UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
For the quarterly period ended September 30, 2005
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
1200 Enclave Parkway, Houston, Texas 77077
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant’s telephone number)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of October 24, 2005, there were 48,969,832 shares of Common Stock, Par Value $.10 Per Share, outstanding.
INDEX TO FINANCIAL STATEMENTS
Condensed Consolidated Statement of Operations for the Three Months and Nine Months Ended September 30, 2005 and 2004
Condensed Consolidated Balance Sheet at September 30, 2005 and December 31, 2004
Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2005 and 2004
Notes to the Condensed Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm on Review of Interim Financial Information
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PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
OPERATING REVENUES
Natural Gas Production
Brokered Natural Gas
Crude Oil and Condensate
Other
OPERATING EXPENSES
Brokered Natural Gas Cost
Direct Operations - Field and Pipeline
Exploration
Depreciation, Depletion and Amortization
Impairment of Unproved Properties
Impairment of Oil & Gas Properties (Note 2)
General and Administrative
Taxes Other Than Income
Gain on Sale of Assets
INCOME FROM OPERATIONS
Interest Expense and Other
Income Before Income Taxes
Income Tax Expense
NET INCOME
Basic Earnings per Share
Diluted Earnings per Share
Average Common Shares Outstanding
Diluted Common Shares (Note 6)
The accompanying notes are an integral part of these condensed consolidated financial statements.
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CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In thousands, except share amounts)
ASSETS
Current Assets
Cash and Cash Equivalents
Accounts Receivable
Inventories
Deferred Income Taxes
Total Current Assets
Properties and Equipment, Net (Successful Efforts Method)
Other Assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable
Current Portion of Long-Term Debt
Derivative Contracts
Accrued Liabilities
Total Current Liabilities
Long-Term Debt
Other Liabilities
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common Stock:
Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 50,050,174 Shares and 49,680,915 Shares in 2005 and 2004, respectively
Additional Paid-in Capital
Retained Earnings
Accumulated Other Comprehensive Loss
Less Treasury Stock, at Cost:
1,081,250 and 1,061,550 Shares in 2005 and 2004
Total Stockholders’ Equity
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CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depletion, Depreciation and Amortization
Impairment of Oil & Gas Properties
Deferred Income Tax Expense
Exploration Expense
Change in Derivative Fair Value
Performance Share Compensation
Changes in Assets and Liabilities:
Other Current Assets
Accounts Payable and Accrued Liabilities
Net Cash Provided by Operating Activities
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures
Proceeds from Sale of Assets
Net Cash Used by Investing Activities
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt
Decrease in Debt
Increase in Book Overdrafts
Sale of Common Stock Proceeds
Purchase of Treasury Stock
Dividends Paid
Net Cash Provided / (Used) by Financing Activities
Net (Decrease) / Increase in Cash and Cash Equivalents
Cash and Cash Equivalents, Beginning of Period
Cash and Cash Equivalents, End of Period
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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. FINANCIAL STATEMENT PRESENTATION
During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies used in its Annual Report to Stockholders and its Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission. People using financial information produced for interim periods are encouraged to refer to the footnotes in the Annual Report on Form 10-K for the year ended December 31, 2004 when reviewing interim financial results. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.
Our independent registered public accounting firm has performed a review of these condensed consolidated interim financial statements in accordance with standards established by the Public Company Accounting Oversight Board (United States). Pursuant to Rule 436(c) under the Securities Act of 1933, this report should not be considered a part of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meanings of Sections 7 and 11 of the Act.
On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the Common Stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.
Recently Issued Accounting Pronouncements
In March 2005, the Financial Accounting Standard Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company does not believe that its financial position, results of operations or cash flows will be impacted by this Interpretation since the Company currently records all asset retirement obligations.
In May 2005, the FASB issued Statement SFAS No. 154, “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting
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for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS 123(R) are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, the Company will not adopt this SFAS until the first quarter of 2006. The Company plans to use the modified prospective application method as detailed in SFAS 123(R). The Company is currently evaluating the impact on the Company’s operating results. Future cash flows of the Company will not be impacted by the adoption of this standard. See “Stock-Based Compensation” below for further information.
