UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
For the quarterly period ended June 30, 2007
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, including area code)
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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
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 July 25, 2007, there were 97,014,595 shares of Common Stock, Par Value $.10 Per Share, outstanding.
INDEX TO FINANCIAL STATEMENTS
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PART I. FINANCIAL INFORMATION
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
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
Weighted Average Common Shares Outstanding
Diluted Common Shares (Note 5)
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, Net
Income Taxes Receivable
Inventories
Deferred Income Taxes
Derivative Contracts (Note 7)
Total Current Assets
Properties and Equipment, Net (Successful Efforts Method) (Note 2)
Other Assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable
Current Portion of Long-Term Debt
Income Taxes Payable
Accrued Liabilities
Total Current Liabilities
Long-Term Liability for Pension Benefits (Note 10)
Long-Term Liability for Postretirement Benefits (Note 10)
Long-Term Debt (Note 4)
Other Liabilities
Commitments and Contingencies (Note 6)
Stockholders’ Equity
Common Stock:
Authorized — 120,000,000 Shares of $0.10 Par Value in 2007 and 2006, respectively
Issued and Outstanding — 102,219,295 Shares and 101,418,220 Shares in 2007 and 2006, respectively
Additional Paid-in Capital
Retained Earnings
Accumulated Other Comprehensive Income (Note 8)
Less Treasury Stock, at Cost:
5,204,700 Shares in both 2007 and 2006
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:
Deferred Income Tax Expense
Exploration Expense
Stock-Based Compensation Expense and Other
Changes in Assets and Liabilities:
Other Current Assets
Accounts Payable and Accrued Liabilities
Stock-Based Compensation Tax Benefit
Net Cash Provided by Operating Activities
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures
Proceeds from Sale of Assets
Net Cash Used in Investing Activities
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt
Decrease in Debt
Sale of Common Stock Proceeds
Purchase of Treasury Stock
Dividends Paid
Net Cash Provided by / (Used in) 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 Annual Report on Form 10-K for the year ended December 31, 2006 filed with the Securities and Exchange Commission (SEC). The interim financial statements should be read in conjunction with the notes to the financial statements and information presented in the Company’s 2006 Annual Report to Stockholders and its Annual Report on Form 10-K. 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. Additionally, certain amounts have been reclassified to conform to the fiscal year 2007 presentation. The results for any interim period are not necessarily indicative of the expected results 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 23, 2007, the Board of Directors declared a 2-for-1 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 30, 2007 to stockholders of record on March 16, 2007. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company’s common stock. The pro forma effect on the December 31, 2006 Balance Sheet was a reduction to Additional Paid-in Capital and an increase to Common Stock of $5.1 million.
Effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” The Company recorded a charge of $0.2 million during the first six months of 2007 for incremental interest expense that is more likely than not payable. For further information regarding the adoption of FIN 48, please refer to Note 12 of the Notes to the Condensed Consolidated Financial Statements.
Recently Issued Accounting Pronouncements
In May 2007, the FASB issued Staff Position (FSP) No. FIN 48-1, “Definition ofSettlement in FASB Interpretation No. 48,” which amends FIN 48 and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, FSP No. FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FSP No. FIN 48-1 is effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this FSP to the date of the initial adoption of FIN 48. The Company has adopted FSP No. FIN 48-1 and no retroactive adjustments are necessary.
In April 2007, the FASB issued FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” to amend FIN 39, “Offsetting of Amounts Related to Certain Contracts.” The terms “conditional contracts” and “exchange contracts” used in FIN 39 have been replaced with the more general term “derivative contracts.” In addition, FSP No. FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a Company’s accounting policy with respect to offsetting fair value amounts. The guidance in FSP No. FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption should be recognized as a change in accounting principle through retrospective application for all periods presented. The Company does not believe that the adoption of FSP No. FIN 39-1 will have a material impact on its financial position, results of operations or cash flows.
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In February 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” 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 instruments for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 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. The Company is currently evaluating what impact, if adopted, SFAS No. 159 may have on its financial position or results of 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 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. The Company is currently evaluating what impact SFAS No. 157 may have on its financial position or results of operations.
2. PROPERTIES AND EQUIPMENT, NET
Properties and equipment, net 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
At June 30, 2007, the Company did not have any capitalized well costs that have been capitalized for greater than one year after drilling was suspended.
At December 31, 2006, the Company had four projects that had $0.1 million of exploratory well costs that were capitalized since 2005 for a period greater than one year. This amount related to three projects comprised of preliminary costs incurred in the preparation of well sites where drilling had not commenced as of December 31, 2006. In 2007, it was determined not to drill these projects and associated costs were expensed. Also included in the December 31, 2006 amount was another well that had completed drilling in January 2007 and was awaiting completion results before confirmation of proved reserves could be made. That well was completed in 2007 and proved reserves were recorded in the first quarter of 2007.
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Disposition of Assets
On September 29, 2006, the Company substantially completed the sale of its offshore portfolio and certain south Louisiana properties to Phoenix Exploration Company LP (Phoenix) for a gross sales price of $340.0 million. Through June 30, 2007, the Company received approximately $333.3 million in net proceeds from the sale. 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 of $12.3 million ($7.7 million, net of tax) in the Condensed Consolidated Statement of Operations for the six months ended June 30, 2007, which included cash proceeds of $5.8 million received in the first quarter of 2007, $2.1 million in purchase price adjustments and $4.4 million that was deferred until legal title to certain properties could be assigned.
