~$3.5 million in the first three months of 2007 as ~~well as~~

compared to the first three months of 2006, primarily due to decreased exploration charges and taxes other than income, ~~tax expense~~partially offset by increased general and administrative expenses and depreciation, depletion and amortization (DD&A). Because of ~~$112.3~~reduced income before taxes due to the reasons discussed above, income taxes decreased by $5.2 million. ~~Income taxes increased primarily as a result of the gain on the disposition of properties that occurred during the third quarter of 2006.~~

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. ~~For the fourth quarter of 2006,~~In 2007, we expect to spend approximately ~~$100~~$434 million in capital and exploration expenditures. Our annual capital budget of approximately $500 million was increased by approximately $104 million from the $396 million figure previously reported in our Form 10-K in order to reflect increased drilling costs as well as new projects. Of the $104 million increase, approximately $60 million will be funded from the proceeds from the saleFunding of the ~~offshore~~program will come from operating cash flow, existing cash and ~~south Louisiana assets.~~increased borrowings, if required. For the ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, approximately ~~$401.0~~$129.2 million of capital and exploration expenditures have been invested in our exploration and development efforts.

During the ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, we drilled ~~301~~100 gross wells ~~(278~~(97 development, 142 exploratory and 91 extension wells) with a success rate of ~~97%~~99.0% compared to ~~229~~71 gross wells ~~(207~~(66 development, 184 exploratory and 41 extension wells) with a success rate of ~~95%~~97.2% for the comparable period of the prior year. As disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2005,~~2006, for the full year of ~~2006,~~2007, we plan to drill approximately ~~391~~440 gross wells compared to ~~316~~387 gross wells drilled in ~~2005.~~2006.

We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results and selectively pursuing impact exploration opportunities as we accelerate drilling on our accumulated acreage position. In the current year we have allocated our planned program for 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.

~~On September 29, 2006,~~During the first quarter of 2007, we ~~completed~~recorded a gain of $7.9 million related to the ~~sale~~completion of our ~~offshore portfolio and~~disposition of certain south Louisiana ~~properties to Phoenix Exploration Company LP (“Phoenix”) for a gross sales price of $340.0 million. The properties sold included proved reserves of approximately 98 Bcfe as of~~and offshore properties. During the ~~August 1, 2006 effective date, including 68 Bcfe of proved reserved recorded as of December 31, 2005, and had average daily production for the nine months ended September 30, 2006 of 47.4 Mmcfe.~~

Pursuant to the Asset Purchase Agreement (the “Agreement”) dated August 25, 2006, the gross sales price is to be offset by the net cash flow (as defined in the Agreement) from operation of the properties from August 1, 2006 and other purchase price adjustments, if any. The net proceeds from the sale are expected to be used to add funding to our capital program, repurchase shares of common stock, repay outstanding debt under the revolving credit facility and pay taxes related to the transaction. Also pursuant to the Agreement, we entered into certain commodity price swaps on behalf of Phoenix. At closing on September 29, 2006, these derivative instruments were assigned to Phoenix, and we were released from all rights and obligations with respect thereto. There was no ultimate impact on our financial statements due to the existence of these swaps.

Through September 30, 2006, the Company had received approximately $321.4 million in net proceeds from this sale of our offshore and south Louisiana properties. Net proceeds of $321.4 million reflects the $340.0 million gross sales price, reduced by purchase price adjustments of $3.1 million as well as consents and preferential rights expected to be settled in the fourthsecond quarter of ~~2006 of $15.5 million. A net gain of $229.7 million ($143.6 million, net of tax) is recorded in the Statement of Operations for the third quarter of 2006 and~~2007, we expect to record an additional gain of approximately $12.0 million is expected to be recognized in the fourth quarter of 2006, in connection with the closing of certain property sales to Phoenix for which third party consents had not been obtained as of September 30, 2006 and sales to other parties that executed their contractual preferential rights.$4.4 million.

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

Our primary sources of cash for the ~~nine~~three months ended ~~September 30, 2006 are~~March 31, 2007 were from funds generated from the sale of natural gas and crude oil ~~production as well as proceeds from the sale of our offshore and certain south Louisiana properties.~~production. 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~~volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in our Annual Report on Form 10-K for the year ended December 31, 2006, have also influenced prices throughout the recent years. Working capital is also 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~~development, and ~~development~~to a lesser extent, exploratory expenditures, ~~purchase treasury stock~~reduce borrowings on our revolving credit facility and to pay dividends. See below for additional discussion and analysis of cash flow.

Operating Activities. Net cash provided by operating activities in the first ~~nine~~three months of ~~2006 increased~~2007 decreased by ~~$108.9~~$19.1 million over the comparable period in ~~2005.~~2006. This ~~increase~~decrease is primarily due to ~~higher~~a decrease in working capital changes as well as a decrease in net income due to reduced commodity prices and, to a lesser extent, ~~increased~~decreased equivalent production. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices ~~increased 17%~~for the first three months of 2007 decreased by 10% over the ~~2005~~2006 period, ~~while~~and crude oil realized prices ~~increased 51%~~decreased by 13% over the same period. Equivalent production volumes ~~increased~~decreased by approximately 8%one percent in the first ~~nine~~three months of ~~2006~~2007 compared to the comparable period in ~~2005.~~2006. While we ~~expect~~believe 2007 actual commodity production may exceed 2006 ~~actual production to exceed 2005~~ levels, 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 uses of cash in investing activities are capital spending and exploration expense. Cash flows used for investments in capital and exploration expenditures is $384.6 million in the first nine months of 2006 compared to $288.9 used in the first nine months of 2005. This increase of $95.7 million in investments in capital and exploration expenses is entirely offset by the increase of $322.0 million in proceeds from the sale of assets, primarily as a result of the sale of our offshore and certain south Louisiana properties, resulting in an overall decrease of $226.3 million in net cash used in investing activities for the first nine months of 2006 compared to the first nine months of 2005. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices, our capital expenditures budget may be periodically adjusted during any given year. ~~The increase from 2005 to 2006 in cash~~Cash flows used in ~~capital spending~~investing activities decreased by $0.6 million from the first three months of 2006 compared to the first three months of 2007. The decrease from 2006 to 2007 is due to proceeds from the sale of assets related to the disposition of certain south Louisiana and offshore properties as well as a decrease in exploration expense, ~~is primarily due to~~partially offset by an increase in ~~drilling activity in response to higher commodity prices.~~capital expenditures.

Financing Activities. Cash flows ~~provided by~~used in financing activities ~~are $17.1~~were $6.7 million for the ~~nine months ended September 30, 2006~~first quarter of 2007, and ~~are~~were comprised of payments made to ~~purchase treasury stock~~decrease outstanding debt under our revolving credit facility and ~~dividend payments. Offsetting~~to pay dividends. Partially offsetting these cash uses were inflows from ~~a net increase in borrowings under our revolving credit facility,~~ the exercise of stock options and the tax benefit received from stock-based compensation. Cash flows ~~provided~~used by financing activities were ~~$34.0~~$42.9 million for the ~~nine months ended September 30, 2005. Cash flows provided by financing activities in the~~ first ~~nine months~~quarter of ~~2005 were the result of an increase in book overdrafts,~~2006, primarily from payments made to reduce outstanding borrowings ~~under~~on our revolving credit facility ~~and proceeds~~by $45 million as well as dividend payments, partially offset by cash inflows from the exercise of stock options ~~partially offset by dividend payments~~ and ~~purchases of treasury stock.~~the tax benefit received from stock-based compensation.

At ~~September 30, 2006,~~March 31, 2007, we had ~~$150 million of debt~~no borrowings outstanding under our credit facility. ~~Subsequent to the end of the third quarter, on October 2, 2006, we repaid the entire $150 million outstanding balance with proceeds from the sale of assets.~~ The credit facility 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. 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. 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.

In August 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. As a result of the 3-for-2 stock split effected in March 2005, this figure was adjusted to three million shares. During the first nine months of 2006, we repurchased 1,088,500 shares of our common stock at a weighted average price of $42.71. All of the repurchases occurred during the second and third quarters. All purchases executed to date have been through open market transactions. OnIn October ~~26,~~ 2006, we announced that our Board of Directors increased the number of shares of our common stock authorized for repurchase by an additional two million shares for a total of five million shares. As a result of the 2-for-1 stock split effected in March 2007, this figure was adjusted to 10 million shares. During the first quarter of 2007, 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 maximum number of shares that may yet be purchased under the plan as of ~~September 30, 2006~~March 31, 2007 was ~~397,650.~~4,795,300. See “Unregistered Sales of Equity Securities – Issuer Purchases of Equity Securities” in Item 2 of Part II of this quarterly report.

During the ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, we paid dividends of ~~$5.8~~$1.9 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.