In September 2005, the FASB also issued Proposed FASB Staff Position (FSP) FAS 123(R)-c which provides a simplified, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS 123(R). Under this Proposed FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS 123(R) adoption date will not be affected by this Proposed FSP and will be calculated in accordance with SFAS 123(R) which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the Proposed FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS 123(R) for the calculation of the APIC pool. If finalized, the Company will adopt this Proposed FSP in conjunction with the adoption of SFAS 123(R).
In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, the Company is allowed to use the date the award is approved in accordance with its corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. The Company will adopt this FSP in conjunction with the adoption of SFAS 123(R).
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Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Under the intrinsic value based method, compensation cost is the excess, if any, of the quoted market price of the stock at the grant date over the amount an employee must pay to acquire the stock.
SFAS 123, “Accounting for Stock-Based Compensation,” as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments.
The following table illustrates the effect on Net Income and Earnings per Share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation. The Earnings per Share amounts for prior periods have been retroactively adjusted to reflect the 3-for-2 split of the Company’s Common Stock effective March 31, 2005.
Net Income, as reported
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
Pro forma Net Income
Earnings per Share:
Basic - as reported
Basic - pro forma
Diluted - as reported
Diluted - pro forma
The assumptions used in the fair value method calculation as well as additional stock-based compensation information are disclosed in the following table.
Compensation Expense in Net Income, as reported (1)
Weighted Average Value per Option Granted During the Period (2) (3)
Assumptions (3)
Stock Price Volatility
Risk Free Rate of Return
Dividend Rate (per year)
Expected Term (in years)
On October 26, 2005, the Compensation Committee of the Board of Directors of the Company approved the acceleration, to December 15, 2005, of the vesting of 200,299 unvested stock options awarded in February 2003 under the Company’s Second Amended and Restated Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under the Company’s 2004 Incentive Plan.
The 200,299 shares awarded to employees at an exercise price of $15.32, would have vested in February 2006. The 24,500 shares, awarded to the non-employee directors at an exercise price of $23.32, would have vested 12,250 in April 2006 and April 2007, respectively. Of the 200,299 shares, 91,500 were awarded to the named executive officers.
The decision to accelerate the vesting of these unvested options, which the Company believes to be in the best interest of its shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with the Company’s adoption of Financial Accounting Standards Board Statement No. 123(R), “Share Based Payment (revised 2004).” The accelerated vesting of the options will not have a material impact on the Company’s results of operations or cash flows. The Company currently accounts for stock-based compensation using the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” under which the Company has not recognized any compensation expense for its stock option grants. SFAS 123(R) will require the Company to recognize compensation expense equal to the fair value of all equity-based compensation over the vesting period of each such award beginning on January 1, 2006. The acceleration of vesting will reduce the Company’s compensation expense related to these options by an estimated $0.2 million for the year 2006.
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2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
Unproved Oil and Gas Properties
Proved Oil and Gas Properties
Gathering and Pipeline Systems
Land, Building and Improvements
Accumulated Depreciation, Depletion and Amortization
As of September 30, 2005, we did not have any significant changes from year-end in our amount of capitalized well costs that have been capitalized for greater than one year after drilling was suspended.
During the third quarter of 2004, the Company recorded an impairment of approximately $3.5 million on a two-well field in south Louisiana resulting from production performance issues related to water encroachment. This impairment charge was recorded due to the capitalized cost of the fields exceeding the future undiscounted cash flows. This charge was reflected in the quarterly results and was measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related field. There were no impairments of proved oil and gas properties during the nine months ended September 30, 2005.
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 quarter, the Company closed on two large producing property acquisitions for interests in fields in the Gulf Coast. For the McCampbell field acquisition, we spent $41.2 million. The Vernon field acquisition was $18.0 million.
3. INVENTORIES
Inventories are comprised of the following:
Natural Gas and Oil in Storage
Tubular Goods and Well Equipment
Pipeline Imbalances
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4. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
Trade Accounts
Joint Interest Accounts
Current Income Tax Receivable
Other Accounts
Allowance for Doubtful Accounts
Drilling Advances
Prepaid Balances
Natural Gas Purchases
Royalty and Other Owners
Capital Costs
Wellhead Gas Imbalances
Book Overdrafts
Employee Benefits
Interest Payable
Postretirement Benefits Other Than Pension
Accrued Pension Cost
Rabbi Trust Deferred Compensation Plan
Accrued Plugging and Abandonment Liability
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5. LONG-TERM DEBT
At September 30, 2005, the Company had $10 million of debt outstanding under its Revolving Credit Agreement (Credit Facility), which provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. To expand the credit line, the Company must seek prior approval from the administrative agent and the bank whose commitment is increasing. The term of the Credit Facility expires in December 2009. The Credit Facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.