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3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
ACCOUNTS RECEIVABLE, NET
Trade Accounts
Joint Interest Accounts
Other Accounts
Allowance for Doubtful Accounts
INVENTORIES
Natural Gas and Oil in Storage
Tubular Goods and Well Equipment
Pipeline Imbalances
OTHER CURRENT ASSETS
Drilling Advances
Prepaid Balances
ACCOUNTS PAYABLE
Natural Gas Purchases
Royalty and Other Owners
Capital Costs
Wellhead Gas Imbalances
ACCRUED LIABILITIES
Employee Benefits
Current Liability for Pension Benefits
Current Liability for Postretirement Benefits
Interest Payable
OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan
Accrued Plugging and Abandonment Liability
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4. LONG-TERM DEBT
At June 30, 2007, the Company had $25 million of borrowings outstanding under its revolving credit facility, at an interest rate of 8.25%. 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 borrowings under the credit facility, the Company had the following debt outstanding at June 30, 2007:
$60 million of 12-year 7.19% Notes due in November 2009, which consisted of $40 million of long-term debt and $20 million of current portion of long-term debt, to be repaid in 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
The Company is in compliance in all material respects with its debt covenants.
5. 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 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 and six months ended June 30, 2007 and 2006:
Six Months Ended
June 30,
Weighted-Average Shares - Basic
Dilution Effect of Stock Options and Awards at End of Period
Weighted-Average Shares - Diluted
Weighted-Average Stock Awards and Shares
Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect
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6. COMMITMENTS AND CONTINGENCIES
Contingencies
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.
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 the 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 resulted in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and limiting the claims to those arising on and after December 17, 1991. The Court postponed a trial date 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 West Virginia Supreme Court of Appeals issued a decision in 2006 in a case 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 the Company has raised in its litigation with respect to the issue of deductibility of post-production expenses under certain leases, but it believes that in a significant number of leases the Company has lease language, factual distinctions and defenses that are not implicated by the ruling.
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 verdict against the producer for $130 million in compensatory damages and $270 million in punitive damages. The Court has entered an order in the Tawney case affirming the punitive damage award, and final judgment is expected in the near future. 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 its case. The case against the Company was recently re-activated to the docket and trial was set for August 13, 2007.
The parties are engaged in settlement discussions and a tentative settlement has been reached. Any settlement reached between the parties is not final or binding until approved by the Court. A reserve has been established that management believes is adequate based on its estimate of the probable outcome of this case.
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
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Company could incur approximately $8.4 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.
Firm Gas Transportation Agreements
The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. The agreements provide firm transportation capacity rights on pipeline systems in Canada, the West region and the East 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 decreased in the first half of 2007 by approximately $2.4 million from the amount previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. For further information on these future obligations, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2006.
Drilling Rig Commitments
In its Annual Report on Form 10-K for the year ended December 31, 2006, the Company disclosed that it had commitments on seven drilling rigs under contract in the Gulf Coast and that one of these rigs had not yet been delivered. This rig was delivered in April 2007. As of June 30, 2007, the total commitment increased by $0.9 million in the aggregate from the amount disclosed in the Annual Report on Form 10-K (decreased by $1.9 million in 2007 and increased by $2.6 million and $0.2 million in 2008 and 2009, respectively). For further information on these future obligations, please refer to Note 7 of the Notes to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2006.
7. 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. 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 June 30, 2007, the Company had 24 cash flow hedges open: 22 natural gas price collar arrangements and two crude oil collar arrangements. At June 30, 2007, a $36.9 million ($23.0 million, net of tax) unrealized gain was recorded in Accumulated Other Comprehensive Income, along with a $36.5 million short-term derivative receivable, a $0.3 million short-term derivative liability (included within Accrued Liabilities on the Balance Sheet), a $0.9 million long-term derivative receivable (included within Other Assets on the Balance Sheet) and a $0.2 million long-term derivative liability (included within Other 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, as appropriate. During the first six months of 2007 and 2006, there was no ineffectiveness recorded in the Condensed Consolidated Statement of Operations.
Assuming no change in commodity prices, after June 30, 2007 the Company would expect to reclassify to the Condensed Consolidated Statement of Operations, over the next 12 months, $22.6 million in after-tax income associated with commodity hedges. This reclassification represents the net short-term receivable associated with
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open positions currently not reflected in earnings at June 30, 2007 related to anticipated 2007 and 2008 production.
During the first half of 2007, the Company entered into three new natural gas collar contracts and one new crude oil collar contract covering a portion of its 2008 production. As of June 30, 2007, natural gas price collars for the full 2008 year will cover 9,808 Mmcf of production at a weighted average floor of $8.40 per Mcf and a weighted average ceiling of $11.03 per Mcf. As of June 30, 2007, the crude oil price collar for the full 2008 year will cover 366 Mbbls of production at a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.
