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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2003 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. |
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE | 04-3072771 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
1200 Enclave Parkway, Houston, Texas 77077
(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant’s telephone number)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yesx No¨
As of October 28, 2003, there were 32,493,157 shares of Common Stock, Par Value $.10 Per Share, outstanding.
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CABOT OIL & GAS CORPORATION
Page | ||||
Part I. Financial Information | ||||
Item 1. | Financial Statements | |||
3 | ||||
Condensed Consolidated Balance Sheet at September 30, 2003 and December 31, 2002 | 4 | |||
5 | ||||
6 | ||||
Report of Independent Accountant’s Review of Interim Financial Information | 17 | |||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 18 | ||
Item 3. | 30 | |||
Item 4. | 32 | |||
Part II. Other Information | ||||
Item 6. | 33 | |||
34 |
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PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
THREE MONTHS ENDED SEPTEMBER 30, | NINE MONTHS ENDED SEPTEMBER 30, | |||||||||||||
2003 | 2002 | 2003 | 2002 | |||||||||||
NET OPERATING REVENUES | ||||||||||||||
Natural Gas Production | $ | 84,555 | $ | 52,029 | $ | 242,841 | $ | 152,684 | ||||||
Brokered Natural Gas | 18,709 | 10,838 | 73,929 | 40,223 | ||||||||||
Crude Oil and Condensate | 21,455 | 20,754 | 65,098 | 51,792 | ||||||||||
Other | 752 | 1,928 | 6,275 | 5,508 | ||||||||||
125,471 | 85,549 | 388,143 | 250,207 | |||||||||||
OPERATING EXPENSES | ||||||||||||||
Brokered Natural Gas Cost | 16,602 | 9,771 | 66,402 | 36,619 | ||||||||||
Direct Operations - Field and Pipeline | 11,271 | 11,652 | 36,022 | 35,808 | ||||||||||
Exploration | 13,999 | 9,803 | 43,053 | 27,683 | ||||||||||
Depreciation, Depletion and Amortization | 23,647 | 25,420 | 70,918 | 72,083 | ||||||||||
Impairment of Unproved Properties | 2,337 | 2,337 | 7,011 | 7,011 | ||||||||||
Impairment of Long-Lived Assets (Note 11) | 5,870 | — | 93,796 | 1,063 | ||||||||||
General and Administrative | 5,802 | 5,966 | 18,569 | 21,277 | ||||||||||
Taxes Other Than Income | 9,301 | 5,273 | 28,176 | 18,900 | ||||||||||
88,829 | 70,222 | 363,947 | 220,444 | |||||||||||
Gain (Loss) on Sale of Assets | 6,988 | (216 | ) | 7,593 | 195 | |||||||||
INCOME FROM OPERATIONS | 43,630 | 15,111 | 31,789 | 29,958 | ||||||||||
Interest Expense and Other | 6,972 | 6,314 | 18,549 | 18,871 | ||||||||||
Income Before Income Taxes | 36,658 | 8,797 | 13,240 | 11,087 | ||||||||||
Income Tax Expense | 13,990 | 2,672 | 5,044 | 3,638 | ||||||||||
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE | 22,668 | 6,125 | 8,196 | 7,449 | ||||||||||
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 12) | — | — | (6,847 | ) | — | |||||||||
NET INCOME | $ | 22,668 | $ | 6,125 | $ | 1,349 | $ | 7,449 | ||||||
Basic Earnings Per Share - Before Accounting Change | $ | 0.70 | $ | 0.19 | $ | 0.26 | $ | 0.23 | ||||||
Diluted Earnings Per Share - Before Accounting Change | $ | 0.70 | $ | 0.19 | $ | 0.25 | $ | 0.23 | ||||||
Basic Loss Per Share - Accounting Change | $ | — | $ | — | $ | (0.21 | ) | $ | — | |||||
Diluted Loss Per Share - Accounting Change | $ | — | $ | — | $ | (0.21 | ) | $ | — | |||||
Basic Earnings Per Share | $ | 0.70 | $ | 0.19 | $ | 0.04 | $ | 0.23 | ||||||
Diluted Earnings Per Share | $ | 0.70 | $ | 0.19 | $ | 0.04 | $ | 0.23 | ||||||
Average Common Shares Outstanding | 32,179 | 31,793 | 32,000 | 31,712 | ||||||||||
Diluted Common Shares (Note 5) | 32,435 | 32,136 | 32,238 | 32,080 |
The accompanying notes are an intergral part of these condensed consolidated financial statements.