~~On May 4, 2006, our stockholders approved an~~ After the March 2007 2-for-1 stock split, the dividend was increased to $0.03 per share per quarter, or a 50% increase ~~in the authorized number of shares of our common stock~~ from 80 million to 120 million shares. We correspondingly increased the number of shares of Series A Junior Participating Preferred Stock reserved for issuance from 800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to our Rights Agreement with The Bank of New York, as Rights Agent.pre-split levels.

On an annual basis, we generally fund most of our capital and exploration activities, excluding 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 capital and exploration expenditures for the ~~nine~~three months ended ~~September 30, 2006~~March 31, 2007 and ~~2005.~~2006:

During the nine months ended September 30, 2005, we spent $60.4 million on producing property acquisitions. Of this amount, $59.4 million was spent in the third quarter of 2005. During the third quarter of 2005, we closed on two large producing property acquisitions for interests in fields in the Gulf Coast region. For the McCampbell field acquisition, we spent $41.2 million. The Vernon field acquisition was $18.0 million. During the nine months ended September 30, 2006, primarily in the third quarter, we spent $6.6 million on producing property acquisitions in the Gulf Coast region.

We plan to drill approximately ~~391~~440 gross wells in ~~2006.~~2007. This drilling program includes approximately ~~$500~~$434 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. ~~The increase in our leasehold acquisitions expense from September 30, 2005 to September 30, 2006 is the result of several new exploratory resource areas in all regions.~~ We will continue to assess the natural gas and crude oil price environment and may increase or decrease the capital and exploration expenditures accordingly.

During the ~~nine~~three months ended ~~September 30, 2006,~~March 31, 2007, certain events have occurred changing the amounts previously reported in our contractual obligations table for drilling rig commitments and firm gas transportation agreements in our Annual Report on Form 10-K for the year ended December 31, ~~2005.~~2006.

Our firm gas transportation agreements provide firm transportation capacity rights on pipeline systems in Canada, the West region and the East ~~regions.~~region. The amount of transportation demand charges under these agreements that we are estimated to pay, regardless of the amount of pipeline capacity we utilize, has decreased by approximately ~~$3.8~~$2.4 million ~~over~~from the total ~~remaining terms of these contracts, which range from less than one year to 21 years.~~$85.1 million figure previously disclosed. This is due to ~~rate changes and~~ released volumes on ~~certain contracts, partially offset by increased charges as a result of new contracts entered into~~one contract in ~~Canada. Demand charges for 2006 are expected to be $7.1 million, a decrease of $4.6 million from~~ the $11.7 million figure previously disclosed. Future obligations that we expect to pay starting in 2007 under these firm gas transportation agreements in effect at September 30, 2006 have increased by $0.8 million to $82.9 million.West region.

Drilling rig commitments increased by $0.7 million from the $120.3 million figure reported in ~~the~~our Annual Report on Form 10-K for the year ended December 31, ~~2005 totaled $104.3 million. As~~2006. This increase was due to an increase in the daily rig rates on two rigs as a result of an ~~additional contract entered into during 2006, renewals~~increase of ~~existing contracts~~5% in the U.S. Department of Labor Wholesale Price Index for Oilfield Machinery and ~~increases~~Tools from the base index, as required in ~~daily rates due to increased contractor expenses for certain rigs, our total commitments have increased by $11.3 million.~~the commitment agreement.

For further information, please refer to “Firm Gas Transportation Agreements” and “Rig Commitments” under Note 6 in the Notes to the Condensed Consolidated Financial Statements.

Our discussion and analysis of our financial condition and results of operations 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 us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Annual Report on Form 10-K for the year ended December 31, ~~2005,~~2006, for further discussion of our critical accounting policies.

Effective January 1, ~~2006,~~2007, we adopted the ~~accounting policies described in SFAS~~provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 123(R), “Share Based Payment (revised 2004).” We chose to use the modified prospective method of transition, and accordingly, no adjustments to prior period financial statements have been made. Prior to January 1, 2006, we accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion (APB) No. 25,48, “Accounting for ~~Stock Issued~~Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” Due to Employees.” In addition, SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments.

One primary difference in our method of accounting after the adoption of SFAS No. 123(R) is that unvested stock options will now be expensed as a component of Stock-Based Compensation cost in the General and Administrative Expense line item of the Condensed Consolidated Statement of Operations. This expense will be based on the fair value of the award at the original grant date and will be recognized over the vesting period. Prior to the adoption of SFAS No. 123(R), we included this amount as a pro-forma disclosure in the Notes to the Condensed Consolidated Financial Statements. The expense resulting from the expensing of stock options is $0.2 million for the nine months ended September 30, 2006. Another change relates to the accounting for our performance share awards. Certain of these awards are now accounted for by bifurcating the equity and liability components. A Monte Carlo model is used to value the liability component, rather than accounting for the award using the average closing stock price at the end of each reporting period. All other awards are accounted for in substantially the same way as they were or would have been in prior periods, with the exception of the differences noted below.

Other differences in the way we account for stock-based compensation after January 1, 2006, result from the application of a forfeiture rate to all grants rather than recording actual forfeitures as they occur. We are now required to estimate forfeitures on all equity-based compensation and adjust periodic expense. Upon adoption, we ~~did not record~~recorded a cumulative effect adjustment for these forfeitures as the amount is immaterial. In addition, this change in accounting for forfeitures results in an immaterial change in overall compensation cost for the nine months ended September 30, 2006. Furthermore, we are required to immediately expense certain awards to retirement-eligible employees depending on the structurecharge of each individual plan. The retirement-eligibility provision only applies to new grants that were awarded after January 1, 2006. The total expense that we immediately recognized related to restricted stock awards granted to retirement-eligible employees in the first nine months of 2006 is $0.5 million.

We issued stock appreciation rights to executive employees for the first time during the first quarter of 2006. The grant date fair value of these awards is measured using a Black-Scholes model and compensation cost is expensed over the three year graded-vesting service period. Expense related to these awards is $0.7less than $0.1 million before the effect of taxes, for the first nine months of 2006. In addition, a new type of performance share was issued to employees. These awards measure our performance based on three internal metrics rather than a peer group’s stock performance used for our other performance share awards. These awards cliff vest at the end of the three year service period. Compensation cost related to these new internal-metric based performance share awards granted to employees is $1.0 million, before the effect of taxes, for the first nine months of 2006. In addition, we incurred a $0.4 million, net of tax, cumulative effect charge in the first quarter of ~~2006 as a result of changes made in our accounting~~2007 for performance shares. For further information on the accounting for these and our other stock-based compensation awards, please refer to Notes 1 and 11 to the Notes to the Condensed Consolidated Financial Statements.

During the third quarter of 2006, we adopted the provisions outlined under FSP FAS No. 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which discusses accounting for taxes for stock awards using the APIC Pool concept. We have made a one time election as prescribed under the FSP to use the shortcut approach to derive the initial windfall tax benefit pool. We chose to use a one pool approach which combines all awards granted to employees, including non-employee directors.

Our Compensation Committee of our Board of Directors made one modification to our stock option awards in 2005. It approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under our Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under our 2004 Incentive Plan.

The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in each of April 2006 and April 2007. The decision to accelerate the vesting of these unvested options, which we believed to be in the bestincremental interest ~~of our shareholders and employees, was made solely to reduce compensation~~ expense ~~and administrative burden associated with our~~that is more likely than not payable. This adoption ~~of SFAS No. 123(R). The accelerated vesting of the options~~ did not have ana material impact on any of our ~~results of operations or cash flows for 2005. The acceleration of vesting reduced our compensation expense related to these options by approximately $0.2 million for 2006.~~financial statements.

We reported net income in the ~~third~~first quarter of ~~2006~~2007 of ~~$189.0~~$48.5 million, or ~~$3.92~~$0.50 per share. During the corresponding quarter of ~~2005,~~2006, we reported net income of ~~$33.8~~$53.2 million, or ~~$0.69~~$0.55 per share. Net income ~~increased~~decreased in the ~~third~~first quarter by ~~$155.2~~$4.7 million, primarily due to ~~an increase~~a decrease in operating income of ~~$245.7~~$12.0 million from ~~$59.0~~$91.2 million in the ~~third~~first quarter of ~~2005~~2006 to ~~$304.7~~$79.2 million in the ~~third~~first quarter of ~~2006.~~2007. This ~~increase~~decrease in net income was primarily due ~~to the $229.7 million ($143.6 million net of tax) gain on the sale of offshore and certain south Louisiana assets recorded in the third quarter of 2006 as well as an increase~~a decrease in natural gas and crude oil production ~~revenues. This income increase is~~revenues, partially offset by ~~an increase~~a decrease of ~~$88.8~~$5.2 million in income tax expense ~~as well as an increase~~and a decrease in operating expenses of ~~$7.0 million.~~$3.5 million, primarily as a result of reduced exploration expense, partially offset by general and administrative and other operating expense increases.