8. COMPREHENSIVE INCOME
Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Accumulated Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the three and six month periods ended June 30, 2007 and 2006:
Three Months Ended
Accumulated Other Comprehensive Income / (Loss) - Beginning of Period
Other Comprehensive Income / (Loss)
Reclassification Adjustment for Settled Contracts, net of taxes of $4,962, $2,734, $11,681 and $3,281, respectively
Changes in Fair Value of Hedge Positions, net of taxes of $(7,795), $(9,253), $5,109 and $(21,379), respectively
Defined Benefit Pension and Postretirement Plans:
Amortization of Net Obligation at Transition, net of taxes of $(119)
Amortization of Prior Service Cost, net of taxes of $(207)
Amortization of Net Loss, net of taxes of $(242)
Total Defined Benefit Pension and Postretirement Plans, net of taxes of $(568), $ - , $(568) and $ - , respectively
Foreign Currency Translation Adjustment, net of taxes of $(2,291), $(698), $(2,573) and $(563), respectively
Total Other Comprehensive Income / (Loss)
Comprehensive Income
Accumulated Other Comprehensive Income - End of Period
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Changes in the components of accumulated other comprehensive income, net of taxes, for the six months ended June 30, 2007 were as follows:
Accumulated Other Comprehensive Income
Balance at December 31, 2006
Net change in unrealized gains on cash flow hedges, net of taxes of $16,790
Net change in defined benefit pension and postretirement plans, net of taxes of $(568)
Change in foreign currency translation adjustment, net of taxes of $(2,573)
Balance at June 30, 2007
9. ASSET RETIREMENT OBLIGATIONS
The following table reflects the changes in the asset retirement obligations during the six months ended June 30, 2007:
Carrying amount of asset retirement obligations at December 31, 2006
Liabilities added during the current period
Liabilities settled and divested during the current period
Current period accretion expense
Carrying amount of asset retirement obligations at June 30, 2007
Accretion expense was $0.5 million and $0.7 million, respectively, for the six months ended June 30, 2007 and 2006 and is included within Depreciation, Depletion and Amortization expense on the Company’s Condensed Consolidated Statement of Operations.
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10. PENSION AND OTHER POSTRETIREMENT BENEFITS
The components of net periodic benefit costs for the three and six months ended June 30, 2007 and 2006 were as follows:
Current Period Service Cost
Interest Cost
Expected Return on Plan Assets
Amortization of Prior Service Cost
Amortization of Net Loss
Net Periodic Pension Cost
Plan Termination Gain
Amortization of Net Obligation at Transition
Total Postretirement Benefit Cost
Employer Contributions
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, 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 2007. It is anticipated that these contributions will be made prior to December 31, 2007. The Company does not have any required minimum funding obligations for its qualified pension plan in 2007. Management has not determined the level of discretionary funding, if any, that will be made to the qualified pension plan during the remainder of 2007.
11. STOCK-BASED COMPENSATION
Incentive Plans
Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards. In the first quarter of 2007, the Board of Directors eliminated the automatic award of an option to purchase 15,000 shares (pre 2-for-1 split) of common stock on the date the non-employee directors first join the board of directors. In its place, the Board of Directors will consider an annual fixed dollar stock award which is competitive with the Company’s peer group. A total of 5,100,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 1,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 3,000,000 shares may be issued pursuant to incentive stock options.
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Stock-Based Compensation Expense
Compensation expense charged against income for stock-based awards during the first half of 2007 and 2006 was $10.7 million and $9.1 million, pre-tax, respectively, and is included in General and Administrative Expense in the Condensed Consolidated Statement of Operations. Of this expense, $4.1 million and $4.2 million were incurred during the second quarter of 2007 and 2006, respectively.
For further information regarding Stock-Based Compensation, please refer to Note 10 of the Notes to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2006.
Restricted Stock Awards
Restricted stock awards vest either at the end of a three year service period, or on a graded-vesting basis of one-third at each anniversary date over a three 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, 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 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.
During the first half of 2007, there were no shares of restricted stock granted. Compensation expense recorded for all unvested restricted stock awards for the first six months of 2007 and 2006 was $1.8 million and $3.7 million, respectively. Included in 2006 restricted stock expense was $0.5 million related to the immediate expensing of shares granted to retirement-eligible employees.
Restricted Stock Units
Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are paid out when the director ceases to be a director of the Company.
During the first half of 2007, 24,654 restricted stock units were granted with a grant date per share value of $35.49. The compensation cost, which reflects the total fair value of these units, recorded in the first quarter of 2007 was $0.9 million. During the second quarter of 2006, the Company recorded $0.9 million of expense related to restricted stock units.
Stock Options
Stock option awards are granted with an exercise price equal to the fair market price (defined as the average of the high and low trading prices of the Company’s stock at the date of 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.
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During the first half of 2007, there were no stock options granted. Compensation expense recorded during the first six months of 2007 and 2006 for amortization of stock options was $0.1 million for each period.
Stock Appreciation Rights
During the first six months of 2007, the Compensation Committee granted 107,200 SARs to employees. These awards allow the employee to receive any intrinsic value over the $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 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:
Weighted Average Value per Stock Appreciation Right
Granted During the Period (1)
Assumptions
Stock Price Volatility
Risk Free Rate of Return
Expected Dividend
Expected Term (in years)
(1)
Calculated using the Black-Scholes fair value based method.
Compensation expense recorded during the first six months of 2007 and 2006 for SARs was $1.0 million and $0.4 million, respectively. Included in the 2007 amount was $0.5 million related to the immediate expensing of shares granted to retirement-eligible employees.