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CONDENSED CONSOLIDATED BALANCE SHEET
(In Thousands, except share amounts)
SEPTEMBER 30, 2003 | DECEMBER 31, 2002 | |||||||
(Unaudited) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and Cash Equivalents | $ | 4,346 | $ | 2,561 | ||||
Restricted Cash (Note 1) | 15,761 | — | ||||||
Accounts Receivable | 78,668 | 70,028 | ||||||
Inventories | 21,860 | 15,252 | ||||||
Other | 10,734 | 5,280 | ||||||
Total Current Assets | 131,369 | 93,121 | ||||||
Properties and Equipment, Net (Successful Efforts Method) | 881,722 | 971,754 | ||||||
Other Assets | 6,901 | 7,013 | ||||||
$ | 1,019,992 | $ | 1,071,888 | |||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts Payable | $ | 91,381 | $ | 73,578 | ||||
Accrued Liabilities | 57,406 | 48,312 | ||||||
Total Current Liabilities | 148,787 | 121,890 | ||||||
Long-Term Debt | 285,000 | 365,000 | ||||||
Deferred Income Taxes | 174,822 | 200,207 | ||||||
Other Liabilities | 55,337 | 34,134 | ||||||
Stockholders’ Equity | ||||||||
Common Stock: | ||||||||
Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 32,187,557 Shares and 32,133,118 Shares in 2003 and 2002, Respectively | 3,249 | 3,213 | ||||||
Additional Paid-in Capital | 359,289 | 353,093 | ||||||
Retained Earnings | 9,268 | 11,674 | ||||||
Accumulated Other Comprehensive Loss (Note 9) | (11,376 | ) | (12,939 | ) | ||||
Less Treasury Stock, at Cost: | ||||||||
302,600 Shares in 2003 and 2002 | (4,384 | ) | (4,384 | ) | ||||
Total Stockholders’ Equity | 356,046 | 350,657 | ||||||
$ | 1,019,992 | $ | 1,071,888 | |||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
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CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In Thousands)
THREE MONTHS ENDED SEPTEMBER 30, | NINE MONTHS ENDED SEPTEMBER 30, | |||||||||||||||
2003 | 2002 | 2003 | 2002 | |||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||
Net Income | $ | 22,668 | $ | 6,125 | $ | 1,349 | $ | 7,449 | ||||||||
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: | ||||||||||||||||
Cumulative Effect of Accounting Change | — | — | 6,847 | — | ||||||||||||
Depletion, Depreciation and Amortization | 23,647 | 25,420 | 70,918 | 72,083 | ||||||||||||
Impairment of Unproved Properties | 2,337 | 2,337 | 7,011 | 7,011 | ||||||||||||
Impairment of Long-Lived Assets | 5,870 | — | 93,796 | 1,063 | ||||||||||||
Deferred Income Tax Expense | 3,072 | 2,492 | (22,176 | ) | 2,443 | |||||||||||
(Gain) Loss on Sale of Assets | (6,988 | ) | 216 | (7,593 | ) | (195 | ) | |||||||||
Exploration Expense | 13,999 | 9,803 | 43,053 | 27,683 | ||||||||||||
Other | (658 | ) | (926 | ) | 868 | 3,160 | ||||||||||
Changes in Assets and Liabilities: | ||||||||||||||||
Accounts Receivable | 6,490 | 4,034 | (8,640 | ) | 2,030 | |||||||||||
Inventories | (11,900 | ) | (4,308 | ) | (6,608 | ) | (1,899 | ) | ||||||||
Other Current Assets | 1,742 | (47 | ) | (3,870 | ) | (2,443 | ) | |||||||||
Other Assets | (102 | ) | (1,525 | ) | 112 | (1,547 | ) | |||||||||
Accounts Payable and Accrued Liabilities | 4,783 | (20,528 | ) | 29,893 | (5,412 | ) | ||||||||||
Other Liabilities | 942 | 2,159 | 746 | (3,145 | ) | |||||||||||
Net Cash Provided by Operating Activities | 65,902 | 25,252 | 205,706 | 108,281 | ||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
Capital Expenditures | (33,985 | ) | (15,460 | ) | (85,384 | ) | (86,649 | ) | ||||||||
Proceeds from Sale of Assets | 15,821 | 228 | 18,181 | 3,671 | ||||||||||||
Restricted Cash | (15,761 | ) | — | (15,761 | ) | — | ||||||||||
Exploration Expense | (13,999 | ) | (9,803 | ) | (43,053 | ) | (27,683 | ) | ||||||||
Net Cash Used by Investing Activities | (47,924 | ) | (25,035 | ) | (126,017 | ) | (110,661 | ) | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
Increase in Debt | 50,000 | 36,000 | 181,000 | 136,000 | ||||||||||||
Decrease in Debt | (69,000 | ) | (38,000 | ) | (261,000 | ) | (134,000 | ) | ||||||||
Sale of Common Stock Proceeds | 3,393 | 13 | 5,851 | 3,150 | ||||||||||||
Dividends Paid | (1,287 | ) | (1,272 | ) | (3,755 | ) | (3,808 | ) | ||||||||
Net Cash Provided (Used) by Financing Activities | (16,894 | ) | (3,259 | ) | (77,904 | ) | 1,342 | |||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 1,084 | (3,042 | ) | 1,785 | (1,038 | ) | ||||||||||
Cash and Cash Equivalents, Beginning of Period | 3,262 | 7,710 | 2,561 | 5,706 | ||||||||||||
Cash and Cash Equivalents, End of Period | $ | 4,346 | $ | 4,668 | $ | 4,346 | $ | 4,668 | ||||||||
The accompanying notes are an intergral part of these condensed consolidated financial statements.
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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. | FINANCIAL STATEMENT PRESENTATION |
During interim periods, Cabot Oil & Gas Corporation (the Company) follows the same accounting policies used in its Annual Report to Stockholders and its Report on Form 10-K filed with the Securities and Exchange Commission. People using financial information produced for interim periods are encouraged to refer to the footnotes in the Annual Report to Stockholders when reviewing interim financial results. In management’s opinion, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year.
Our independent accountants have performed a review of these condensed consolidated interim financial statements in accordance with standards established by the American Institute of Certified Public Accountants. 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.
Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications had no effect on the Company’s financial position, results of operations or cash flows.
Recently Issued Accounting Pronouncements
In June 2001, the FASB approved for issuance Statement of Financial Accounting Standards (SFAS) 143, “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived asset, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003. The impact on the financial statements of adopting SFAS 143 is disclosed in Note 12, “Adoption of SFAS 143, Accounting for Asset Retirement Obligations,” to the financial statements.
In December 2002, the FASB issued SFAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The Company is evaluating whether to adopt the recognition provisions of SFAS 123, as amended by SFAS 148. The adoption of the recognition provisions would impact the Company’s financial position and results of operations. See Note 1, “Stock Based Compensation,” to the financial statements.
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In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities — An Interpretation of Accounting Research Bulletin (ARB) 51” (FIN 46 or Interpretation). FIN 46 is an interpretation of ARB 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. However, on October 8, 2003, the FASB decided to grant a broader deferral of the implementation of FIN 46. Pursuant to this deferral, public companies must complete their evaluations of VIEs that existed prior to February 1, 2003, and the consolidation of those for which they are the primary beneficiary for financial statements issued for the first period ending after December 15, 2003. For calendar year companies, consolidation of previously existing VIEs will be required in their December 31, 2003 financial statements.
There was only one entity that could potentially be a VIE. The Company had a one percent general partner interest in a partnership which held an interest in the Kurten field. However, pursuant to the partnership agreement, the limited partner elected to liquidate the partnership; the liquidation was effective July 31, 2003. See Note 11 for additional information related to the partnership.
In April 2003 the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 30, 2003 (with a few exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 did not have an impact on the Company’s condensed consolidated financial statements.
In May 2003 the FASB issued SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. This Statement was developed in response to concerns expressed by preparers, auditors, regulators, investors, and other users of financial statements about issuers’ classification in the statement of financial position of certain financial instruments that have characteristics of both liabilities and equity but that have been presented either entirely as equity or between the liabilities section and the equity section of the statement of financial position. This Statement also addresses questions about the classification of certain financial instruments that embody obligations to issue equity shares.