In addition to the $10 million of debt outstanding on the Credit Facility, the Company has the following debt outstanding at September 30, 2005:
6. EARNINGS PER SHARE
Basic Earnings per Share (EPS) is computed by dividing Net Income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated using the treasury stock method except that the denominator is increased to reflect the potential dilution that could occur if outstanding stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.
The following is a calculation of basic and diluted weighted average shares outstanding for the three months and nine months ended September 30, 2005 and 2004.
Shares - basic
Dilution effect of stock options and awards at end of period
Shares - diluted
Stock awards and shares excluded from diluted earnings per share due to theanti-dilutive effect
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7. COMMITMENTS AND CONTINGENCIES
Contingencies
The Company is a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
Wyoming Royalty Litigation
In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court, as reported in previous filings. The plaintiffs made claims pertaining to deductions from their overriding royalty and claims concerning penalties for improper reporting. As a result of several decisions by the Court favorable to the Company, the case was settled in September 2005 with no payment from the Company and a dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. Management has reversed the reserve it had recorded regarding this case.
West Virginia Royalty Litigation
In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification and allege that the Company failed to pay royalty based upon the wholesale market value of the gas, that it had taken improper deductions from the royalty and failed to properly inform royalty owners of the deductions. The plaintiffs 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, if entered by the court, would result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings. Trial has been set for April 17, 2006. The Company intends to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.
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.
Texas Title Litigation
On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs 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 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, conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that
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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. The Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title is approximately $15.2 million, and that the carrying value of this property is approximately $33.7 million.
Although the investigation into this claim continues, the Company intends to vigorously defend the case. Should the Company receive an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.
Raymondville Area
In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody 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 have filed a counter claim against the Company, and one of the defendants has 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 has filed a Motion for Reconsideration and Opposition to Proposed Order. The court is scheduled to consider these two motions in December 2005.
Commitment and Contingency Reserves
The Company has established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur approximately $14.9 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.
While the outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position or cash flow of the Company. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
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8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. At September 30, 2005, the Company had 20 cash flow hedges open: 11 natural gas price collar arrangements, 2 crude oil price collars and 7 natural gas price swap arrangements. Additionally, the Company had 2 crude oil financial instruments open at September 30, 2005, that did not qualify for hedge accounting. At September 30, 2005, a $114.8 million ($70.8 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $114.6 million short term derivative liability and an $8.9 million long term derivative liability, which is included in other long term liabilities 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.
Assuming no change in commodity prices, after September 30, 2005 the Company would reclassify to the Statement of Operations, over the next 12 months, $65.4 million in after-tax expenditures associated with commodity hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at September 30, 2005 related to remaining anticipated 2005 production and a portion of anticipated 2006 production.
From time to time, the Company enters into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At September 30, 2005, the fair value of the Company’s two open crude oil swap arrangements was $7.3 million, and is reported as a component of Derivative Contracts in the liability section of the accompanying Condensed Consolidated Balance Sheet. The total loss related to these arrangements was $2.9 million and $12.2 million for the three months and nine months ended September 30, 2005, respectively, and has been reported as a component of Operating Revenues in the accompanying Condensed Consolidated Statement of Operations.
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9. COMPREHENSIVE INCOME
Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the nine month periods ended September 30, 2005 and 2004.
Nine Months Ended
September 30,
Accumulated Other Comprehensive Loss - Beginning of Period
Other Comprehensive Loss Reclassification Adjustment for Settled Contracts
Changes in Fair Value of Hedge Positions
Minimum Pension Liability
Foreign Currency Translation Adjustment
Deferred Income Tax
Total Other Comprehensive Loss
Comprehensive Income
Accumulated Other Comprehensive Loss - End of Period
Comprehensive income (loss) for the three months ended September 30, 2005 and 2004 was ($16.5) million and $13.1 million, respectively.