Performance Share Awards
During 2007, the Compensation Committee granted three types of performance share awards to employees for a total of 387,100 performance shares. The performance period for two of these awards commences on January 1, 2007 and ends December 31, 2009. Both of these types of awards vest at the end of the three year performance period.
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 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.
Awards totaling 196,500 performance shares are earned, or not earned, based on the Company’s internal performance metrics rather than a peer group. The grant date per share value 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 the Company’s performance against three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at June 30, 2007, it is currently considered probable that these three criteria will be met.
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The third performance share award, totaling 92,400 performance shares, with a grant date per share value of $35.22, has a three-year graded vesting schedule, vesting one-third on each anniversary date following the date of grant, provided that the Company has positive operating income for the year preceding the vesting date. If the Company does not have positive operating income for the year preceding a vesting date, then the portions of the performance shares that would have vested on that date will be forfeited. As of June 30, 2007, it is considered probable that this performance metric will be met.
For all awards granted to employees after January 1, 2006, an annual forfeiture rate ranging from 0% to 5.0% has been assumed based on the Company’s history for this type of award to various employee groups.
For awards that are based on the internal metrics (performance condition) of the Company and for awards that were granted prior to the adoption of SFAS No. 123(R) on January 1, 2006, 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 was valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model.
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 was 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 June 30, 2007 for the Monte Carlo model to value the liability component of the peer group measured performance share awards. The equity portion of the award has already been valued on the date of grant using the Monte Carlo model and this portion was not marked to market.
Correlation in Stock Price Movement
The liability component for all outstanding market condition performance share awards ranged from $12.28 to $32.93 at June 30, 2007. The long-term liability for all market condition performance share awards, included in Other Liabilities in the Condensed Consolidated Balance Sheet at June 30, 2007 and 2006 was $1.9 million and $1.1 million, respectively. The short-term liability, included in Accrued Liabilities in the Condensed Consolidated Balance Sheet at June 30, 2007 and 2006, for certain market condition performance share awards was $4.5 million and $0.3 million, respectively.
Total compensation cost recognized for both the equity and liability components of all performance share awards during the six months ended June 30, 2007 and 2006 was $6.9 million and $4.0 million, respectively.
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12. UNCERTAIN TAX POSITIONS
In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.” This Interpretation provides guidance for recognizing and measuring uncertain tax positions as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit of the uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN 48 provides additional guidance on measuring the amount of the uncertain tax position. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and increased disclosure of these uncertain tax position. FIN 48 is effective for fiscal years beginning after December 15, 2006.
The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized no change to the liability for unrecognized tax benefits.
As of January 1, 2007, after the implementation of FIN 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 the Interest Expense and Other line and penalties accrued in the General and Administrative line in the Condensed Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods. During the first half of 2007, the Company recorded $0.2 million of interest expense related to uncertain tax positions. As of January 1, 2007, the Company had recorded a liability of approximately $0.9 million for interest. As of June 30, 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 its 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 respective return. The state impact of any federal changes remains subject to examination by various states for a period of 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 an upcoming examination, by West Virginia. The Company has been audited by Texas. The audits were resolved successfully and no material adjustments were needed.
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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 June 30, 2007, the related condensed consolidated statement of operations for each of the three and six month periods ended June 30, 2007 and 2006, and the condensed consolidated statement of cash flows for the six month periods ended June 30, 2007 and 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, 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, 2006 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006; and in our report dated February 28, 2007, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for 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, 2006, 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
July 30, 2007
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The following review of operations for the three and six month periods ended June 30, 2007 and 2006 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, 2006.
Overview
Operating revenues for the six months ended June 30, 2007 decreased by $38.2 million, or nine percent, from the six months ended June 30, 2006 due to decreased equivalent production resulting from the disposition of assets substantially completed in the third quarter of 2006 and, to a lesser extent, decreased realized commodity prices. Natural gas revenues decreased by $5.8 million, or two percent, for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. The decrease is due to a decrease in both natural gas prices and production. Oil revenues decreased by $29.7 million, or 55%, for the first six months of 2007 as compared to the first six months of 2006. This 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 six months of 2007 as compared to the first six months of 2006. Excluding $51.5 million and $32.3 million, respectively, of natural gas and crude oil revenues from our 2006 results attributable to properties sold, natural gas revenues for the first half of 2007 would have increased by 19% and crude oil revenues would have increased by 12%. Brokered natural gas revenues increased by $0.9 million due to an increase in brokered volumes, partially offset by a decrease in sales price.
Our realized natural gas price for the first half of 2007 was $7.33 per Mcf, two percent lower than the $7.46 per Mcf price realized in the same period of the prior year. Our realized crude oil price was $57.76 per Bbl, 11% lower than the $64.88 per Bbl price realized in the same period of the prior year. These realized prices include realized gains and losses resulting from commodity 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 six months of 2007 decreased by six percent from the first six months of 2006. For the six months ended June 30, 2007, we produced 42.2 Bcfe compared to production of 44.8 Bcfe for the comparable period of the prior year. Natural gas production was 39.7 Bcf and oil production was 419 Mbbls for the first half of 2007. Natural gas production decreased by less than one percent when compared to the comparable period of the prior year, which had production of 39.8 Bcf. This decrease was primarily a result of a decline in production in the Gulf Coast, partially offset by increased production in the West and East regions associated with an increase in the drilling program and an increase in Canada due to increased pipeline capacity in Canada for the Hinton field. The Gulf Coast region experienced an overall decrease in natural gas production of 2.9 Bcf, or 18%. Excluding 6.3 Bcf of natural gas production related to the properties sold in the third quarter of 2006, the Gulf Coast region would have experienced a 3.4 Bcf, or 35% increase in production in the first half of 2007 compared to the first half of 2006, primarily as a result of increased drilling in the Minden and McCampbell fields and recompletions in the Raymondville field. Oil production decreased by 411 Mbbls, or 50%, from 830 Mbbls in the first half of 2006 to 419 Mbbls produced in the first half of 2007. This was primarily the result of a decrease of 391 Mbbls in the Gulf Coast region. Excluding 492 Mbbls of crude oil production related to the properties sold in the third quarter of 2006, oil production would have increased by 24% in the first half of 2007 compared to the first half of 2006, 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 remained flat in the East region, decreased slightly in the West region due to natural decline and increased by three Mbbls in Canada.