In accordance with SFAS 150, companies with consolidated entities that will terminate by a specified date, such as limited-life partnerships, will have to measure the liabilities for the other owners’ interests in those limited-life entities based on the fair values of the limited-life entities’ assets. Period-to-period changes in the liabilities are to be reported in the consolidated income statement as interest costs. As a result of SFAS 150, liability amounts and related interest costs may be significantly greater than the minority interests previously recognized. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this standard did not have a material impact on our results of operations, financial position or cash flows.
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The Company has been made aware of an issue regarding the application of provisions of SFAS 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets ( SFAS 142 ) to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities ( SFAS 69 ). Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.
If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its results of operations and financial condition would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. In addition, costs associated with mineral rights would continue to be characterized as oil and gas property costs in our required disclosures under SFAS 69.
At September 30, 2003, the Company had undeveloped leaseholds of approximately $39.1 million that would be classified on our balance sheet as intangible undeveloped leaseholds and developed leaseholds of approximately $354.1 million (net of accumulated depletion) that would be classified as intangible developed leaseholds if the Company applied the interpretation currently being discussed.
Restricted Cash
Restricted cash consists of $15.8 million of cash held in an escrow account related to the divestiture of certain non-strategic properties in the East. A gain of $7.0 million was recognized on the sale of these properties. The Company is currently evaluating the potential purchase of other properties. If additional properties are acquired the transaction may be treated as a tax-deferred exchange transaction. For a transaction to qualify for tax-deferred exchange treatment the Company has 45 days to identify a replacement property. Once a replacement property has been identified, the Company has an additional 135 days to close on the property.
Stock Based Compensation
SFAS 123, “Accounting for Stock-Based Compensation”, as amended by SFAS 148, “Accounting for Stock-Based Compensation
— Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion 25, to measure compensation cost for its stock option plans. However, the Company is evaluating the adoption of the recognition provisions of SFAS 123, as amended by SFAS 148.
The following table illustrates the effect on Net Income and Earnings Per Share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation.
THREE MONTHS ENDED SEPTEMBER 30, | NINE MONTHS ENDED SEPTEMBER 30, | |||||||||||||||
(In Thousands, Except Per Share Amounts) | 2003 | 2002 | 2003 | 2002 | ||||||||||||
Net Income, as reported | $ | 22,668 | $ | 6,125 | $ | 1,349 | $ | 7,449 | ||||||||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax | (479 | ) | (464 | ) | (1,473 | ) | (1,410 | ) | ||||||||
Pro forma net income (loss) | $ | 22,189 | $ | 5,661 | $ | (124 | ) | $ | 6,039 | |||||||
Earnings per share: | ||||||||||||||||
Basic - as reported | $ | 0.70 | $ | 0.19 | $ | 0.04 | $ | 0.23 | ||||||||
Basic - pro forma | $ | 0.69 | $ | 0.18 | $ | — | $ | 0.19 | ||||||||
Diluted - as reported | $ | 0.70 | $ | 0.19 | $ | 0.04 | $ | 0.23 | ||||||||
Diluted - pro forma | $ | 0.68 | $ | 0.18 | $ | — | $ | 0.19 |
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The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.
THREE MONTHS ENDED SEPTEMBER 30, | NINE MONTHS ENDED SEPTEMBER 30, | |||||||||||||
(In Thousands, Except Per Share Amounts) | 2003 | 2002 | 2003 | 2002 | ||||||||||
Compensation Expense in Net Income, as reported(1) | $ | 238 | $ | 681 | $ | 763 | $ | 3,354 | ||||||
Weighted Average Value per Option Granted | ||||||||||||||
During the Period(2) | $ | — | $ | — | $ | 6.77 | $ | 6.23 | ||||||
Assumptions(3) | ||||||||||||||
Stock Price Volatility | — | — | 35.3 | % | 35.8 | % | ||||||||
Risk Free Rate of Return | — | — | 2.5 | % | 3.9 | % | ||||||||
Dividend Rate (per year) | $ | — | $ | — | $ | 0.16 | $ | 0.16 | ||||||
Expected Term (in years) | — | — | 4 | 4 |
(1) | Compensation expense is defined as expense related to the vesting of stock grants, net of tax. |
(2) | Calculated using the Black Sholes fair value based method. |
(3) | There were no stock options issued in the third quarter of 2003 and 2002. |
The fair value of stock options included in the pro forma results for each of the periods presented is not necessarily indicative of future effects on Net Income and Earnings Per Share.
2. | PROPERTIES AND EQUIPMENT |
Properties and equipment are comprised of the following:
SEPTEMBER 30, 2003 | DECEMBER 31, 2002 | |||||||
(In Thousands) | ||||||||
Unproved Oil and Gas Properties | $ | 86,072 | $ | 76,959 | ||||
Proved Oil and Gas Properties | 1,526,872 | 1,459,240 | ||||||
Gathering and Pipeline Systems | 141,551 | 137,137 | ||||||
Land, Building and Improvements | 4,884 | 4,884 | ||||||
Other | 30,781 | 29,457 | ||||||
1,790,160 | 1,707,677 | |||||||
Accumulated Depreciation, Depletion and Amortization | (908,438 | ) | (735,923 | ) | ||||
$ | 881,722 | $ | 971,754 | |||||
Prior to the adoption of SFAS 143 on January 1, 2003, future estimated plug and abandonment costs were accrued over the productive life of certain oil and gas properties when the residual value of well equipment was not sufficient to cover the plug and abandonment liability. The accrued liability for plug and abandonment costs was included in Accumulated Depreciation, Depletion and Amortization.
Total future plug and abandonment costs of $17.1 million and $1.1 million, recorded at December 31, 2002, have been reclassified from Accumulated Depreciation, Depletion and Amortization and Other Accrued Liabilities, respectively, to Other Long-Term Liabilities due to the adoption of SFAS 143 (see Note 12). These reclassifications were made to conform to the current period presentation.
In the current quarter the Company recorded a pre-tax non-cash impairment charge of $5.9 million related to a field in the East which had capitalized costs that exceeded the future undiscounted cash flows. See Note 11 for information regarding the impairment on the Kurten Field.