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, ~~is $6.76~~was $7.42 per Mcf for the three months ended ~~September 30, 2006~~March 31, 2007 compared to ~~$6.77~~$8.22 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instrument settlements which increased the price by ~~$0.41~~$0.89 per Mcf in ~~2006~~2007 and ~~reduced the price by $1.26~~$0.08 per Mcf in ~~2005. The following table excludes the unrealized loss from the change in derivative fair value of $0.4 million for the three months ended September 30, 2005.~~2006. There iswas no unrealized impact from the change in derivative fair value for the three months ended ~~September 30,~~March 31, 2007 or 2006. ~~The unrealized change in fair value has been included in Natural Gas Production Revenues in the Statement of Operations.~~

The ~~increase~~decrease in Natural Gas Production Revenue is primarily due to the decrease in realized natural gas sales prices, partially offset by an increase in natural gas production. ~~Production is higher~~Prices were lower in all regions in the third quarter of 2006 compared to the third quarter of 2005. Increased production is primarily the result of the increased capital program in 2005 and 2006 and timing of initial production from the drilling program. Prices were lower overall quarter over quarter for the Company. The ~~increase in production and~~ decrease in the realized natural gas price and increase in production resulted in a net revenue ~~increase~~decrease of ~~$18.4~~$8.4 million. After removing $27.3 million ~~excluding the unrealized impact~~ of ~~derivative instruments. For the quarter ended September 30, 2006,~~ natural gas ~~volumes from~~revenues and 2,986 Mmcf of natural gas production associated with properties in the ~~properties~~Gulf Coast region sold in ~~the~~ third quarter ~~disposition were 2,952 Mmcf~~of 2006 divestiture from 2006 results, total natural gas revenue would have increased by $18.9 million, or 15%, and natural gas ~~revenues~~production would have increased by 3,872 Mmcf, or 24%, from ~~those properties were approximately $20.2 million.~~the first quarter of 2006 to the first quarter of 2007.

The ~~decreased~~increased brokered natural gas margin of ~~$0.4~~$0.9 million is driven by ~~decreased commodity prices for~~a decrease in purchase price that outpaced the ~~third quarter of 2006 compared~~decrease in sales price in addition to ~~the third quarter of 2005. Partially offsetting this decrease is~~ an increase in the volumes brokered in the ~~third~~first quarter of ~~2006~~2007 over the same period in the prior year.

Our average total company realized crude oil sales price ~~is $69.80~~was $53.36 per Bbl for the ~~third~~first quarter of ~~2006. There is no~~2007. The 2007 price includes the realized impact of derivative ~~instruments in~~instrument settlements which increased the ~~third quarter of 2006.~~price by $0.89 per Bbl. Our average total company realized crude oil sales price, including the realized impact of derivative instruments, ~~is $46.05~~was $61.11 per Bbl for the ~~third~~first quarter of ~~2005. The 2005 price includes the~~2006. There was no realized impact of derivative ~~instrument settlements which reduced~~instruments in the ~~price by $14.59 per Bbl. The following table excludes the unrealized gain from the change in derivative fair value of $2.0 million for the third~~first quarter of ~~2005.~~2006. There iswas no unrealized impact from the change in derivative fair value for the ~~third~~either first quarter of 2007 or 2006. ~~The unrealized change in fair value has been included in Crude Oil and Condensate Revenues in the Statement of Operations.~~

The ~~increase~~decrease in the realized crude oil price combined with the decline in production resulted in a net revenue ~~increase~~decrease of ~~$7.1 million, excluding the unrealized impact of derivative instruments.~~$13.3 million. The decrease in oil production is mainly the result of ~~decreased Gulf Coast production from~~ the ~~continued natural decline of the CL&F lease in south Louisiana, which was sold~~sale in the third quarter of ~~2006. For~~2006 of certain south Louisiana and offshore properties in the ~~quarter ended September 30, 2006,~~Gulf Coast region. After removing $15.4 million of crude oil revenues and ~~condensate volumes from~~250 Mbbls of crude oil production associated with properties in the ~~properties~~Gulf Coast region sold in ~~the~~ third quarter ~~disposition were 196 Mbbl~~of 2006 divestiture from 2006 results, total crude oil revenue would have increased by $2.2 million, or 25%, and crude oil ~~and condensate revenues~~production would have increased by 59 Mbbls, or 40%, from ~~those properties were approximately $13.9 million.~~the first quarter of 2006 to the first quarter of 2007.

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

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.

Other operating revenues ~~increased~~decreased by ~~$0.8~~$1.9 million between the ~~third~~first quarter of ~~2006~~2007 and ~~the third quarter of 2005 primarily due to a decrease in our payout liability associated with a favorable legal ruling in~~ the first quarter of 2006 ~~which correspondingly increased other revenues, as well as~~primarily due to an increase in ~~cash received for a net profits interest that originated in 2006.~~our payout liability, which correspondingly decreased other revenues.

Total costs and expenses from operations ~~increased $7.0~~decreased $3.5 million in the ~~third~~first quarter of ~~2006~~2007 compared to the same period of ~~2005.~~2006. The primary reasons for this fluctuation are as follows:

Direct Operations expense increased by $5.6 million over the third quarter of 2005. This is primarily the result of an increase over the prior year quarter in outside operated properties expense, primarily in the Gulf Coast, due to offshore activity, including hurricane repairs. In addition, higher expenses were incurred related to disposal costs, treating, compressors and workovers. These increases were primarily seen in the Gulf Coast region due to additional usage, rates and production in addition to timing. In addition, we incurred higher insurance expenses due to premium increases as well as higher expenses for compensation and personnel related expenses.

Depreciation, Depletion and Amortization increased by $5.5 million in the third quarter of 2006. This is primarily due to increased production for the quarter, an increase in finding costs and an increase in the DD&A rate associated with one field in East Texas as well as the commencement of offshore production in late 2005.

General and Administrative expense increased by $1.0 million in the third quarter of 2006. Third quarter 2005 expense included a credit to miscellaneous expenses for a reversal of a reserve attributable to litigation settled during the quarter. Partially offsetting this increase is a decrease in the third quarter 2006 stock compensation expense of $1.1 million due to the change in accounting for performance share compensation as prescribed by SFAS No. 123(R).

Exploration expense decreased by ~~$3.1~~$5.9 million in the ~~third~~first quarter of ~~2006,~~2007, primarily as a result of a decrease in total dry hole expense of ~~$2.1~~$3.2 million ~~which is primarily comprised of~~and a decrease in ~~dry hole expense in the Gulf Coast region, partially offset by increases in Canada and the West region, as well as decreased~~ geophysical and geological expenses of ~~$1.1~~$2.4 million, primarily in Canada and the ~~West.~~Gulf Coast region

~~Brokered Natural Gas Cost decreased~~General and Administrative expense increased by ~~$1.3~~$4.0 million ~~from~~in the ~~third~~first quarter of ~~2005~~2007 primarily due to increased stock compensation charges of $1.7 million resulting from new stock awards issued during the first quarter of 2007, increased performance share expense as a result of a favorable company ranking against its peers and the associated increase in the liability related to the ~~third quarter~~cash portion of ~~2006. See~~ the ~~preceding table labeled “Brokered Natural Gas Revenue~~awards, and ~~Cost”~~increased SAR expense for ~~further analysis.~~retirement eligible employees which are expensed immediately upon grant. Additionally, expense for litigation accruals increased by $0.5 million.

Taxes Other Than Income decreased by ~~$0.6~~$2.4 million in the first three months of 2007 compared to the ~~third quarter~~first three months of ~~2005,~~2006, primarily due to decreased production taxes of $1.1 million as a result of decreased natural gas ~~prices.~~and crude oil prices as well as a decrease of $1.1 million in ad valorem taxes.

Depreciation, Depletion and Amortization increased by $1.5 million in the first quarter of 2007. This is primarily due to negative reserve revisions due to lower prices at year-end, higher capital costs and commencement of production in an East Texas field.

Interest Expense, Net

Interest expense, net ~~increased $1.8~~decreased by $2.2 million in the ~~third~~first quarter of ~~2006~~2007 due to ~~higher~~lower credit facility borrowings, ~~as well as an increasing~~lower borrowings on our 7.19% fixed rate debt and increased interest ~~rate environment.~~on our short term investments. Weighted average borrowings on our credit facility based on daily balances were approximately ~~$113~~$3 million during the ~~third~~first quarter of ~~2006~~2007 compared to ~~$49~~approximately $70 million during the ~~third~~first quarter of ~~2005.~~2006.