We had net income of $89.9 million, or $0.93 per share, for the six months ended June 30, 2007 compared to net income of $100.0 million, or $1.03 per share, for the comparable period of the prior year. The decrease in net income is primarily due to decreased natural gas and oil production revenues, as discussed above.
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Partially offsetting this revenue decrease was a decrease in total operating expenses of $6.4 million in the first half of 2007 as compared to the first half of 2006, primarily due to decreased exploration charges, and to a lesser extent taxes other than income, partially offset by increased general and administrative expenses, depreciation, depletion and amortization (DD&A) and impairment of unproved properties. These impacts reduced income before taxes and consequently decreased income taxes by $4.9 million. Gain on sale of assets was $12.1 million higher in the first half of 2007 compared to the first half of 2006 as a result of the completion of our disposition of certain south Louisiana and offshore properties in 2007.
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 2007, we expect to spend approximately $500 million in capital and exploration expenditures. Funding of the program will come from operating cash flow, existing cash and increased borrowings, if required. For the six months ended June 30, 2007, approximately $300.1 million of capital and exploration expenditures have been invested in our exploration and development efforts.
During the six months ended June 30, 2007, we drilled 222 gross wells (215 development, 4 exploratory and 3 extension wells) with a success rate of 98% compared to 191 gross wells (176 development, 12 exploratory and 3 extension wells) with a success rate of 94% for the comparable period of the prior year. For the full year of 2007, we plan to drill approximately 430 gross wells compared to 387 gross wells drilled in 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.
The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.
Financial Condition
Capital Resources and Liquidity
Our primary sources of cash for the six months ended June 30, 2007 were from funds generated from the sale of natural gas and crude oil production and, to a lesser extent, from borrowings under our revolving credit facility and proceeds from the sale of assets. Cash flows provided by operating activities were primarily used to fund development and, to a lesser extent, exploratory expenditures, and to pay dividends. See below for additional discussion and analysis of cash flow.
Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, 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. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales.
Our working capital is also substantially influenced by these variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate liquidity available to meet our working capital requirements.
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Cash Flows Provided by Operating Activities
Cash Flows Used in Investing Activities
Cash Flows Provided by / (Used in) Financing Activities
Operating Activities. Net cash provided by operating activities in the first half of 2007 decreased by $27.5 million over the comparable period in 2006. This decrease is primarily due to a decrease in working capital changes as well as a decrease in net income due to decreased equivalent production and, to a lesser extent, reduced commodity prices. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average crude oil realized prices decreased by 11% for the first half of 2007 versus the 2006 period and average realized natural gas prices decreased by two percent over the same period. Equivalent production volumes decreased by approximately six percent in the first six months of 2007 compared to the comparable period in 2006. While we believe 2007 production may match the 2006 actual commodity production 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. 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. Cash flows used in investing activities increased by $28.3 million from the first six months of 2006 compared to the first six months of 2007. The increase from 2006 to 2007 is due to an increase in capital expenditures, partially offset by decreased exploration expense and an increase in proceeds from the sale of assets related to the disposition of certain south Louisiana and offshore properties.
Financing Activities. Cash flows provided by financing activities were $18.5 million for the first half of 2007, and were comprised of a net increase in borrowings under our revolving credit facility, proceeds from the exercise of stock options and the tax benefit received from stock-based compensation payments, partially offset by dividend payments. Cash flows used in financing activities were $13.6 million for the six months ended June 30, 2006, primarily due to payments made to purchase treasury stock and pay dividends. Partially offsetting these cash uses were inflows from the net increase in borrowings under our revolving credit facility, proceeds from the exercise of stock options and the tax benefit received from stock-based compensation.
At June 30, 2007, we had $25 million of borrowings outstanding under our credit facility, at an interest rate of 8.25%. 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. In October 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 ten million shares. During the six months ended June 30, 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 June 30, 2007 was 4,795,300. See “Unregistered Sales of Equity Securities and Use of Proceeds – Issuer Purchases of Equity Securities” in Item 2 of Part II of this quarterly report.
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Capitalization
Information about our capitalization is as follows:
(In millions)
Debt (1)
Total Capitalization
Debt to Capitalization
Includes $20.0 million of current portion of long-term debt at both June 30, 2007 and December 31, 2006. Includes $25.0 million and $10.0 million of borrowings outstanding under our revolving credit facility at June 30, 2007 and December 31, 2006, respectively.