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3. | ADDITIONAL BALANCE SHEET INFORMATION |
Certain balance sheet amounts are comprised of the following:
SEPTEMBER 30, 2003 | DECEMBER 31, 2002 | |||||||
(In Thousands) | ||||||||
Accounts Receivable | ||||||||
Trade Accounts | $ | 75,063 | $ | 65,796 | ||||
Joint Interest Accounts | 6,238 | 6,601 | ||||||
Current Income Tax Receivable | 2,384 | 2,479 | ||||||
Other Accounts | 390 | 619 | ||||||
84,075 | 75,495 | |||||||
Allowance for Doubtful Accounts | (5,407 | ) | (5,467 | ) | ||||
$ | 78,668 | $ | 70,028 | |||||
Other Current Assets | ||||||||
Commodity Hedging Contracts - SFAS 133 | $ | 2,219 | $ | 634 | ||||
Drilling Advances | 2,219 | 558 | ||||||
Prepaid Balances | 5,466 | 2,131 | ||||||
Other Accounts | 830 | 1,957 | ||||||
$ | 10,734 | $ | 5,280 | |||||
Accounts Payable | ||||||||
Trade Accounts | $ | 23,970 | $ | 13,317 | ||||
Natural Gas Purchases | 9,540 | 6,058 | ||||||
Royalty and Other Owners | 26,899 | 20,254 | ||||||
Capital Costs | 13,190 | 13,900 | ||||||
Taxes Other Than Income | 2,831 | 3,076 | ||||||
Drilling Advances | 5,541 | 7,254 | ||||||
Wellhead Gas Imbalances | 2,475 | 2,817 | ||||||
Other Accounts | 6,935 | 6,902 | ||||||
$ | 91,381 | $ | 73,578 | |||||
Accrued Liabilities | ||||||||
Employee Benefits | $ | 6,989 | $ | 8,751 | ||||
Taxes Other Than Income | 14,408 | 9,887 | ||||||
Interest Payable | 5,093 | 7,076 | ||||||
Commodity Hedging Contracts - SFAS 133 | 16,857 | 20,680 | ||||||
Other Accounts | 14,059 | 1,918 | ||||||
$ | 57,406 | $ | 48,312 | |||||
Other Liabilities | ||||||||
Postretirement Benefits Other Than Pension | $ | 2,024 | $ | 1,843 | ||||
Accrued Pension Cost | 7,647 | 8,486 | ||||||
Commodity Hedging Contracts - FAS 133 | 2,957 | — | ||||||
Accrued Plugging and Abandonment Liability | 36,343 | 18,151 | ||||||
Taxes Other Than Income and Other | 6,366 | 5,654 | ||||||
$ | 55,337 | $ | 34,134 | |||||
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4. | LONG-TERM DEBT |
At September 30, 2003, the Company had $15 million outstanding under its credit facility, which provides for an available credit line of $250 million. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the bank’s petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. The revolving term under this credit facility presently ends in October 2006 and is subject to renewal. At September 30, 2003, the Company had $235 million of credit available on the revolving credit facility.
In addition to the credit facility, the Company has the following debt outstanding:
• | $100 million of 12-year 7.19% Notes to be repaid in five annual installments of $20 million beginning in November 2005 |
• | $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 |
5. | EARNINGS PER SHARE |
Basic earnings per common share (EPS) is computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated using the treasury stock method except that the denominator is increased to reflect the potential dilution that could occur if outstanding stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.
The following is a calculation of basic and diluted weighted average shares outstanding for the three and nine months ended September 30, 2003 and 2002:
THREE MONTHS ENDED SEPTEMBER 30, | NINE MONTHS ENDED SEPTEMBER 30, | |||||||
2003 | 2002 | 2003 | 2002 | |||||
Shares - basic | 32,179,445 | 31,793,342 | 31,999,999 | 31,712,145 | ||||
Dilution effect of stock options and awards at end of period | 255,786 | 342,675 | 238,207 | 367,471 | ||||
Shares - diluted | 32,435,231 | 32,136,017 | 32,238,206 | 32,079,616 | ||||
Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect | 998,711 | 1,231,132 | 1,027,110 | 1,206,336 | ||||
6. | ENVIRONMENTAL LIABILITY |
The EPA notified the Company in February 2000 of its potential liability for waste material disposed of at the Casmalia Superfund Site (“Site”), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1992. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for disposal of approximately 4.5 billion pounds of waste would be expected to pay the clean-up costs, which are estimated by the EPA to be $271.9 million.
A group of potentially responsible parties, including the Company, formed a group, called the Casmalia Negotiating Committee (“CNC”). The CNC had extensive settlement discussions with the EPA and entered into a consent decree requiring the CNC to pay approximately $27 million toward Site clean up in return for a release from liability. On January 30, 2002, the Company placed $1,283,283 in an
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escrow account, representing its volumetric share of the CNC/United States settlement. The consent decree was approved by the court on August 14, 2003 and the funds in the escrow account were paid to the government on September 8, 2003. The settlement has resolved all federal claims against the Company for response costs and releases the Company from all response costs related to the Site, except for future claims against the Company for natural resource damage, unknown conditions, transshipment risks and claims by third parties. Most of the CNC, including the Company, have purchased insurance designed to protect the Company from these liabilities not covered by the consent decree.
The State of California, a third party, has asserted a claim against the CNC and other companies alleged to have waste at Casmalia for costs the State incurred and will incur at the site. The CNC has presented the claim to its insurer. The ultimate disposition of this claim is unknown. However, given the size of the State’s claim and the number of parties allegedly responsible, the Company’s share of this claim is not expected to be material.
With the entry of the consent decree and the purchase of the insurance, any potential material claims against the Company related to Casmalia have been resolved and the Company does not plan to report on this Site in future disclosures.
7. | COMMITMENTS AND CONTINGENCIES |
Wyoming Royalty Litigation
In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs have requested class certification under the Wyoming Rules of Civil Procedure and allege that the Company has improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claims that the Company has failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. Settlement discussions continue between the parties.
In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification.
Although management believes that a number of the Company’s defenses are supported by Wyoming case law, two letter decisions handed down by state district court judges in other cases do not support certain of the defenses. The decisions have not been reduced to formal orders and it is not known what effect, if any, the decisions will have on the pending cases. In addition, in 2000 a district court judge’s decision supported the defenses of the Company, and that decision was recently orally confirmed by another state district court judge. Accordingly, there is a split of authority concerning the interpretation of the reporting penalty provisions of the Wyoming Royalty Payment Act, which will need to be resolved by the Wyoming Supreme Court.