Deferred income tax of $31.5 million for the nine months ended September 30, 2005 represents the net deferred tax liability of ($15.8) million on the Reclassification Adjustment for Settled Contracts, $48.7 million on the Changes in Fair Value of Hedge Positions, ($0.8) million on the Minimum Pension Liability Adjustment and ($0.6) million on the Foreign Currency Translation Adjustment.
Deferred income tax of $14.0 million for the nine months ended September 30, 2004 represents the net deferred tax liability of ($11.5) million on the Reclassification Adjustment for Settled Contracts, $25.6 million on the Changes in Fair Value of Hedge Positions, and less than ($0.1) million on the Foreign Currency Translation Adjustment.
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10. ASSET RETIREMENT OBLIGATIONS
The following table reflects the changes of the asset retirement obligations during the nine months ended September 30, 2005.
Carrying amount of asset retirement obligations at December 31, 2004
Liabilities added during the current period
Liabilities settled during the current period
Current period accretion expense
Revisions to estimated cash flows
Carrying amount of asset retirement obligations at September 30, 2005
Accretion expense was $1.1 million and $1.4 million for the nine months ended September 30, 2005 and 2004, respectively, and is included within Depletion, Depreciation and Amortization expense on the Company’s Condensed Consolidated Statement of Operations.
11. PENSION AND OTHER POSTRETIREMENT BENEFITS
The components of net periodic benefit costs for the three months and nine months ended September 30, 2005 and 2004 are as follows:
Qualified and Non-Qualified Pension Plans
Current Period Service Cost
Interest Accrued on Pension Obligation
Expected Return on Plan Assets
Net Amortization and Deferral
Recognized Loss
Net Periodic Benefit Costs
Postretirement Benefits Other than Pension Plans
Service Cost of Benefits Earned During the Period
Interest Cost on the Accumulated Postretirement Benefit Obligation
Plan Termination Loss
Amortization Benefit of the Unrecognized Gain
Amortization of Prior Service Cost
Amortization Benefit of the Unrecognized Transition Obligation
Total Postretirement Benefit Cost
The Company does not have any required minimum funding obligations for its qualified pension plan in 2005. The Company, however, has made a $2.0 million discretionary contribution in the first nine months of 2005. Management has not determined if any additional discretionary funding will be made in the fourth quarter.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Cabot Oil & Gas Corporation:
We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the Company) as of September 30, 2005, and the related condensed consolidated statement of operations for each of the three and nine month periods ended September 30, 2005 and 2004 and the condensed consolidated statement of cash flows for the nine month periods ended September 30, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated balance sheet as of December 31, 2004 and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for the year then ended, management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004; and in our report dated March 2, 2005, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, we expressed unqualified opinions thereon. The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting referred to above are not presented herein. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2004, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
October 28, 2005
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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, 2005 and 2004 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Form 10-K for the year ended December 31, 2004.
Overview
Natural gas revenues increased by $61.0 million for the nine months ended September 30, 2005 as compared to the nine months ended September 30, 2004. The increase is due to increased realized natural gas prices as well as increased production. Oil revenues increased by $22.4 million for the first nine months of 2005 as compared to the first nine months of 2004. This increase is primarily due to an increase in oil prices of 40% in the first nine months of 2005 as compared to the first nine months of 2004. Additionally, the unrealized loss on crude oil derivatives decreased by $11.4 million in the first nine months of 2005 from the comparable prior year period. Somewhat offsetting the crude oil price increase and the decrease in the unrealized loss was the decrease in crude oil production in the first nine months of 2005.
In the first nine months of 2005, natural gas prices were higher than the comparable period of the prior year and our financial results reflect their impact. Our realized natural gas price was $6.16 per Mcf, 21% higher than the $5.10 per Mcf price realized in the same period of the prior year. These realized prices are impacted by realized losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” 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, NGLs and crude oil prices, and therefore, cannot accurately predict revenues.