During the six months ended June 30, 2007, we paid dividends of $4.8 million on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990. After the March 2007 2-for-1 stock split, the dividend was increased to $0.03 per share per quarter, or a 50% increase from pre-split levels.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration activities, excluding any significant oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.
The following table presents major components of capital and exploration expenditures for the six months ended June 30, 2007 and 2006:
Drilling and Facilities
Leasehold Acquisitions
Pipeline and Gathering
Proved Property Acquisitions
Total
We plan to drill approximately 430 gross wells in 2007. This drilling program includes approximately $500 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 and crude oil price environment and may increase or decrease the capital and exploration expenditures accordingly.
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Contractual Obligations
During the six months ended June 30, 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, 2006.
Our firm gas transportation agreements provide firm transportation capacity rights on pipeline systems in Canada, the West region and the East region. These amounts are payable over the next 21 years. The transportation demand charges under these agreements that we are estimated to pay, regardless of the amount of pipeline capacity we utilize, decreased in the first half of 2007 by approximately $2.4 million from the total $85.1 million figure previously disclosed in our Annual Report on Form 10-K. This is due to released volumes on one contract in the West region. As of June 30, 2007, demand charges for 2007 and 2008, respectively, are expected to be $8.2 million and $7.5 million, a decrease of $1.7 million and $0.7 million from the amounts previously disclosed.
Drilling rig commitments increased by $0.9 million from the $120.3 million figure reported in our Annual Report on Form 10-K for the year ended December 31, 2006.
For further information, please refer to “Firm Gas Transportation Agreements” and “Drilling Rig Commitments” under Note 6 in the Notes to the Condensed Consolidated Financial Statements.
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. See our Annual Report on Form 10-K for the year ended December 31, 2006, for further discussion of our critical accounting policies.
Effective January 1, 2007, we adopted the provisions of FIN 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” This adoption did not have a material impact on any of our financial statements.
Results of Operations
Second Quarters of 2007 and 2006 Compared
We reported net income in the second quarter of 2007 of $41.4 million, or $0.43 per share. During the corresponding quarter of 2006, we reported net income of $46.9 million, or $0.48 per share. Net income decreased in the second quarter by $5.5 million, primarily due to a decrease in operating income of $7.7million from $77.9 million in the second quarter of 2006 to $70.2 million in the second quarter of 2007, partially offset by a decrease of $2.2 million resulting from a combination of lower interest and other expenses and higher income tax expense.
The decrease in operating income was primarily the result of a decrease in natural gas and crude oil production revenues, offset in part by a decrease in operating expenses of $2.9 million and an increase in gain on sale of assets of $4.4 million. The decrease in operating expenses was primarily the result of reduced exploration expense, which was partially offset by increases in DD&A and impairment of unproved properties expenses.
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Natural Gas Production Revenues
Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $7.24 per Mcf for the three months ended June 30, 2007 compared to $6.77 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 $0.66 per Mcf in 2007 and $0.34 per Mcf in 2006. There was no unrealized impact from the change in derivative fair value for the three months ended June 30, 2007 or 2006.
Natural Gas Production (Mmcf)
East
Gulf Coast
West
Canada
Total Company
Natural Gas Production Sales Price ($/Mcf)
Natural Gas Production Revenue (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 primarily due to the increase in realized natural gas sales prices, partially offset by a decrease in natural gas production. The decrease in the realized natural gas production and increase in prices resulted in a net revenue increase of $2.6 million. After removing from the second quarter 2006 results $24.2 million of natural gas revenues and 3,316 Mmcf of natural gas production associated with properties in the Gulf Coast region sold in the third quarter 2006 divestiture, total natural gas revenue would have increased by $26.8 million, or 23%, and natural gas production would have increased by 2,334 Mmcf, or 13%, from the second quarter of 2006 to the second quarter of 2007.
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Brokered Natural Gas Revenue and Cost
Sales Price ($/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 decreased brokered natural gas margin of $0.1 million is primarily a result of a decrease in the volumes brokered in the second quarter of 2007 over the same period in the prior year.
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Crude Oil and Condensate Revenues
Our average total company realized crude oil sales price was $61.98 per Bbl for the second quarter of 2007. Our average total company realized crude oil sales price was $68.32 per Bbl for the second quarter of 2006. There was no realized or unrealized impact of derivative instruments in the second quarter of 2007 or 2006.
Crude Oil Production (Mbbl)
Crude Oil Sales Price ($/Bbl)
Crude Oil Revenue (In thousands)
Price Variance Impact on Crude Oil Revenue
Volume Variance Impact on Crude Oil Revenue
The decrease in production combined with the decrease in realized crude oil prices resulted in a net revenue decrease of $16.4 million. The decrease in oil production is mainly the result of the sale in the third quarter of 2006 of certain south Louisiana and offshore properties in the Gulf Coast region. After removing from the second quarter 2006 results $16.9 million of crude oil revenues and 242 Mbbls of crude oil production associated with properties in the Gulf Coast region sold in third quarter of 2006 divestiture, total crude oil revenue would have increased by $0.5 million, or four percent, and crude oil production would have increased by 22 Mbbls, or 11%, from the second quarter of 2006 to the second quarter of 2007.