In the Company’s federal case, the judge agreed to certify two questions of state law for decision by the Wyoming State Supreme Court. The Wyoming State Supreme Court has agreed to decide both questions, and these decisions should dispose of important issues in these cases. The federal judge refused, however, to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner check stubs that had been decided adversely to the Company’s position in the state district court letter decision. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon the plaintiffs expert witness report filed in March 2003, the plaintiffs are now claiming $21 million in total damages which can be broken down into $15.7 million for alleged violations of the check stub reporting statute and the remainder for all other damages. In the opinion of our outside counsel,
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Brown, Drew & Massey, LLP the likelihood of the plaintiffs recovering the stated damages for violation of the check stub reporting statute is remote.
The Company is vigorously defending both cases. The Company has a reserve that management believes is adequate to provide for these potential liabilities based on its estimate of the probable outcome of these matters. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact our financial position.
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 under the West Virginia Rules of Civil Procedure and allege that the Company failed to pay royalty based upon the wholesale market value of the gas produced, that the Company has taken improper deductions from the royalty and have failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty. The plaintiffs have also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia in the 1995 Columbia bankruptcy proceeding.
The Company had removed the lawsuit to federal court; however, in February 2003, we received an order remanding the lawsuit back to state court. Discovery and pleadings necessary to place the class certification issue before the court have been ongoing. The class certification hearing was held on October 20 but the court has not yet ruled on the plaintiff’s motion for class certification; dispositive motions to be filed by December 1; and trial to be held March 29, 2004. Based on the current status of discovery, the dispositive motion and trial dates are likely to be continued to a later date.
The investigation into this claim continues and it is in the discovery phase. The Company is vigorously defending the case. The Company has reserves it believes are adequate to provide for these potential liabilities based on its estimate of the probable outcome of this matter. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact the Company’s financial position.
Texas Title Litigation
On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. The plaintiffs allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and the Company subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in the surface and minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. The trial date of May 19, 2003 has been cancelled and a new trial date has not been set. The Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title and since the Company acquired its lease is approximately $12 million. The carrying value of this property is approximately $35 million. Co-defendants Shell Oil Company and Shell Western E&P have filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The Company was in the process of joining in that motion, when the plaintiffs’ attorneys asked permission from the Court to withdraw from the representation. The Court granted that request, and new attorneys for some, but not all of the plaintiffs have recently entered the case. We expect that the motion for summary judgment will be reset for hearing in the next several months, at which time the Company will join in the motion. Although the investigation into this claim has just begun, the Company intends to vigorously defend the case. Management cannot currently determine the likelihood or range of any potential outcome.
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8. | DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY |
The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. At September 30, 2003, the Company had 31 cash flow hedges open: 10 natural gas price collar arrangements and 21 natural gas price swap arrangements. Additionally, the Company had five crude oil financial instruments and one natural gas financial instrument open at September 30, 2003, that did not qualify for hedge accounting under SFAS 133. At September 30, 2003, a $16.2 million ($10.0 million net of tax) unrealized loss was recorded to Other Comprehensive Income, along with a $19.8 million derivative liability and a $2.4 million derivative receivable. The change in derivative fair value for the current and prior periods have been included as a component of Natural Gas Production and Crude Oil and Condensate revenue, as appropriate. This classification is a modification of prior period disclosures that segregated the ineffective portion of cash flow hedges and the mark-to-market value changes on instruments that do not qualify for hedge accounting as the Change in Derivative Fair Value on the Statement of Operations.
Unrealized income related to the change in fair value of derivative instruments of $1.2 million ($0.7 million for gas and $0.5 million for oil) is reflected in the respective Net Operating Revenues line item for the three-month period ending September 30, 2003. For the nine-month period ending September 30, 2003 an unrealized charge of $0.3 million is reflected in natural gas production revenue and unrealized income of $0.3 million is reflected in crude oil and condensate revenue. For the nine-month and three-month periods ending September 30, 2003, the company has reflected realized charges of $48.3 million ($45.4 million for gas and $2.9 million for oil) and $8.6 million ($7.9 million for gas and $0.7 million for oil), respectively, in the respective Net Operating Revenue line items.
Assuming no change in commodity prices, after September 30, 2003 the Company would reclassify to earnings, over the next 12 months, $8.5 million in after-tax expenditures associated with commodity derivatives out of the net after-tax $10.0 million recorded in other comprehensive income at September 30, 2003.
From time to time the Company enters into natural gas and crude oil swap arrangements that do not qualify for hedge accounting in accordance with SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At September 30, 2003, the Company had five open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of $0.4 million and $0.2 million recognized in Operating Revenue, respectively.
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9. | COMPREHENSIVE INCOME |
Comprehensive Income includes Net Income and certain items recorded directly to Stockholders’ Equity and classified as Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for the nine-month periods ended September 30, 2003 and 2002:
NINE MONTHS ENDED | ||||||||||||||||
SEPTEMBER 30, 2003 | SEPTEMBER 30, 2002 | |||||||||||||||
(In Thousands) | ||||||||||||||||
Accumulated Other Comprehensive Income (Loss) - Beginning of Period | $ | (12,939 | ) | $ | 835 | |||||||||||
Net Income | $ | 1,349 | $ | 7,449 | ||||||||||||
Other Comprehensive Loss | ||||||||||||||||
Reclassification Adjustment for Settled Contracts | 44,479 | 4,607 | ||||||||||||||
Changes in Fair Value of | ||||||||||||||||
Hedge Positions | (41,911 | ) | (7,535 | ) | ||||||||||||
Deferred Income Tax | (1,005 | ) | 1,126 | |||||||||||||
Total Other Comprehensive Income (Loss) | $ | 1,563 | $ | 1,563 | $ | (1,802 | ) | $ | (1,802 | ) | ||||||
Comprehensive Income | $ | 2,912 | $ | 5,647 | ||||||||||||
Accumulated Other Comprehensive Loss - End of Period | $ | (11,376 | ) | $ | (967 | ) | ||||||||||
10. | RETIREMENT OF EXECUTIVE OFFICER |
In May 2002, Ray Seegmiller retired as the Company’s Chairman and Chief Executive Officer. The Company recorded a charge of approximately $3.6 million in the second quarter of 2002 for expenses related to his retirement. The costs include a lump sum cash payment of $0.9 million in recognition of Mr. Seegmiller’s employment agreement, his contributions to the Company and in lieu of a 2002 long-term incentive award. Another $1.0 million was expensed as part of his supplemental executive retirement plan benefits. Mr. Seegmiller’s previously awarded stock grants and options vested upon retirement, resulting in compensation expense of approximately $1.7 million.