For the nine months ended September 30, 2005, we produced 62.9 Bcfe compared to production of 63.5 Bcfe for the comparable period of the prior year, reflecting the deferral of approximately 1.0 Bcfe of expected production from the two hurricanes that impacted the Gulf Coast in the third quarter of 2005. Natural gas production was 54.8 Bcf and oil production was 1,346 Mbbls. Natural gas production increased slightly when compared to the comparable period of the prior year, which had production of 54.2 Bcf. We increased production in all regions except our Gulf Coast region. Our East region increased production with the success of the increased drilling program in 2004 and 2005. In the West region, we have had a successful drilling and recompletion program this year. In addition, production in Canada increased as a result of having a full nine months of production in the current year. These increases are partially offset by reduced production in our Gulf Coast region as a result of the hurricanes experienced in Louisiana during the third quarter of 2005 as well as the natural decline of gas production in south Louisiana. Oil production decreased by 186 Mbbls from 1,532 Mbbls in the first nine months of 2004 to 1,346 Mbbls produced in the first nine months of 2005. The decrease in oil production is primarily the result of the continued natural decline of the CL&F lease in south Louisiana and decreased production from properties, which are currently producing below capacity, after the impact of the hurricanes that occurred during the third quarter in Louisiana, including non-operated offshore properties that are currently shut-in.
We had net income of $89.9 million, or $1.84 per share, for the nine months ended September 30, 2005 compared to net income of $56.2 million, or $1.15 per share, for the comparable period of the prior year. The increase in net income is primarily due to increased natural gas and oil production revenues, as discussed above. This increase is partially offset by an increase in total operating expenses of $30.0 million and an increase in income tax expense of $19.1 million in the first nine months of 2005 as compared to the first nine months of 2004.
In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. In 2005, we expect to spend approximately $400 million in capital and exploration expenditures, which includes a layer of investment for new projects that may arise during the remainder of 2005. This figure has increased by $70 million from $330 million previously reported in order to reflect increased drilling as well as new projects. During the third quarter of 2005,
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we closed on two large producing property acquisitions for interests in fields in the Gulf Coast. For the McCampbell field acquisition, we spent $41.2 million. The Vernon field acquisition was $18.0 million. For the nine months ended September 30, 2005, $299.7 million of capital and exploration expenditures have been invested in our exploration and development efforts.
During the nine months ended September 30, 2005, we drilled 229 gross wells (207 development, 18 exploratory and 4 extension wells) with a success rate of 95% compared to 205 gross wells (190 development and 15 exploratory wells) with a success rate of 97% for the comparable period of the prior year. For the full year, we plan to drill approximately 330 gross wells compared to 256 gross wells in 2004.
We remain focused on our strategies of balancing our capital investments between acceptable risk and strongest economics, along with balancing longer life investments with impact exploration opportunities. In the current year we have allocated our planned 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 February 28, 2005, we announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock in the form of a stock distribution, distributed on March 31, 2005 to stockholders of record on March 18, 2005. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of our Common Stock.
The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See “Forward-Looking Information” on page 33.
Financial Condition
Capital Resources and Liquidity
Our primary source of cash for the nine months ended September 30, 2005 was from funds generated from operations, as well as borrowings on our revolving credit facility and proceeds from the exercise of stock options under our stock plans. We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been subject to 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 the Annual Report on Form 10-K, have influenced prices throughout the recent years. During the third quarter, approximately 1.0 Bcfe of expected production in our Gulf Coast region was deferred due to the impacts of Hurricanes Katrina and Rita. These events in Louisiana did not have a material adverse impact on our capital resources or liquidity. Working capital is substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures, pay dividends and purchase treasury stock. During the nine months ended September 30, 2005 we purchased 19,700 shares of Cabot stock at a weighted average purchase price of $28.99. See below for additional discussion and analysis of cash flow.
Cash Flows Provided by Operating Activities
Cash Flows Used by Investing Activities
Cash Flows Provided by Financing Activities
Operating Activities. Net cash provided by operating activities in the first nine months of 2005 increased $31.2 million over the comparable period in 2004. This increase is primarily due to higher commodity prices. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 21% over the 2004 period, while crude oil realized prices
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increased 40% over the same period. Production volumes decreased slightly with a 1% decline in equivalent production in the first nine months of 2005 compared to the comparable period in 2004. We are unable to predict future commodity prices, and as a result cannot provide any assurance about future levels of net cash provided by operating activities.