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Impact of Derivative Instruments on Operating Revenues
The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:
Operating Revenues - Increase to Revenue
Cash Flow Hedges
Crude Oil
Total Cash Flow Hedges
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
Other operating revenues decreased by $1.7 million between the second quarter of 2007 and the second quarter of 2006 primarily due to the fact that, during the second quarter of 2006, we had an increase in revenue of $1.5 million related to net profits interests that originated in 2006.
Operating Expenses
Total costs and expenses from operations decreased $2.9 million in the second quarter of 2007 compared to the same period of 2006. The primary reasons for this fluctuation are as follows:
Exploration expense decreased by $8.0 million in the second quarter of 2007, primarily as a result of a decrease in total dry hole expense of $8.5 million and a decrease in geophysical and geological expenses of $0.5 million, primarily in Canada and the Gulf Coast region, partially offset by other net expense increases.
Impairment of Unproved Properties increased by $2.4 million in the second quarter of 2007 compared to the second quarter of 2006, primarily due to increased lease acquisition costs during 2006.
Depreciation, Depletion and Amortization increased by $1.5 million in the second quarter of 2007. This is primarily due to the impact on the DD&A rate of 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 decreased by $2.2 million in the second quarter of 2007 due to lower credit facility borrowings, lower outstanding principal amount on our 7.19% fixed rate debt and increased interest income from our short term investments. Weighted average borrowings under our credit facility based on daily balances were approximately $3 million during the second quarter of 2007 compared to approximately $60 million during the second quarter of 2006.
Income tax expense increased by $0.3 million. The effective tax rate for the second quarter of 2007 and 2006 was 37.9% and 34.8%, respectively. The increase in the effective tax rate is primarily due to the sale during 2006 of certain south Louisiana producing properties which had historically generated net operating losses of a permanent nature. Additionally, the second quarter 2006 recognition of a decrease in the Texas state income tax rate due to a tax law change lowered the effective tax rate for the prior year quarter.
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Six Months of 2007 and 2006 Compared
We reported net income in the first half of 2007 of $89.9 million, or $0.93 per share. During the corresponding period of 2006, we reported net income of $100.0 million, or $1.03 per share. This decrease of $10.1 million in net income was primarily due a decrease in operating income of $19.7 million, partially offset by a $4.9 million decrease in income tax expense and a $4.7 million decrease in interest and other expenses.
The decrease in operating income was primarily the result of a decrease in operating revenues of $38.2 million, offset in part by a decrease of $6.4 million in operating expenses and an increase of $12.1 million in gain on sale of assets. This decrease in operating expenses was primarily the result of reduced exploration expense and, to a lesser extent, taxes other than income, partially offset by increases in general and administrative, DD&A and impairment expenses and other operating expense increases.
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Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $7.33 per Mcf for the six months ended June 30, 2007 compared to $7.46 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 $0.77 per Mcf in 2007 and $0.22 per Mcf in 2006. There was no unrealized impact from the change in derivative fair value for the six months ended June 30, 2007 or 2006.
The decrease in Natural Gas Production Revenue is due to the decrease in production as well as decreased realized natural gas sales prices. Prices were lower in all regions except for the Gulf Coast for the first six months of 2007 over the prior year six months for the Company. The decrease in the realized natural gas price and slight decrease in production resulted in a net revenue decrease of $5.8 million. After removing from the first half 2006 results $51.5 million of natural gas revenues and 6,302 Mmcf of natural gas production associated with properties in the Gulf Coast region sold in third quarter 2006 divestiture, total natural gas revenue would have increased by $45.7 million, or 19%, and natural gas production would have increased by 6,206 Mmcf, or 19%, from the first half of 2006 to the first half of 2007.
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The increased brokered natural gas margin of $0.8 million is driven by an increase in sales price that outpaced the increase in purchase price, partially offset by a decrease in the volumes brokered in the first half of 2007 over the same period in the prior year.
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Our average total company realized crude oil sales price was $57.76 per Bbl for the first half of 2007. The 2007 price includes the realized impact of derivative instrument settlements which increased the price by $0.43 per Bbl. Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $64.88 per Bbl for the first half of 2006. There was no realized impact of derivative instruments in the first six months of 2006. There was no unrealized impact from the change in derivative fair value for the either the first half of 2007 or 2006.
The decrease in the realized crude oil production combined with the decline in realized prices resulted in a net revenue decrease of $29.7 million. The decrease in oil production is mainly the result of the sale in the third quarter of 2006 of certain south Louisiana and offshore properties in the Gulf Coast region. After removing from the first half 2006 results $32.3 million of crude oil revenues and 492 Mbbls of crude oil production associated with properties in the Gulf Coast region sold in the divestiture, total crude oil revenue would have increased by $2.6 million, or 12%, and crude oil production would have increased by 81 Mbbls, or 24%, from the first half of 2006 to the first half of 2007.
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Other operating revenues decreased by $3.6 million between the six months ended June 30, 2007 and the six months ended June 30, 2006 primarily due to a larger amount of net profits interest in 2006, favorable settlements of state severance tax audits in 2006 and a decrease in our payout liability in the first quarter of 2006 associated with a favorable legal ruling.
Total costs and expenses from operations decreased by $6.4 million in the first half of 2007 compared to the same period of 2006. The primary reasons for this fluctuation are as follows:
Exploration expense decreased by $13.9 million in the first six months of 2007, primarily as a result of a decrease in total dry hole expense of $11.7 million and a decrease in geophysical and geological expenses of $2.9 million, primarily in Canada and the Gulf Coast region.