Income Tax Expense

Income tax expense ~~increased~~decreased by ~~$88.8~~$5.2 million due to a comparable ~~increase~~decrease in our pre-tax income, primarily as a result of the ~~gain on the sale of assets recorded~~decrease in ~~the third quarter.~~revenues. The effective tax rate for the ~~third~~first quarter of 2007 and 2006 was 35.5% and ~~2005 is 36.5% and 37.1%~~37.5%, respectively. The decrease in the effective tax rate is primarily due to the recognition of a change in the Texas state income tax rate due to a change in the tax law in May 2006. In addition, there was a ~~change~~reduction in the overall blended state income tax rate due to the sale of certain south Louisiana and offshore ~~properties.~~

~~Nine Months of 2006 and 2005 Compared~~

We reported net income in the first nine months of 2006 of $289.0 million, or $5.95 per share. During the corresponding period of 2005, we reported net income of $89.9 million, or $1.84 per share. Net income increased in the current period by $199.1 million primarily due to an increase in operating income as a result of the gain of $229.7 million ($143.6 million, net of tax) recorded in the third quarter of 2006 related to the disposition of our offshore and certain south Louisiana properties as well as an increase in natural gas and oil production revenues. This increase is partially offset by an increase in total operating expenses of $47.0 million and an increase of $112.3 million in income tax expense. Operating income increased $315.5 million compared to the prior year, from $158.8 million in the first nine months of 2005 to $474.3 million in the first nine months of 2006.

~~Natural Gas Production Revenues~~

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, is $7.22 per Mcf for the nine months ended September 30, 2006 compared to $6.16 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instrument settlements which increased the price by $0.28 per Mcf in 2006 and reduced the price by $0.73 per Mcf in 2005. The following table excludes the unrealized loss from the change in derivative fair value of $0.2 million for the nine months ended September 30, 2005. There is no unrealized impact from the change in derivative fair value for the nine months ended September 30, 2006. The unrealized change in fair value has been included in Natural Gas Production Revenues in the Statement of Operations.

   Nine Months Ended
September 30,    Variance
   2006 2005    Amount Percent
Natural Gas Production (Mmcf)

Gulf Coast
   23,881 21,007    2,874 14 %
West
   17,272 17,337    (65 ) —
East
   17,581 15,669    1,912 12 %
Canada
   1,778 818    960 117 %

Total Company
   60,512 54,831    5,681 10 %

Natural Gas Production Sales Price ($/Mcf)

Gulf Coast
   $ 7.41 $ 6.26    $ 1.15 18 %
West
   $ 6.19 $ 5.38    $ 0.81 15 %
East
   $ 8.09 $ 6.90    $ 1.19 17 %
Canada
   $ 6.10 $ 5.95    $ 0.15 3 %
Total Company
   $ 7.22 $ 6.16    $ 1.06 17 %
Natural Gas Production Revenue (in thousands)

Gulf Coast
   $ 176,888 $ 131,548    $ 45,340 34 %
West
   106,953 93,229    13,724 15 %
East
   142,248 108,109    34,139 32 %
Canada
   10,842 4,866    5,976 123 %

Total Company
   $ 436,931 $ 337,752    $ 99,179 29 %

Price Variance Impact on Natural Gas Production Revenue

(in thousands)

Gulf Coast
   $ 27,461
West
   14,071
East
   20,949
Canada
   270

Total Company
   $ 62,751

Volume Variance Impact on Natural Gas Production Revenue

(in thousands)

Gulf Coast
   $ 17,879
West
   (347 )
East
   13,190
Canada
   5,706

Total Company
   $ 36,428

The increase in Natural Gas Production Revenue is due to the increase in natural gas sales prices and, to a lesser extent, the increase in natural gas production. Prices were higher in all regions and production increased in the Gulf Coast, East and Canada. Slightly decreased production in the West is due to natural declines as well as lower production on a small number of non-operated wells. The increase in the total realized natural gas price and production resulted in a net revenue increase of $99.2 million, excluding the unrealized impact of derivative instruments. For the nine months ended September 30, 2006, natural gas volumes from the properties sold in the third quarter disposition were 9,143 Mmcf and natural gas revenues from those properties were approximately $70.9 million.

~~Brokered Natural Gas Revenue and Cost~~

   Nine Months Ended
September 30,    Variance
   2006 2005    Amount    Percent
Sales Price ($/Mcf)
   $ 8.13 $ 7.82    $ 0.31    4 %
Volume Brokered (Mmcf)
   8,292 7,773    519    7 %

Brokered Natural Gas Revenues (in thousands)
   $ 67,389 $ 60,768

Purchase Price ($/Mcf)
   $ 7.23 $ 6.89    $ 0.34    5 %
Volume Brokered (Mmcf)
   8,292 7,773    519    7 %

Brokered Natural Gas Cost (in thousands)
   $ 59,924 $ 53,549

Brokered Natural Gas Margin (in thousands)
   $ 7,465 $ 7,219    $ 246    3 %

(in thousands)

Sales Price Variance Impact on Revenue
   $ 2,562
Volume Variance Impact on Revenue
   4,059

   $ 6,621

(in thousands)

Purchase Price Variance Impact on Purchases
   $ (2,799 )
Volume Variance Impact on Purchases
   (3,576 )

   $ (6,375 )

~~The increased brokered natural gas margin of $0.2 million is driven by an increase in brokered volumes partially offset by an increased purchase cost that outpaced the increase in sales price.~~

~~Crude Oil and Condensate Revenues~~

Our average total company realized crude oil sales price is $66.42 per Bbl for the first nine months of 2006. There is no realized impact of derivative instruments in the first nine months of 2006. Our average total company realized crude oil sales price, including the realized impact of derivative instruments, is $43.92 per Bbl for the first nine months of 2005. The 2005 price includes the realized impact of derivative instrument settlements which reduced the price by $8.93 per Bbl. The following table excludes the unrealized loss from the change in derivative fair value of $1.9 million for the first nine months of 2005. There is no unrealized impact from the change in derivative fair value for the first nine months of 2006. The unrealized change in fair value has been included in Crude Oil and Condensate Revenues in the Statement of Operations.

   Nine Months Ended
September 30,    Variance
   2006 2005    Amount Percent
Crude Oil Production (Mbbl)

Gulf Coast
   1,020 1,189    (169 ) (14 )%
West
   162 123    39 32 %
East
   19 20    (1 ) (5 )%
Canada
   8 14    (6 ) (43 )%

Total Company
   1,209 1,346    (137 ) (10 )%

Crude Oil Sales Price ($/Bbl)

Gulf Coast
   $ 66.71 $ 42.72    $ 23.99 56 %
West
   $ 64.99 $ 54.21    $ 10.78 20 %
East
   $ 63.29 $ 52.98    $ 10.31 19 %
Canada
   $ 65.90 $ 42.23    $ 23.67 56 %
Total Company
   $ 66.42 $ 43.92    $ 22.50 51 %
Crude Oil Revenue (in thousands)

Gulf Coast
   $ 67,967 $ 50,804    $ 17,163 34 %
West
   10,545 6,651    3,894 59 %
East
   1,220 1,074    146 14 %
Canada
   551 586    (35 ) (6 )%

Total Company
   $ 80,283 $ 59,115    $ 21,168 36 %

Price Variance Impact on Crude Oil Revenue

(in thousands)

Gulf Coast
   $ 24,397
West
   1,804
East
   167
Canada
   198

Total Company
   $ 26,566

Volume Variance Impact on Crude Oil Revenue

(in thousands)

Gulf Coast
   $ (7,234 )
West
   2,090
East
   (21 )
Canada
   (233 )

Total Company
   $ (5,398 )

The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $21.2 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is primarily the result of decreased Gulf Coast production from the continued natural decline of the CL&F lease in south Louisiana, which was sold in the third quarter of 2006. For the nine months ended September 30, 2006, crude oil and condensate volumes from the properties sold in the third quarter disposition were 634 Mbbl and crude oil and condensate revenues from those properties were approximately $42.8 million.

~~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:~~

Nine Months Ended
September 30,

   2006    2005
   Realized    Unrealized    Realized Unrealized
   (In thousands)
Operating Revenues - Increase/(Decrease) to Revenue

Cash Flow Hedges

Natural Gas Production
   $ 17,166    $ —      $ (40,211 ) $ (186 )
Crude Oil
   —      —      (1,552 ) (103 )

Total Cash Flow Hedges
   17,166    —      (41,763 ) (289 )
Other Derivative Financial Instruments

Crude Oil
   —      —      (10,470 ) (1,762 )

Total Other Derivative Financial Instruments
   —      —      (10,470 ) (1,762 )

   $ 17,166    $ —      $ (52,233 ) $ (2,051 )

~~Other Operating Revenues~~

Other operating revenues increased by $3.6 million between the first nine months of 2006 and the first nine months of 2005 primarily due to an increase in net profits interest that originated in 2006 as well as a decrease in our payout liability associated with a favorable legal ruling in the first quarter of 2006. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year period.