11. | ACQUISITION OF CODY COMPANY |
In August 2001, the Company acquired the stock of Cody Company, the parent of Cody Energy LLC (“Cody acquisition”) for $231.2 million, consisting of $181.3 million cash and 1,999,993 shares of common stock valued at $49.9 million. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region. The acquisition was accounted for using the purchase method of accounting. As such, the Company reflected the assets and liabilities acquired at fair value in the Company’s balance sheet effective August 1, 2001, and the results of operations of Cody Company beginning August 1, 2001. The Company recorded a purchase price of approximately $315.6 million, which was allocated to specific assets and liabilities based on certain estimates of fair values, resulting in approximately $302.4 million allocated to property and $13.2 million allocated to working capital items. The remaining $78.0 million of the recorded purchase price reflected a non-cash item pertaining to the deferred income taxes attributable to the differences between the tax basis and the fair value of the acquired oil and gas properties, and acquisition related fees and costs of $6.4 million.
As part of the Cody acquisition, the Company acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. The Company’s interest in Kurten
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was approximately 25%, including a one percent interest in the partnership. Under the partnership agreement, the Company had the right to a reversionary working interest that would bring its ultimate interest to 50% upon the limited partner reaching payout. Under the partnership agreement, the limited partner had the sole option to trigger a liquidation of the partnership. Effective February 13, 2003, the Kurten partnership commenced liquidation at the limited partner’s election. In connection with the liquidation, an appraisal was obtained to allocate the interest in the partnership assets. Based on the receipt of the appraisal in February 2003, the Company did not receive the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field and the limited partners’ decision to proceed with the liquidation, the Company performed an impairment review that resulted in an after-tax charge of $54 million. This impairment charge is reflected in the first quarter of 2003 as an operating expense but does not impact the Company’s cash flows. In addition, the Company recorded a downward reserve revision of approximately 16 Bcfe as a result of the loss of the reversionary interest. The partnership liquidation was effective July 31, 2003.
12. | ADOPTION OF SFAS 143, “ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS” |
Effective January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. The adoption of SFAS 143 resulted in (1) an increase of total liabilities because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset and (3) an increase in operating expense because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities will also be recorded for meter stations, pipelines, processing plants and compressors. At January 1, 2003, there are no assets legally restricted for purposes of settling asset retirement obligations. The Company recorded a net-of-tax cumulative effect of change in accounting principle loss in January 2003 of $6.8 million and recorded a retirement obligation of $35.2 million. There was no impact on the Company’s cash flows as a result of adopting SFAS 143. See Note 2 for additional information on plugging and abandonment costs.
Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement liabilities, settled liabilities, and revisions of estimated cash flows. Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense for the nine-month and three-month periods ended September 30, 2003 is $1.4 million and $0.3 million, respectively.
The following unaudited pro forma information has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002.
PERIOD ENDING SEPTEMBER 30, 2002 | ||||||
QUARTER | NINE MONTHS | |||||
(In Thousands) | ||||||
(Except Per Share Amounts) | ||||||
Net Income | $ | 5,833 | $ | 6,592 | ||
Per Share - Basic | $ | 0.18 | $ | 0.21 | ||
Per Share - Diluted | $ | 0.18 | $ | 0.21 |
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Report of Independent Accountants
To the Board of Directors and Shareholders of
Cabot Oil & Gas Corporation:
We have reviewed the accompanying condensed consolidated balance sheet of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) as of September 30, 2003, and the related condensed consolidated statements of operations and cash flows for each of the three-month and nine-month periods ended September 30, 2003 and September 30, 2002. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. 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 generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2002, and the related consolidated statements of operations, stockholders’ equity, and of cash flows for the year then ended (not presented herein), and in our report dated February 17, 2003 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
October 29, 2003
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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following review of operations for the third quarter and first nine months of 2003 and 2002 should be read along with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in the Cabot Oil & Gas Form 10-K for the year ended December 31, 2002.
Overview
In the first nine months of 2003, we produced 67.1 Bcfe compared to production of 68.7 Bcfe for the comparable period of the prior year. Natural gas production was 53.7 Bcf and oil production was 2,193 Mbbls. Natural gas production in the current period decreased slightly from the same period in 2002, which is when we experienced the highest annual production levels in our history. The decline in our natural gas production is essentially attributable to the size and timing of the Gulf Coast and West regions drilling program, along with the natural decline of existing production.
In the nine months ended September 30, 2003, we drilled123 gross wells (106 development and 17 exploratory wells) with a success rate of 90% compared to 85 gross wells (79 development and six exploratory wells) with a success rate of 93% for the comparable period of the prior year. For the full year, we plan to drill 185 gross wells compared to 108 gross wells in 2002.
We had net income of $1.3 million, or $0.04 per share, for the nine months ended September 30, 2003 despite impairment charges of $93.8 million and the $6.8 million impact of a cumulative effect of accounting change. The pre-tax non-cash impairment charges consist of $87.9 million related to the liquidation of a limited partnership interest in the Kurten field and $5.9 million related to a field in the East. The cumulative effect of accounting change is related to a $6.8 million charge from the adoption of SFAS 143. These charges were partially offset by a pre-tax gain of $7.6 million recognized on the sale of oil and gas properties.
In the first nine months of 2003, commodity prices were unusually high, and our financial results reflected their impact. Our realized natural gas price was 64% higher and our realized crude oil price was 26% higher than in 2002. 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, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGLs and crude oil prices, and therefore, cannot accurately predict revenues.
In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. In 2003, excluding acquisitions, we expect to spend approximately $172.0 million in capital and exploration expenditures. For the nine months ended September 30, 2003, $127.7 million of capital and exploration expenditures have been incurred.
We remain focused on our strategies of concentrating our capital spending program on projects balancing acceptable risk with the strongest economics. As in the past, we will use a portion of the cash flow from our long-lived Eastern and Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast and Rocky Mountain areas. In addition, we have begun to expand our interest in the offshore Gulf of Mexico and Canada. We believe these strategies are appropriate in the current industry environment and should enable Cabot Oil & Gas to add shareholder value over the long term.
The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See Forward-Looking Information on page 29.