General and Administrative expense increased by $3.4 million in the first half of 2007 primarily due to increased stock compensation charges of $1.6 million resulting from increased performance share expense from new grants issued in 2007 and a favorable company ranking against its peers and the associated increase in the liability related to the cash portion of the awards. In addition, SAR expense was higher due to new awards granted in 2007, including awards to retirement eligible employees which are expensed immediately upon grant. Another component of the increase was other compensation related expenses, which increased by approximately $1.0 million. Partially offsetting this was a decrease in professional services for litigation.
Depreciation, Depletion and Amortization increased by $3.0 million in the first six months of 2007 over the first six months of 2006. This is primarily due to the impact on the DD&A rate of negative reserve revisions due to lower prices at year-end, higher capital costs and commencement of production in an East Texas field.
Impairment of Unproved Properties increased by $2.8 million in the first half of 2007 compared to the first half of 2006, primarily due to increased lease acquisition costs during 2006.
Taxes Other Than Income decreased by $2.4 million in the six months ended June 30, 2007 compared to the six months ended June 30, 2006, primarily due to decreased production taxes of $1.5 million as a result of decreased natural gas and crude oil volumes and prices as well as a decrease in ad valorem taxes resulting form the sale of assets in the third quarter of 2006, partially offset by an increase in franchise taxes.
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Interest expense, net decreased by $4.4 million in the first six months of 2007 due to lower credit facility borrowings, lower outstanding principal amount on our 7.19% fixed rate debt and increased interest income from our short term investments. Weighted average borrowings under our credit facility based on daily balances were approximately $3 million during the first half of 2007 compared to approximately $64 million during the first half of 2006.
Income tax expense decreased by $4.9 million due to a comparable decrease in our pre-tax income, primarily as a result of the decrease in revenues. The effective tax rate for the first half of 2007 and 2006 was 36.6% and 36.3%, respectively. The increase in the effective tax rate is primarily due to the sale during 2006 of certain south Louisiana producing properties which had historically generated net operating losses of a permanent nature. Additionally, the second quarter 2006 recognition of a decrease in the Texas state income tax rate due to a tax law change lowered the effective tax rate for the prior year quarter.
In May 2007, the FASB issued FSP No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48,” which amends FIN 48 and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, FSP No. FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FSP No. FIN 48-1 is effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this FSP to the date of the initial adoption of FIN 48. We have adopted FSP No. FIN No 48-1and no retroactive adjustments are necessary.
In April 2007, the FASB issued FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” to amend FIN 39, “Offsetting of Amounts Related to Certain Contracts.” The terms “conditional contracts” and “exchange contracts” used in FIN 39 have been replaced with the more general term “derivative contracts.” In addition, FSP No. FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a Company’s accounting policy with respect to offsetting fair value amounts. The guidance in FSP No. FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption should be recognized as a change in accounting principle through retrospective application for all periods presented. We do not believe that the adoption of FSP No. FIN 39-1 will have a material impact on our financial position, results of operations or cash flows.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” 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 instruments for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 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 what impact SFAS No. 159, if adopted, may have on our financial position or results of 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 United States GAAP to be measured at fair value. SFAS No. 157 clarifies guidance in 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
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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 or results of 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.
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 six months of 2007, natural gas price collars covered 21,092 Mmcf, or 53%, of our first half of 2007 gas production, with a weighted average floor of $8.99 per Mcf and a weighted average ceiling of $12.19 per Mcf.
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At June 30, 2007, we had open natural gas price collar contracts covering a portion of our 2007 and 2008 production as follows:
Contract Period
Weighted
AverageCeiling/ Floor (per Mcf)
Net UnrealizedGain
As of June 30, 2007
Third Quarter 2007
Fourth Quarter 2007
Six Months Ended December 31, 2007
First Quarter 2008
Second Quarter 2008
Third Quarter 2008
Fourth Quarter 2008
Full Year 2008
During the first six months of 2007, a crude oil price collar covered 181 Mbbls, or 43%, of our first half of 2007 oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.
At June 30, 2007, we had two open crude oil price collar contracts covering a portion of our 2007 and 2008 production as follows:
Ceiling /Floor
(per Bbl)
Net UnrealizedLoss
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.
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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
The information set forth under the caption “West Virginia Royalty Litigation” 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.
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, 2006.
Issuer Purchases of Equity Securities
In August 1998, the Company announced that the Board of Directors authorized the repurchase of two million shares of 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 the Board of Directors increased the number of shares of 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 ten million shares. During the first half 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 these securities. The maximum number of shares that may yet be purchased under the plan as of June 30, 2007 was 4,795,300.
On May 2, 2007, the Company held its Annual Meeting of Stockholders. At this meeting, the Company’s stockholders voted on the following two matters:
the election of three directors and
the ratification of the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm for the Company for its 2007 fiscal year.
Of the 48,423,766 shares entitled to vote, 46,292,475 were present at the meeting in person or represented by proxy. Below are the results of the voting.
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Shareholders voted to re-elect three directors by the following vote:
The terms of office of directors Dan O. Dinges, James G. Floyd, Robert Kelley, P. Dexter Peacock and William P. Vititoe continued beyond the meeting date.
Shareholders voted to ratify the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm for the Company for its 2007 fiscal year by the following vote:
Against
Abstain
Broker Non-votes
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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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