~~Operating Expenses~~

~~Total costs and expenses from operations increased $47.0 million in the first nine months of 2006 compared to the same period of 2005. The primary reasons for this fluctuation are as follows:~~

Depreciation, Depletion and Amortization increased by $17.5 million in the first nine months of 2006. This is primarily due to increased production for the first nine months of 2006, an increase in finding costs and an increase in the ~~DD&A~~qualified production activities deduction rate ~~associated with one field in East Texas as well as the commencement of offshore production in late 2005.~~

Direct Operations expense increased by $12.3 million over the first nine months of 2005. This is primarily the result of an increase over the prior year period in outside operated properties expense, compressor expense, workovers, treating and disposal costs, as well as expenses for incentive compensation and personnel related charges. The increase in outside operated properties expense resulted from ~~increases in the Gulf Coast region, largely from accruals related~~three percent to ~~repairs on a plant damaged by the hurricanes that occurred in 2005 and also, to a lesser extent, in the West region.~~

General and Administrative expense increased by $10.7 million in the first nine months of 2006. This increase is primarily due to increased stock compensation costs of $5.0 million. During the first nine months of 2006, performance share and restricted stock amortization expense increased by $2.6 million and $1.5 million, respectively, primarily due to new grants issued in 2006 and changes in the accounting for the value of performance shares. For the first nine months of the year, expense related to SARs, which were granted for the first time in 2006, and stock options, which are being expensed in 2006 due to the adoption of SFAS No. 123(R), increased by $0.9 million in total. In addition, there is an increase in litigation expense and incentive compensation related to employee bonuses over the first nine months of the prior year.

Taxes Other Than Income increased by $7.4 million compared to the first nine months of 2005, primarily due to increased production taxes as a result of increased commodity prices as well as an increase in ad valorem taxes and, to a lesser extent, franchise taxes.

Brokered Natural Gas Cost increased by $6.4 million from the first nine months of 2005 to the first nine months of 2006. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.

Exploration expense decreased by $7.4 million in the first nine months of 2006, primarily as a result of decreased dry hole expense of $9.1 million, mainly as a result of a decrease in the Gulf Coast attributable to a more successful drilling program in the first nine months of 2006 compared to the first nine months of 2005 and, to a lesser extent, better success in Canada, partially offset by an increase in dry hole expense in the West region. Partially offsetting this overall decrease in dry hole expense is an increase in employee expenses for salaries and benefits of approximately $0.8 million for employees in this division as well as increased delay rental expenses of $0.4 million.

~~Interest Expense, Net~~

Interest expense, net increased $4.0 million in the first nine months of 2006 due to higher credit facility borrowings as well as an increasing interest rate environment. Weighted average borrowings based on daily balances were approximately $81 million during the first nine months of 2006 compared to $49 million during the first nine months of 2005.

~~Income Tax Expense~~

Income tax expense increased by $112.3 million due to a comparable increase in our pre-tax income, primarily as a result of the gain on the sale of assets recorded in the third quarter of 2006. The effective tax rate for the first nine months of 2006 and 2005 is 36.4% and 37.2%, respectively. The decrease in the effective tax rate is primarily due to the recognition of a change in the Texas state income tax rate due to a change in the tax law in May 2006. In addition, there was a change in the overall blended state income tax rate due to sale in the third quarter of 2006 of certain south Louisiana and offshore properties.six percent.

Recently Issued Accounting Pronouncements

In February ~~2006,~~2007, the FASB issued Statement of Financial Accounting Standards ~~Board (FASB) issued SFAS~~(SFAS) No. ~~155, “Accounting~~159, “The Fair Value Option for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and ~~Extinguishments of~~Financial Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form. We do not believe that our financial position, results of operations or cash flows will be impacted by SFAS No. 155 as we do not currently hold any hybrid financial instruments.

~~In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation~~ including an amendment of FASB Statement No. ~~109.~~115,” ~~This Interpretation provides guidance~~which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of this Statement is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of the Statement apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for ~~recognizing and measuring uncertain tax positions, as defined in~~instruments for which the fair value option is elected. SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit of the uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN 48 provides additional guidance on measuring the amount of the uncertain tax position. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and disclosure of these uncertain tax positions. FIN 48159 is effective for fiscal years beginning after ~~December~~November 15, ~~2006.~~2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. We are currently evaluating ~~the~~what impact SFAS No. 159, if ~~any, that this Interpretation~~adopted, may have on our financial position, results of ~~operations and cash flows.~~operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by ~~U.S~~United States. generally accepted accounting principles (GAAP) to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement (CON) No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. No new fair value measurements are prescribed, and SFAS No. 157 is intended to codify the several definitions of fair value included in various accounting standards. However, the application of this Statement may change current practices for certain companies. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating what impact SFAS No. 157 may have on our financial position, results of ~~operations or cash flows.~~

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158 requires recognition of the funded status of a benefit plan in the balance sheet and the recognition through other comprehensive income of gains, losses, prior service costs and credits, net of tax, arising during the period but not included as a component of periodic benefit cost. In addition, the measurement date of plan assets and obligations must be as of a Company’s balance sheet date. Additional disclosures in the notes to the financial statements will also be required and guidance is prescribed regarding the selection of discount rates to be used in measuring the benefit obligation. For public companies, the effective date of SFAS No. 158 is as of the end of the fiscal year ending after December 15, 2006. The effective date of the new measurement date provision is for fiscal years ending after December 15, 2008; however, our measurement date is currently its balance sheet date, so no change will be required. We plan to adopt this standard using the prospective transition method of adoption effective with our Annual Report on Form 10-K for the year ended December 31, 2006. The anticipated incremental effect of SFAS No. 158 is to increase our total liabilities and total assets by $18.7 million and $7.1 million, respectively, and to decrease total stockholders’ equity by $11.6 million based on actuarial reports as of September 30, 2006.

In September 2006, the SEC Staff issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB No. 108, the two methods used for quantifying the effects of financial statement errors were the “roll-over” and “iron curtain” methods. Under the “roll-over” method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The criticism of this method is that misstatements can accumulate on the balance sheet. On the other hand, the “iron curtain” method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB No. 108 establishes a “dual approach” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. We are currently evaluating the impact that SAB No. 108 may have on our financial position, results of operations and cash flows.operations.

Forward-Looking Information

The statements regarding future financial performance and results, market prices and the other statements which are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict” 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. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

~~ITEM 3. Quantitative and Qualitative Disclosures about Market Risk~~

ITEM 3.

Quantitative and Qualitative Disclosures about Market Risk

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 and Note 7 of the Notes to the Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

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 the first ~~nine~~three months of ~~2006,~~2007, natural gas price collars covered ~~20,328~~10,487 Mmcf, or ~~34%~~53%, of our ~~2006~~first quarter 2007 gas production, with a weighted average floor of ~~$8.25~~$8.99 per Mcf and a weighted average ceiling of ~~$12.74~~$12.19 per Mcf.

At ~~September 30, 2006,~~March 31, 2007, we had open natural gas price collar contracts covering a portion of our ~~2006~~2007 and 2008 production as follows:


	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor *(per Mcf)*		Net Unrealized Gain / (Loss) *(In thousands)*
As of March 31, 2007
Second Quarter 2007	10,604	$	12.19 / $8.99
Third Quarter 2007	10,721		12.19 / 8.99
Fourth Quarter 2007	10,721		12.19 / 8.99

Nine Months Ended December 31, 2007	32,046	$	12.19 / $8.99	$	30,032

First Quarter 2008	1,637	$	11.15 / $8.62
Second Quarter 2008	1,637		11.15 / 8.62
Third Quarter 2008	1,655		11.15 / 8.62
Fourth Quarter 2008	1,655		11.15 / 8.62

Full Year 2008	6,584	$	11.15 / $8.62	$	(650	)

During the first three months of 2007, a crude oil price collar covered 90 Mbbls, or 44%, of our first quarter 2007 oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.

At March 31, 2007, we had one open crude oil price collar contract covering a portion of our 2007 production as follows:

   Natural Gas Price Collars
Contract Period
   Volume
in
Mmcf
Weighted
Average
Ceiling /Floor (per Mcf)

Net Unrealized
Gain
(In thousands)
As of September 30, 2006

Fourth Quarter 2006
   6,851    $12.74 / $8.25

Three Months Ended December 31, 2006
   6,851    $12.74 / $8.25    $ 16,670

First Quarter 2007
   8,444    $12.45 / $9.09
Second Quarter 2007
   8,538    12.45 / 9.09
Third Quarter 2007
   8,632    12.45 / 9.09
Fourth Quarter 2007
   8,632    12.45 / 9.09

Full Year 2007
   34,246    $12.45 /$9.09    $ 51,257

During the first nine months of 2006, crude oil price collars covered 273 Mbbls, or 23%, of our 2006 oil production, with a weighted average floor of $50.00 per Bbl and a weighted average ceiling of $76.00 per Bbl.