Investing Activities. The key components of cash used by investing activities are capital spending and exploration expense. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices our budget may be periodically adjusted during any given year. Cash flows used in investing activities increased by $97.7 million for the nine months ended September 30, 2005, compared to the same period in 2004. The increase from 2004 to 2005 is primarily due to proved property acquisitions in the third quarter and, to a lesser extent, an increase in drilling activity as a result of higher commodity prices.
Financing Activities. Cash flows provided by financing activities were $34.0 million for the nine months ended September 30, 2005. Cash flows used by financing activities were $1.5 million for the nine months ended September 30, 2004. Cash flows provided by financing activities in the first nine months of 2005 were the result of an increase in book overdrafts, borrowings under the Credit Facility and proceeds from the exercise of stock options, partially offset by dividend payments and the purchases of treasury stock.
At September 30, 2005, we had $10 million of debt outstanding under our Credit Facility, which provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. It 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.
On August 13, 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our Common Stock in the open market or in negotiated transactions. Subsequent to this announcement, there was a 3-for-2 split of the Company’s Common Stock. As a result of this stock split, this figure has been adjusted to three million shares. During the first nine months of 2005, we repurchased 19,700 shares of our Common Stock. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The approximate number of shares that may yet be purchased under the plan is 1,918,750. See “Issuer Purchases of Equity Securities” in Item 2 “Unregistered Sales of Equity Securities and Use of Proceeds” for additional information.
Capitalization
Our capitalization information is as follows:
Debt (1)
Stockholders’ Equity (2) (3)
Total Capitalization
Debt to Capitalization (3)
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During the nine months ended September 30, 2005, we paid dividends of $5.3 million on our Common Stock. A regular dividend of $0.04 per share of Common Stock has been declared for each quarter since we became a public company in 1990. We expect to pay additional incremental dividends of approximately $2.0 million in 2005 as a result of the 3-for-2 stock split.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving Credit Facility. We budget these capital expenditures based on our projected cash flows for the year.
The following table presents major components of capital and exploration expenditures:
Drilling and Facilities
Leasehold Acquisitions
Pipeline and Gathering
Proved Property Acquisitions
Total
We plan to drill approximately 330 gross wells in 2005. This drilling program includes approximately $400 million in total capital and exploration expenditures. See the “Overview” discussion for additional information regarding the current year drilling program. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.
Critical Accounting Policies and Estimates
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. There have been no changes to our critical accounting policies from those described in the 2004 Form 10-K. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, for further discussion.
Results of Operations
Third Quarters of 2005 and 2004 Compared
We reported Net Income in the third quarter of 2005 of $33.8 million, or $0.69 per share. During the corresponding quarter of 2004, we reported Net Income of $17.8 million, or $0.37 per share. Operating Income increased $24.7 million compared to the prior year, from $34.3 million in the third quarter of 2004 to $59.0 million in the third quarter of 2005. The increase in current year Operating Income was substantially due to an increase in natural gas and oil production revenues partially offset by an increase in total Operating Expenses. Net Income increased in the current quarter by $15.9 million due to an increase in Operating Income partially offset by an increase of $9.0 million in Income Tax Expense.
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Natural Gas Production Revenues
Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $6.77 per Mcf for the three months ended September 30, 2005 compared to $5.07 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $1.26 per Mcf in 2005 and $0.59 per Mcf in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $0.4 million and the unrealized gain of $0.3 million for the three months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.
Natural Gas Production (Mmcf)
Gulf Coast
West
East
Canada
Total Company
Natural Gas Production Sales Price ($/Mcf)
Natural Gas Production Revenue (in thousands)
(in thousands)
Price Variance Impact on Natural Gas Production Revenue
Volume Variance Impact on Natural Gas Production Revenue
The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. Partially offsetting this increase was the decrease in production due to decreases in the Gulf Coast region as a result of the hurricanes in the third quarter as discussed above and natural production declines. The increase in the realized natural gas price partially offset by the decrease in production resulted in a net revenue increase of $26.1 million, excluding the unrealized impact of derivative instruments.