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Financial Condition
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and gas properties and asset-based borrowings supported by our oil and gas reserves. The level of earnings and cash flows depend on many factors, including the price of crude oil and natural gas and our ability to control and reduce costs. Demand for crude oil and natural gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. However, demand and prices moved higher, strengthening from the first half of 2002 into the summer and continued to strengthen through 2003. Prices in the first nine months of 2003 were the result of a higher demand associated with colder than normal winter temperatures, combined with higher storage injection demand in the second and third quarters.
Our primary source of cash during the first nine months of 2003 was from funds generated from operations. Cash was primarily used to fund exploration and development expenditures, reduce debt and pay dividends. We had a net cash inflow of $1.8 million for the nine months ended September 30, 2003. See below for additional discussion and analysis of cash flow.
Nine-Months Ended September 30, | |||||||||
2003 | 2002 | Variance | |||||||
Cash Flows Provided by Operating Activities | 205,706 | 108,281 | 97,425 | ||||||
Cash Flows Used by Investing Activities | (126,017 | ) | (110,661 | ) | (15,356 | ) | |||
Cash Flows (Used) Provided by Financing Activities | (77,904 | ) | 1,342 | (79,246 | ) | ||||
Net Increase (Decrease) in Cash and Cash Equivalents | 1,785 | (1,038 | ) | 2,823 | |||||
Cash flow discussion and analysis:
• | Cash flows from operating activities increased due to higher commodity prices partially offset by lower natural gas |
production sales volumes.
• | Cash flows used in investing activities increased due to an increase in exploration expense. |
• | Cash flows used in financing activities increased due to additional debt repayments. |
The available credit line under our revolving credit facility, currently $250 million, is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the bank’s petroleum engineer) and other assets. At September 30, 2003, excess capacity totaled $235 million of the total available credit facility. The revolving term of the credit facility ends in October 2006. 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 acquisitions.
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Capitalization
Our capitalization information is as follows:
SEPTEMBER 30, 2003 | DECEMBER 31, 2002 | |||||||
(In millions) | ||||||||
Debt | $ | 285.0 | $ | 365.0 | ||||
Stockholders’ Equity(1) | 356.0 | 350.7 | ||||||
Total Capitalization | $ | 641.0 | $ | 715.7 | ||||
Debt to Capitalization | 44 | % | 51 | % |
(1) | Includes common stock, net of treasury stock. |
During the first nine months of 2003, we paid dividends of $3.8 million on our Common Stock. A regular dividend of $0.04 per share of Common Stock has been declared for each quarter since we became a public company.
Capital and Exploration Expenditures
On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations, and budget such capital expenditures while considering projected cash flows for the year.
The following table presents major components of capital and exploration expenditures:
NINE MONTHS ENDED SEPTEMBER 30, | ||||||
2003 | 2002 | |||||
(In Millions) | ||||||
Capital Expenditure | ||||||
Drilling and Facilities | $ | 65.2 | $ | 55.6 | ||
Leasehold Acquisitions | 12.3 | 2.0 | ||||
Pipeline and Gathering | 4.5 | 2.4 | ||||
Other | 1.5 | 0.8 | ||||
83.5 | 60.8 | |||||
Proved Property Acquisitions | 1.1 | 2.1 | ||||
Exploration Expense | 43.1 | 27.7 | ||||
Total | $ | 127.7 | $ | 90.6 | ||
We plan to drill 185 gross wells in 2003 compared with 108 gross wells drilled in 2002. This 2003 drilling program includes approximately $172.0 million in total capital and exploration expenditures, up from $126.3 million in 2002. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.
Non-GAAP Financial Measures
From time to time management discloses Discretionary Cash Flow and Net Income and Earnings Per Share, excluding selected items. These non-GAAP financial measure calculations may be presented in earnings releases of the Company, furnished in Form 8-K to the Securities and Exchange Commission, along with reconciliations to the most comparable GAAP financial measure for the period.
Discretionary Cash Flow is defined as Net Income plus non-cash charges and Exploration Expense. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionary Cash Flow is presented based on management’s belief that this non-GAAP measure is helpful to investors when comparing our cash flow with the cash flow of other companies that use the Full Cost method of accounting for
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oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, as defined by GAAP, or as a measure of liquidity, or an alternative to Net Income.
Net Income excluding selected items and Earnings Per Share excluding selected items is presented based on management’s belief that these non-GAAP measures enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a beneficial comparison to similarly adjusted measurements of prior periods. Net Income and Earnings Per Share excluding selected items is not a measure of financial performance under GAAP and should not be considered as an alternative to Net Income and Earnings Per Share, as defined by GAAP.
Critical Accounting Policies and Estimates
The Company’s discussion and analysis of its financial condition and results of operation are based upon condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, for further discussion.
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Results of Operations
Third Quarters of 2003 and 2002 Compared
Net Income and Operating Revenue
We reported net income in the third quarter of 2003 of $22.7 million, or $0.70 per share. During the corresponding quarter of 2002, we reported net income of $6.1 million, or $0.19 per share. Operating income increased by $28.5 million compared to the comparable period of the prior year. The increase in net income and operating income was substantially due to an increase in our realized natural gas and crude oil prices.
Natural Gas Production Revenues
The average total company realized natural gas production sales price, including the impact of derivative instruments, was $4.53 per Mcf. Due to derivative instruments this price was reduced by $0.42 per Mcf. The following table excludes the impact of the change in derivative fair value of $0.7 million and $0.2 million for the three months ended September 30, 2003 and 2002, respectively. These amounts have been included in the Natural Gas Production revenues line item on the Statement of Operations.