~~At September 30, 2006, we had open crude oil price collar contracts covering our 2006 and 2007 production as follows:~~

   Crude Oil Price Collar
Contract Period
   Volume
in
Mbbl
Weighted
Average
Ceiling /Floor (per Bbl)

Net Unrealized
(Loss) / Gain
(In thousands)

As of September 30, 2006

Fourth Quarter 2006
   92    $76.00 / $50.00

Three Months Ended December 31, 2006
   92    $76.00 / $50.00    $ (16 )

First Quarter 2007
   90    $80.00 / $60.00
Second Quarter 2007
   91    80.00 / 60.00
Third Quarter 2007
   92    80.00 / 60.00
Fourth Quarter 2007
   92    80.00 / 60.00

Full Year 2007
   365    $80.00 / $60.00    $ 212


	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Ceiling / Floor *(per Bbl)*		Net Unrealized Gain *(In thousands)*
As of March 31, 2007
Second Quarter 2007	91	$	80.00 / $60.00
Third Quarter 2007	92		80.00 / 60.00
Fourth Quarter 2007	92		80.00 / 60.00

Nine Months Ended December 31, 2007	275	$	80.00 / $60.00	$	35

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 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.

~~ITEM 4. Controls and Procedures~~

ITEM 4.

Controls and Procedures

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

~~ITEM 1. Legal Proceedings~~

ITEM 1.

Legal Proceedings

The information set forth under the ~~captions~~caption “West Virginia Royalty ~~Litigation,” “Texas Title~~ Litigation” ~~and “Raymondville Area”~~ in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q is incorporated by reference in response to this item.

~~ITEM 1A. Risk Factors~~

ITEM 1A.

Risk Factors

For additional information about the risk factors facing the Company, see Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2005.~~2006.

~~ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds~~

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period

Total
Number of
Shares
Purchased

Average
Price Paid
per Share

Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plans or
Programs

Maximum
Number
of Shares that
May Yet Be
Purchased
Under the
Plans or
Programs
July 2006
   —      $ —      —      819,950
August 2006
   —      $ —      —      819,950
September 2006
   422,300    $ 45.71    422,300    397,650

Total
   422,300    $ 45.71

In August 1998, the Company announced that its Board of Directors authorized the repurchase of two million shares of ~~the Company’s~~its common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure was adjusted to three million shares. In October 2006, the Company announced that its Board of Directors increased the number of shares of our common stock authorized for repurchase by an additional two million shares for a total of five million shares. As a result of the 2-for-1 stock split effected in March 2007, this figure was adjusted to 10 million shares. During the first quarter of 2007, the Company did not repurchase any shares of its common stock. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase ~~securities of the Company.~~

~~On October 26, 2006, the Company announced that its Board of Directors increased the~~these securities. The maximum number of shares that may yet be purchased under the plan as of ~~common stock authorized for repurchase by an additional two million shares.~~March 31, 2007 was 4,795,300.

~~ITEM 6. Exhibits~~

ITEM 6.

Exhibits


* 10.14.2		~~Purchase~~By-laws as amended and ~~Sale~~restated May 2, 2007

4.3		Rights Agreement dated ~~August 25, 2006~~as of March 28, 1991 between the Company and The First National Bank of Boston, as Rights Agent, as amended and restated as of December 8, 2000, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-K for December 21, 2000).

		(a) Amendment to Rights Agreement dated as of January 1, 2003 (The Bank of New York as rights agent).

		(b) Amendment to Rights Agreement dated as of March 30, 2007(regarding uncertified shares).

10.24		Amendment to the Cabot Oil & Gas Corporation a Delaware corporation, Cody Energy LLC, a Colorado limited liability company, and Phoenix Exploration Company LP, a Delaware limited partnership (incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K dated September 29, 2006).2004 Incentive Plan

15.1		Awareness letter of PricewaterhouseCoopers LLP

31.1		302 Certification - Chairman, President and Chief Executive Officer

31.2		302 Certification - Vice President and Chief Financial Officer

32.1		906 Certification

*	~~Incorporated by reference as indicated~~

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	CABOT OIL & GAS CORPORATION
	(Registrant)

~~October 27, 2006~~May 2, 2007	By:	/s/ Dan O. Dinges
		Dan O. Dinges
		Chairman, President and
		Chief Executive Officer
		(Principal Executive Officer)

~~October 27, 2006~~May 2, 2007	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

~~October 27, 2006~~May 2, 2007	By:	/s/ Henry C. Smyth
		Henry C. Smyth
		Vice President, Controller and Treasurer
		(Principal Accounting Officer)

4933


		Part I. Financial Information	Page

Item 1.	~~Part I.~~ Financial ~~Information~~Statements

	~~Item 1. Financial Statements~~

	Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2007 and ~~Nine Months Ended September 30,~~ 2006 ~~and 2005~~	3

	Condensed Consolidated Balance Sheet at ~~September 30, 2006~~March 31, 2007 and December 31, ~~2005~~2006	4

	Condensed Consolidated Statement of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~	5

	Notes to the Condensed Consolidated Financial Statements	6

	Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information	2619

Item 2.	~~Item 2.~~ Management’s Discussion and Analysis of Financial Condition and Results of Operations	2720

Item 3.	~~Item 3.~~ Quantitative and Qualitative Disclosures about Market Risk	4529

Item 4.	~~Item 4.~~ Controls and Procedures	4631

Part II. Other Information

Item 1.	~~Item 1.~~ Legal Proceedings	4631

Item 1A.	~~Item 1A.~~ Risk Factors	4631

Item 2.	~~Item 2.~~ Unregistered Sales of Equity Securities and Use of Proceeds	4731

Item 6.	~~Item 6.~~ Exhibits	4832

Signatures	49	33


	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
*(In thousands, except per share amounts)*	2006		2005		2006			2005		2007		2006
OPERATING REVENUES
Natural Gas Production	$	140,261	$	121,477	$	436,931		$	337,566	$	146,750	$	155,167
Brokered Natural Gas		17,075		18,756		67,389			60,768		33,177		32,819
Crude Oil and Condensate		26,435		21,336		80,283			57,250		10,942		24,180
Other		973		188		5,703			2,131		704		2,602

		184,744		161,757		590,306			457,715		191,573		214,768
OPERATING EXPENSES
Brokered Natural Gas Cost		15,282		16,550		59,924			53,549		28,699		29,245
Direct Operations - Field and Pipeline		19,893		14,246		55,478			43,171
Direct Operations – Field and Pipeline											17,131		17,630
Exploration		13,561		16,665		39,972			47,396		5,652		11,614
Depreciation, Depletion and Amortization		32,088		26,578		96,815			79,346		33,395		31,935
Impairment of Unproved Properties		3,826		4,092		11,289			11,146		3,986		3,580
General and Administrative		10,715		9,679		38,079			27,339		18,280		14,252
Taxes Other Than Income		14,366		14,939		44,439			37,053		13,165		15,495

		109,731		102,749		345,996			299,000		120,308		123,751
Gain on Sale of Assets		229,733		15		229,944			74		7,920		207

INCOME FROM OPERATIONS		304,746		59,023		474,254			158,789		79,185		91,224
Interest Expense and Other		6,978		5,339		19,151			15,461		3,924		6,150

Income Before Income Taxes and Cumulative Effect of Accounting Change		297,768		53,684		455,103			143,328
Income Before Income Taxes											75,261		85,074
Income Tax Expense		108,748		19,928		165,651			53,388		26,714		31,909

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		189,020		33,756		289,452			89,940
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX (Note 11)		—		—		(403	)		—

NET INCOME	$	189,020	$	33,756	$	289,049		$	89,940	$	48,547	$	53,165

Basic Earnings Per Share - Before Accounting Change	$	3.92	$	0.69	$	5.96		$	1.84
Diluted Earnings Per Share - Before Accounting Change	$	3.84	$	0.68	$	5.85		$	1.81
Basic Loss Per Share - Accounting Change	$	—	$	—	$	(0.01	)	$	—
Diluted Loss Per Share - Accounting Change	$	—	$	—	$	(0.01	)	$	—
Basic Earnings Per Share	$	3.92	$	0.69	$	5.95		$	1.84	$	0.50	$	0.55
Diluted Earnings Per Share	$	3.84	$	0.68	$	5.84		$	1.81	$	0.50	$	0.54

Weighted Average Common Shares Outstanding		48,230		48,951		48,548			48,865		96,695		97,360
Diluted Common Shares (Note 5)		49,162		49,665		49,508			49,613		98,047		98,747


*(In thousands, except share amounts)*	September 30, 2006			December 31, 2005
*(In thousands, except share amounts)*				December 31, 2005			March 31,				December 31,
*(In thousands, except share amounts)*	September 30, 2006	September 30, 2006			December 31, 2005				2007				2006
*(In thousands, except share amounts)*		September 30, 2006			December 31, 2005
Current Assets
Cash and Cash Equivalents	$	322,123		$	10,626			$	57,442			$	41,854
Accounts Receivable		104,157			168,248
Accounts Receivable, Net									97,507				116,546
Income Taxes Receivable									—				24,512
Inventories		41,120			24,616				15,410				32,997
Deferred Income Taxes		8,333			15,674				9,901				9,386
Derivative Contracts		58,415			1,736				30,373				81,982
Other		12,859			9,412				8,886				8,405

Total Current Assets		547,007			230,312				219,519				315,682
Properties and Equipment, Net (Successful Efforts Method)		1,390,182			1,238,055				1,568,108				1,480,201
Deferred Income Taxes		25,190			19,587				33,871				30,912
Derivative Contracts		9,725			164
Other Assets		7,856			7,252				21,859				7,696