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Brokered Natural Gas Revenue and Cost
Sales Price ($/Mcf)
Volume Brokered (Mmcf)
Brokered Natural Gas Revenues (in thousands)
Purchase Price ($/Mcf)
Brokered Natural Gas Cost (in thousands)
Brokered Natural Gas Margin (in thousands)
Sales Price Variance Impact on Revenue
Volume Variance Impact on Revenue
Purchase Price Variance Impact on Purchases
Volume Variance Impact on Purchases
The increased brokered natural gas margin of $0.6 million was driven by higher volume combined with an increased sales price that outpaced the increase in purchase cost.
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Crude Oil and Condensate Revenues
Our average total company realized Crude Oil Sales Price, including the realized impact of derivative instruments, was $46.05 per Bbl for the third quarter of 2005 and $32.03 per Bbl for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $14.59 per Bbl in 2005 and $10.87 per Bbl in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $2.0 million and the unrealized loss of $7.4 million for the three months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.
Crude Oil Production (Mbbl)
Crude Oil Sales Price ($/Bbl)
Crude Oil Revenue (in thousands)
Price Variance Impact on Crude Oil Revenue
Volume Variance Impact on Crude Oil Revenue
The decrease in oil production is primarily the result of the decreased Gulf Coast production. This is a result of continued natural decline of the CL&F lease in south Louisiana, as well as the impact of hurricanes which includes the shutting in and deferring of production at the Breton Sound offshore lease. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $3.4 million, excluding the unrealized impact of derivative instruments.
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Impact of Derivative Instruments on Operating Revenues
The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:
Three Months Ended
Operating Revenues - Increase/(Decrease) to Revenue
Cash Flow Hedges
Crude Oil
Total Cash Flow Hedges
Other Derivative Financial Instruments
Total Cash Flow and Non-Qualifying Hedges
Other Operating Revenues
Other operating revenues decreased by $1.4 million between the third quarter of 2005 and the third quarter of 2004 primarily due to a decrease in cash received for net profits interest. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year third quarter period.
Operating Expenses
Total costs and expenses from operations increased $17.5 million in the third quarter of 2005 compared to the same quarter of 2004. The primary reasons for this fluctuation are as follows:
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Interest Expense, net
Interest expense, net decreased $0.2 million in the third quarter of 2005. This decrease is the result of increased interest income on our short term investments. Interest expense related to borrowings under the Credit Facility was higher in the current quarter due to higher average borrowings. Average borrowings based on month end balances for the third quarter of 2005 were approximately $52 million compared to approximately $31 million in the third quarter of 2004.
Income tax expense increased by $9.0 million due to a comparable increase in our pre-tax income.
Nine Months of 2005 and 2004 Compared
We reported Net Income in the first nine months of 2005 of $89.9 million, or $1.84 per share. During the corresponding period of 2004, we reported Net Income of $56.2 million, or $1.15 per share. Operating Income increased by $52.0 million in the first nine months of 2005 compared to the prior year. The increase in current year Operating Income was substantially due to an increase in natural gas and oil production revenues partially offset by an increase in total Operating Expenses. Net Income increased in the first nine months of 2005 by $33.7 million due to an increase in Operating Income partially offset by an increase of $19.1 million in Income Tax Expense.
Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $6.16 per Mcf for the nine months ended September 30, 2005 compared to $5.10 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.73 per Mcf in 2005 and $0.57 per Mcf in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $0.2 million and $0.1 million for the nine months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.
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The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. In addition, the increase in production was due to the successful drilling programs in the West and East as well as the commencement of Canada natural gas production late in 2004. Partially offsetting this was the decrease in the Gulf Coast production. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $61.2 million, excluding the unrealized impact of derivative instruments.
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The increased brokered natural gas margin of $0.8 million was driven by an increased sales price that outpaced the increase in purchase cost, offset in part by a decrease in volume.
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Our average total company realized Crude Oil Sales Price, including the realized impact of derivative instruments, was $43.92 per Bbl for the first nine months of 2005 and $31.36 per Bbl for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $8.93 per Bbl in 2005 and $7.11 per Bbl in 2004. The following table excludes the unrealized loss from the change in derivative fair value of $1.9 million and $13.2 million for the nine months ended September 30, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.
The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $11.1 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is primarily the result of the decrease in the Gulf Coast region production due to the continued natural decline of the CL&F lease in south Louisiana, as well as the impact of hurricanes which included the shutting in and deferring of production at the Breton Sound offshore lease.