	$	1,979,960		$	1,495,370			$	1,843,357			$	1,834,491

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	137,333		$	140,006			$	137,798			$	147,680
Current Portion of Long-Term Debt		20,000			20,000				20,000				20,000
Deferred Income Taxes		22,968			941				12,012				31,962
Derivative Contracts		16			22,478
Income Taxes Payable		89,887			41				9,499				9,282
Accrued Liabilities		35,339			35,118				37,801				42,103

Total Current Liabilities		305,543			218,584				217,110				251,027
Long-Term Debt		380,000			320,000
Long-Term Liability for Pension Benefits (Note 10)									8,198				7,219
Long-Term Liability for Postretirement Benefits (Note 10)									19,132				18,204
Long-Term Debt (Note 4)									210,000				220,000
Deferred Income Taxes		330,855			289,381				367,387				347,430
Other Liabilities		53,778			67,194				55,637				45,413
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized — 120,000,000 and 80,000,000 Shares of $.10 Par Value in 2006 and 2005, respectively
Issued — 50,510,809 Shares and 50,081,983 Shares in 2006 and 2005, respectively		5,051			5,008
Authorized — 120,000,000 Shares of $0.10 Par Value in 2007 and 2006, respectively Issued and Outstanding — 102,053,232 Shares and 101,418,220 Shares in 2007 and 2006, respectively									10,205				10,142
Additional Paid-in Capital		414,201			397,349				424,490				417,995
Retained Earnings		535,383			252,167				612,205				565,591
Accumulated Other Comprehensive Income / (Loss)		40,839			(15,115	)
Less Treasury Stock, at Cost:
2,602,350 and 1,513,850 Shares in 2006 and 2005, respectively		(85,690	)		(39,198	)
Accumulated Other Comprehensive Income (Note 8)									4,683				37,160
Less Treasury Stock, at Cost: 5,204,700 Shares in both 2007 and 2006									(85,690	)			(85,690	)

Total Stockholders’ Equity		909,784			600,211				965,893				945,198

	$	1,979,960		$	1,495,370			$	1,843,357			$	1,834,491


	Nine Months Ended September 30,						Three Months Ended March 31,
*(In thousands)*	2006			2005			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	289,049		$	89,940		$	48,547		$	53,165
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Cumulative Effect of Accounting Change		403			—
Depreciation, Depletion and Amortization		96,815			79,346			33,395			31,935
Impairment of Unproved Properties		11,289			11,146			3,986			3,580
Deferred Income Tax Expense		31,514			18,225			15,874			12,893
Gain on Sale of Assets		(229,944	)		(74	)		(7,920	)		(207	)
Exploration Expense		39,972			47,396			5,652			11,614
Unrealized Loss on Derivatives		—			2,051
Stock-Based Compensation Expense and Other		11,859			7,154			7,170			4,870
Changes in Assets and Liabilities:
Accounts Receivable		64,090			(6,086	)
Accounts Receivable, Net								19,039			42,130
Income Taxes Receivable								17,902			11,850
Inventories		(16,504	)		(11,424	)		17,587			10,830
Other Current Assets		(3,447	)		1,167			(481	)		913
Other Assets		(438	)		(203	)		(13,300	)		(79	)
Accounts Payable and Accrued Liabilities		(34,137	)		1,516			(28,548	)		(34,124	)
Income Taxes Payable		95,278			3,292			10,963			6,461
Other Liabilities		6,007			3,665			10,127			2,130
Stock-Based Compensation Tax Benefit		(5,756	)		—			(4,135	)		(2,952	)

Net Cash Provided by Operating Activities		356,050			247,111			135,858			155,009

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(344,620	)		(241,504	)		(113,748	)		(103,116	)
Proceeds from Sale of Assets		322,987			996			5,784			541
Exploration Expense		(39,972	)		(47,396	)		(5,652	)		(11,614	)

Net Cash Used in Investing Activities		(61,605	)		(287,904	)		(113,616	)		(114,189	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		195,000			85,000			—			55,000
Decrease in Debt		(135,000	)		(75,000	)		(10,000	)		(100,000	)
Increase in Book Overdrafts		—			25,691
Sale of Common Stock Proceeds		3,620			4,088			1,144			1,062
Stock-Based Compensation Tax Benefit		5,756			—			4,135			2,952
Purchase of Treasury Stock		(46,492	)		(571	)
Dividends Paid		(5,832	)		(5,254	)		(1,933	)		(1,946	)

Net Cash Provided by Financing Activities		17,052			33,954
Net Cash Used in Financing Activities								(6,654	)		(42,932	)


Net Increase / (Decrease) in Cash and Cash Equivalents		311,497			(6,839	)		15,588			(2,112	)
Cash and Cash Equivalents, Beginning of Period		10,626			10,026			41,854			10,626

Cash and Cash Equivalents, End of Period	$	322,123		$	3,187		$	57,442		$	8,514


							March 31,			December 31,
*(In thousands)*	September 30, 2006			December 31, 2005			2007			2006
Unproved Oil and Gas Properties	$	107,619		$	107,787		$	117,546		$	114,108
Proved Oil and Gas Properties		1,996,857			1,970,407			2,221,989			2,109,045
Gathering and Pipeline Systems		192,841			178,876			209,121			205,473
Land, Building and Improvements		4,897			4,892			4,997			4,976
Other		32,991			33,077			34,499			34,067

		2,335,205			2,295,039			2,588,152			2,467,669
Accumulated Depreciation, Depletion and Amortization		(945,023	)		(1,056,984	)		(1,020,044	)		(987,468	)

	$	1,390,182		$	1,238,055		$	1,568,108		$	1,480,201


*(in millions)*
Cash Proceeds	$	321.4
Less:
Remaining purchase price adjustments		12.8
Carrying value of properties sold		102.2
Asset retirement obligation of properties sold		(23.8	)
Transaction costs		0.5

Pre-tax gain	$	229.7


*(In thousands)*
2007	$	9,516
2008		7,744
2009		6,553
2010		3,629
2011		3,381
Thereafter		52,123

	$	82,946


	Three Months Ended March 31,
(In thousands)	2007						2006
Accumulated Other Comprehensive Income / (Loss) - Beginning of Period				$	37,160					$	(15,115	)
Net Income	$	48,547						53,165
Other Comprehensive (Loss) / Income
Reclassification Adjustment for Settled Contracts, net of taxes of $6,719 and $546, respectively		(11,056	)					(891	)
Changes in Fair Value of Hedge Positions, net of taxes of $12,904 and $(12,125), respectively		(21,886	)					19,785
Foreign Currency Translation Adjustment, net of taxes of $(282) and $135, respectively		465						(220	)

Total Other Comprehensive (Loss) / Income		(32,477	)		(32,477	)		18,674			18,674

Comprehensive Income	$	16,070					$	71,839

Accumulated Other Comprehensive Income - End of Period				$	4,683					$	3,559


*(in thousands)*	Net Gains / (Losses) on Cash Flow Hedges			Minimum Pension Liability			Foreign Currency Translation Adjustment		Total
Balance at December 31, 2005	$	(12,860	)	$	(3,170	)	$	915	$	(15,115	)
Net change in unrealized gains on cash flow hedges, net of taxes of $33,769		55,097			—			—		55,097
Change in foreign currency translation adjustment, net of taxes of $525		—			—			857		857

Balance at September 30, 2006	$	42,237		$	(3,170	)	$	1,772	$	40,839


*(In thousands)*	*(In thousands)*
Carrying amount of asset retirement obligations at December 31, 2005		$	42,991
Carrying amount of asset retirement obligations at December 31, 2006					$	22,655
Liabilities added during the current period			1,727			342
Liabilities settled and divested during the current period			(23,875	)		(452	)
Current period accretion expense			1,109			249

Carrying amount of asset retirement obligations at September 30, 2006		$	21,952
Carrying amount of asset retirement obligations at March 31, 2007					$	22,794


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						Three Months Ended March 31,
*(In thousands)*	2006			2005			2006			2005			2007			2006
Qualified and Non-Qualified Pension Plans
Current Period Service Cost	$	680		$	558		$	2,040		$	1,674		$	733		$	680
Interest Cost		583			495			1,749			1,485			692			583
Expected Return on Plan Assets		(521	)		(355	)		(1,473	)		(1,065	)		(754	)		(476	)
Amortization of Prior Service Cost		44			44			132			132			36			44
Amortization of Net Loss		303			225			909			675			272			303

Net Periodic Benefit Cost	$	1,089		$	967		$	3,357		$	2,901
Net Periodic Pension Cost													$	979		$	1,134