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Other operating revenues decreased $1.9 million from the first nine months of 2004 to the first nine months of 2005. This change was primarily a result of an increase in our payout liability, associated with the reduction of our interest due to reversionary interest owned by others, which correspondingly decreased other operating revenues. This variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous nine month period.
Total costs and expenses from operations increased $30.0 million in the first nine months of 2005 compared to the comparable period of 2004. The primary reasons for this fluctuation are as follows:
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Interest expense, net decreased $1.1 million in the first nine months of 2005. This variance is mainly a result of increased income on our short term investments.
Income tax expense increased $19.1 million due to a comparable increase in our pre-tax income.
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In March 2005, the Financial Accounting Standard Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation, since we currently record all asset retirement obligations.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS 123(R) are now effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. We plan to use the modified prospective application method as detailed in SFAS 123(R). We are currently evaluating the impact on our operating results. Our future cash flows will not be impacted by the adoption of this standard. See “Stock-Based Compensation” below for further information.
Additionally, in September 2005, the FASB issued Proposed FASB Staff Position (FSP) FAS 123(R)-c which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS 123(R). Under this Proposed FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS 123(R) adoption date will not be affected by this Proposed FSP and will be calculated in accordance with SFAS 123(R) which requires that only the excess tax benefit or deficiency of the tax deduction over the
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tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the Proposed FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS 123(R) for the calculation of the APIC pool. If finalized, we will adopt this Proposed FSP in conjunction with the adoption of SFAS 123(R).
In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, we are allowed to use the date the award is approved in accordance with its corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. We will adopt this FSP in conjunction with the adoption of SFAS 123(R).
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
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 related to commodity price swaps and Note 8 of the Notes to the Interim Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.
Hedges on Production – Swaps
From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. Under our Revolving Credit Agreement, which had borrowings of $10 million outstanding at September 30, 2005, 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. During the first nine months of 2005, natural gas price swaps covered 15,375 Mmcf, or 28%, of our gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.
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At September 30, 2005, we had open natural gas price swap contracts covering our 2005 production as follows:
Contract Period
UnrealizedLoss
As of September 30, 2005
Natural Gas Price Swaps on Production in:
Fourth Quarter 2005
Three Months Ended December 31, 2005
From time to time, we enter into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At September 30, 2005, the fair value of our two open crude oil swap arrangements was $7.3 million, and is reported as a component of Derivative Contracts in the liability section of the accompanying Condensed Consolidated Balance Sheet. The total loss related to these arrangements was an increase of $2.1 million and a decrease of $1.8 million for the three months and nine months ended September 30, 2005, respectively, and has been reported as a component of Operating Revenues in the accompanying Condensed Consolidated Statement of Operations.
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 falls below the floor price, the counterparty pays us. During the first nine months of 2005, natural gas price collars covered 11,753 Mmcf, or 21%, of our 2005 gas production, with a weighted average floor of $5.67 per Mcf and a weighted average ceiling of $8.68 per Mcf.
At September 30, 2005, we had open natural gas price collar contracts covering our 2005 and 2006 production as follows:
First Quarter 2006
Second Quarter 2006
Third Quarter 2006
Fourth Quarter 2006
Full Year 2006
During the first nine months of 2005, crude oil price collars covered 273 Mbbl, or 20%, of our 2005 oil production, with a weighted average floor of $40.00 per Bbl and a weighted average ceiling of $50.50 per Bbl. At September 30, 2005, we had two open crude oil price collar contracts covering our 2005 and 2006 production as follows:
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We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and 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” on page 33.
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.
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PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings
The information set forth under the captions “Wyoming Royalty Litigation” and “Raymondville Area” in Note 7 of the Notes to Unaudited 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 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
Period
ApproximateNumber
of Shares thatMay Yet BePurchasedUnder thePlans orPrograms
July 2005
August 2005
September 2005
On August 13, 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. Subsequent to this announcement, on February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s Common Stock. As a result of this stock split, this figure has been adjusted to three million shares. All purchases executed have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s Common Stock.
ITEM 5. Other Information
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ITEM 6. Exhibits
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
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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.
/s/ Dan O. Dinges
/s/ Scott C. Schroeder
/s/ Henry C. Smyth
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