Postretirement Benefits Other than Pension Plans
Current Period Service Cost	$	197		$	169		$	591		$	507		$	224		$	197
Interest Cost		219			151			658			453			266			219
Plan Termination (Gain) / Loss		(21	)		80			(64	)		240
Recognized Net Actuarial Loss / (Gain)		8			(20	)		24			(60	)
Plan Termination Gain														—			(21	)
Amortization of Net Loss														42			8
Amortization of Prior Service Cost		238			227			714			681			238			238
Amortization of Net Obligation at Transition		158			162			474			486			158			158

Total Postretirement Benefit Cost	$	799		$	769		$	2,397		$	2,307		$	928		$	799


	Three Months Ended			Nine Months Ended
*(In thousands, except per share amounts)*	September 30, 2005			September 30, 2005
Net Income, as reported	$	33,756		$	89,940
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported		2,629			4,217
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income		(2,799	)		(4,866	)

Pro forma net income	$	33,586		$	89,291

Earnings per Share:
Basic - as reported	$	0.69		$	1.84
Basic - pro forma	$	0.69		$	1.83
Diluted - as reported	$	0.68		$	1.81
Diluted - pro forma	$	0.68		$	1.80

Share Count		48,951			48,865
Diluted Share Count		49,665			49,613


Restricted Stock Awards	Shares		Weighted- Average Grant Date Fair Value per share		Weighted- Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands) ⁽¹⁾
Non-vested shares outstanding at December 31, 2005	588,465		$	26.68
Granted	46,850			47.60
Vested	(230,743	)		21.71
Forfeited	(3,800	)		31.31

Non-vested shares outstanding at September 30, 2006	400,772		$	31.92	1.7	$	19,209


Restricted Stock Units	Shares		Weighted- Average Grant Date Fair Value per share		Aggregate Intrinsic Value (in thousands) ⁽¹⁾
Outstanding at December 31, 2005	30,100		$	31.30
Granted and fully vested	17,220			50.82
Issued	(8,600	)		31.30
Forfeited	—			—

Outstanding at September 30, 2006	38,720		$	39.98	$	1,856


	Three and Nine Months Ended September 30, 2006
Weighted Average Value per Option Granted During the Period⁽¹⁾	$	14.65

Assumptions
Stock Price Volatility		31.5	%
Risk Free Rate of Return		4.6	%
Expected Dividend		0.3	%
Expected Term (in years)		4.0


							March 31,			December 31,
*(In thousands)*	September 30, 2006			December 31, 2005			2007			2006
Accounts Receivable
ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	93,423		$	147,016		$	90,364		$	102,023
Joint Interest Accounts		15,731			14,319			11,966			18,574
Current Income Tax Receivable		—			12,239
Other Accounts		376			315			203			501

		109,530			173,889			102,533			121,098
Allowance for Doubtful Accounts		(5,373	)		(5,641	)		(5,026	)		(4,552	)

	$	104,157		$	168,248		$	97,507		$	116,546

Inventories
INVENTORIES
Natural Gas and Oil in Storage	$	32,204		$	18,279		$	5,565		$	22,717
Tubular Goods and Well Equipment		7,736			7,161			8,151			7,680
Pipeline Imbalances		1,180			(824	)		1,694			2,600

	$	41,120		$	24,616		$	15,410		$	32,997

Other Current Assets
OTHER CURRENT ASSETS
Drilling Advances	$	3,268		$	2,169		$	376		$	651
Prepaid Balances		9,253			6,939			8,172			7,416
Other Accounts		338			304			338			338

	$	12,859		$	9,412		$	8,886		$	8,405

Accounts Payable
ACCOUNTS PAYABLE
Trade Accounts	$	17,585		$	18,227		$	8,201		$	28,569
Natural Gas Purchases		9,433			12,208			6,221			8,356
Royalty and Other Owners		44,874			49,312			36,363			37,230
Capital Costs		52,599			37,489			68,564			59,524
Taxes Other Than Income		4,868			10,329			6,039			4,805
Drilling Advances		2,000			5,760			3,565			1,506
Wellhead Gas Imbalances		2,251			2,175			2,823			2,288


Stock Options	Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands) ⁽¹⁾
Outstanding at December 31, 2005	913,348		$	15.32
Granted	30,000			47.60
Exercised	(237,273	)		15.19
Forfeited or Expired	(900	)		18.20

Outstanding at September 30, 2006	705,175		$	16.74	1.3	$	21,996

Options Exercisable at September 30, 2006	675,175		$	15.37	1.1	$	21,986


Number of Options		159,400
Weighted Average Exercise Price	$	12.84
Weighted Average Contractual Term (in years)		0.4


Number of Options		515,775
Weighted Average Exercise Price	$	16.15
Weighted Average Contractual Term (in years)		1.4


	Three and Nine Months Ended September 30, 2006			Three Months Ended March 31, 2007
Weighted Average Value per Stock Appreciation Right Granted During the Period⁽¹⁾	$	14.19

Weighted Average Value per Stock Appreciation Right
Granted During the Period⁽¹⁾				$	11.26
Assumptions
Stock Price Volatility		31.6	%		32.6	%
Risk Free Rate of Return		4.6	%		4.6	%
Expected Dividend		0.3	%		0.2	%
Expected Term (in years)		3.75			4.0


	As of ~~September 30,~~March 31, ~~2006~~2007
Risk Free Rate of Return	~~4.7% - 4.9%~~ 4.6	%
Stock Price Volatility	~~32.8%~~32.9	%
Correlation in ~~stock price movement~~Stock Price Movement	~~90%~~90	%
Expected Dividend	0.2	%


Performance Share Awards	Shares		Weighted- Average Grant Date Fair Value per share⁽¹⁾		Weighted- Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands) ⁽²⁾
Non-vested shares outstanding at December 31, 2005	330,850		$	24.30
Granted	142,750			43.35
Vested	—			—
Forfeited	(2,750	)		29.08

Non-vested shares outstanding at September 30, 2006	470,850		$	30.05	1.2	$	22,568


	Three Months Ended March 31,
(In millions)	2007		2006
Capital Expenditures
Drilling and Facilities	$	115.0	$	89.2
Leasehold Acquisitions		4.4		14.7
Pipeline and Gathering		3.7		3.1
Other		0.4		0.7

		123.5		107.7
Proved Property Acquisitions		—		0.2
Exploration Expense		5.7		11.6

Total	$	129.2	$	119.5


	Three Months Ended September 30,					Variance					Three Months Ended March 31,					Variance
	2006			2005		Amount			Percent		2007			2006		Amount			Percent
Natural Gas Production (Mmcf)
East												5,757			5,765		(8	)	0	%
Gulf Coast		8,029			6,333		1,696		27	%		6,479			7,248		(769	)	(11	%)
West		6,124			5,961		163		3	%		6,458			5,390		1,068		20	%
East		5,930			5,453		477		9	%
Canada		652			264		388		147	%		1,072			477		595		125	%

Total Company		20,735			18,011		2,724		15	%		19,766			18,880		886		5	%

Natural Gas Production Sales Price ($/Mcf)
East											$	8.08		$	9.31	$	(1.23	)	(13	%)
Gulf Coast	$	7.13		$	6.67	$	0.46		7	%	$	7.75		$	8.21	$	(0.46	)	(6	%)
West	$	5.84		$	5.91	$	(0.07	)	(1	)%	$	6.51		$	7.08	$	(0.57	)	(8	%)
East	$	7.41		$	7.75	$	(0.34	)	(4	)%
Canada	$	5.09		$	8.04	$	(2.95	)	(37	)%	$	7.46		$	8.12	$	(0.66	)	(8	%)
Total Company	$	6.76		$	6.77	$	(0.01	)	—		$	7.42		$	8.22	$	(0.80	)	(10	%)
Natural Gas Production Revenue (in thousands)
Natural Gas Production Revenue(In thousands)
East											$	46,498		$	53,666	$	(7,168	)	(13	%)
Gulf Coast	$	57,216		$	42,253	$	14,963		35	%		50,240			59,475		(9,235	)	(16	%)
West		35,770			35,229		541		2	%		42,020			38,157		3,863		10	%
East		43,958			42,280		1,678		4	%
Canada		3,317			2,123		1,194		56	%		7,992			3,869		4,123		107	%

Total Company	$	140,261		$	121,885	$	18,376		15	%	$	146,750		$	155,167	$	(8,417	)	(5	%)

Price Variance Impact on Natural Gas Production Revenue
(in thousands)
(In thousands)
East											$	(7,097	)
Gulf Coast	$	3,723										(2,957	)
West		(415	)									(3,699	)
East		(2,021	)
Canada		(1,925	)									(706	)

Total Company	$	(638	)								$	(14,459	)

Volume Variance Impact on Natural Gas Production Revenue
(in thousands)
(In thousands)
East											$	(71	)
Gulf Coast	$	11,240										(6,278	)
West		956										7,562
East		3,699
Canada		3,119										4,829

Total Company	$	19,014									$	6,042


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 2006	—	$	—	—	819,950
August 2006	—	$	—	—	819,950
September 2006	422,300	$	45.71	422,300	397,650

Total	422,300	$	45.71