THREE MONTHS ENDED SEPTEMBER 30, | Variance | |||||||||||||
2003 | 2002 | Amount | Percent | |||||||||||
Natural Gas Production (Bcf) | ||||||||||||||
Gulf Coast | 7.7 | 8.0 | (0.3 | ) | (4 | %) | ||||||||
West | 5.9 | 6.2 | (0.3 | ) | (5 | %) | ||||||||
East | 4.9 | 4.5 | 0.4 | 9 | % | |||||||||
Total Company | 18.5 | 18.7 | (0.2 | ) | (1 | %) | ||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||
Gulf Coast | $ | 4.68 | $ | 3.21 | $ | 1.47 | 46 | % | ||||||
West | $ | 3.75 | $ | 2.00 | $ | 1.75 | 88 | % | ||||||
East | $ | 5.24 | $ | 3.04 | $ | 2.20 | 72 | % | ||||||
Total Company | $ | 4.53 | $ | 2.77 | $ | 1.76 | 64 | % | ||||||
Natural Gas Production Revenue(in millions) | ||||||||||||||
Gulf Coast | $ | 36.1 | $ | 25.8 | $ | 10.3 | 40 | % | ||||||
West | 22.0 | 12.4 | 9.6 | 77 | % | |||||||||
East | 25.8 | 13.7 | 12.1 | 88 | % | |||||||||
Total Company | $ | 83.9 | $ | 51.9 | $ | 32.0 | 62 | % | ||||||
Price Variance Impact on Natural Gas Production Revenue | ||||||||||||||
Gulf Coast | $ | 11.6 | ||||||||||||
West | 10.2 | |||||||||||||
East | 10.8 | |||||||||||||
Total Company | $ | 32.6 | ||||||||||||
Volume Variance Impact on Natural Gas Production Revenue | ||||||||||||||
Gulf Coast | $ | (1.1 | ) | |||||||||||
West | (0.7 | ) | ||||||||||||
East | 1.2 | |||||||||||||
Total Company | $ | (0.6 | ) | |||||||||||
The decline in natural gas production is due substantially to the size and timing of Gulf Coast and West drilling program, along with the natural decline of existing production. The increase in the realized natural gas price combined with the decline in production resulted in a net revenue increase of $32.0 million.
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Brokered Natural Gas Revenue and Cost
THREE MONTHS ENDED SEPTEMBER 30, | Variance | |||||||||||
2003 | 2002 | Amount | Percent | |||||||||
Brokered Natural Gas Revenues | $ | 18.7 | $ | 10.8 | ||||||||
Brokered Natural Gas Cost | 16.6 | 9.8 | ||||||||||
Brokered Natural Gas Margin | $ | 2.1 | $ | 1.0 | $ | 1.1 | 110 | % | ||||
Brokered Natural Gas Volume (Bcf) | 6.1 | 5.7 | ||||||||||
Sales Price Variance Impact on Revenue | $ | 7.0 | ||||||||||
Volume Variance Impact on Revenue | 0.9 | |||||||||||
$ | 7.9 | |||||||||||
Purchase Price Variance Impact on Purchases | $ | 6.0 | ||||||||||
Volume Variance Impact on Purchases | 0.8 | |||||||||||
$ | 6.8 | |||||||||||
Crude Oil and Condensate Revenues
The average total company realized crude oil sales price, including the impact of derivative instruments, was $28.40 per Bbl for the third quarter of 2003. Due to derivative instruments this price was reduced by $1.00 per Bbl. The following table excludes the impact of the change in derivative fair value of $0.5 million and $1.6 million for the three months ended September 30, 2003 and 2002, respectively. These amounts have been included in the Crude Oil and Condensate revenues line item on the Statement of Operations.
THREE MONTHS ENDED SEPTEMBER 30, | Variance | |||||||||||||
2003 | 2002 | Amount | Percent | |||||||||||
Crude Oil Production (Mbbl) | ||||||||||||||
Gulf Coast | 683 | 697 | (14 | ) | (2 | %) | ||||||||
West | 46 | 61 | (15 | ) | (25 | %) | ||||||||
East | 7 | 8 | (1 | ) | (13 | %) | ||||||||
Total Company | 736 | 766 | (30 | ) | (4 | %) | ||||||||
Crude Oil Sales Price ($/Bbl) | ||||||||||||||
Gulf Coast | $ | 28.32 | $ | 24.76 | $ | 3.56 | 14 | % | ||||||
West | $ | 29.75 | $ | 27.29 | $ | 2.46 | 9 | % | ||||||
East | $ | 28.02 | $ | 25.90 | $ | 2.12 | 8 | % | ||||||
Total Company | $ | 28.40 | $ | 24.97 | $ | 3.43 | 14 | % | ||||||
Crude Oil Revenue(in millions) | ||||||||||||||
Gulf Coast | $ | 19.3 | $ | 17.2 | $ | 2.1 | 12 | % | ||||||
West | 1.4 | 1.7 | (0.3 | ) | (18 | %) | ||||||||
East | 0.2 | 0.2 | 0.0 | 0 | % | |||||||||
Total Company | $ | 20.9 | $ | 19.1 | $ | 1.8 | 9 | % | ||||||
Price Variance Impact on Crude Oil Revenue | ||||||||||||||
Gulf Coast | $ | 2.5 | ||||||||||||
West | 0.1 | |||||||||||||
East | 0.0 | |||||||||||||
Total Company | $ | 2.6 | ||||||||||||
Volume Variance Impact on Crude Oil Revenue | ||||||||||||||
Gulf Coast | $ | (0.4 | ) | |||||||||||
West | (0.4 | ) | ||||||||||||
East | 0.0 | |||||||||||||
Total Company | $ | (0.8 | ) | |||||||||||
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The decline in crude oil production is due substantially to the size and timing of the Gulf Coast drilling program, along with the natural decline of existing production. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $1.8 million.
Other Net Operating Revenues
Other operating revenues decreased $1.2 million. This change was a result of a decline in natural gas liquid revenue combined with the expiration of section 29 tax credits at December 31, 2002.
Operating Expenses
Total costs and expenses from operations increased $18.6 million in the third quarter of 2003 compared to the same quarter of 2002. The primary reasons for this fluctuation are as follows:
• | Brokered natural gas cost increased $6.8 million. For additional information related to this increase see the analysis performed for Brokered Natural Gas Revenue and Cost. |
• | Exploration expense increased $4.2 million as a result of higher dry hole expense in 2003. During the third quarter of 2003, we drilled 10 exploratory wells compared to 1 in the corresponding period of 2002. |
• | Impairment of natural gas producing properties expense increased $5.9 million. |
• | Taxes other than income increased $4 million as a result of higher commodity prices realized this quarter. |
Interest Expense
Interest expense increased $0.7 million. This variance is the combination of a decrease due to a lower average level of outstanding debt during the third quarter of 2003 when compared to the corresponding period of the prior year and a decline in interest rates on the revolving credit facility, offset by a charge related to the adoption of SFAS 150.
Income Tax Expense
Income tax expense increased $11.3 million due to a comparable increase in our pre-tax net income.
Nine Months of 2003 and 2002 Compared
Net Income and Operating Revenue
We reported net income for the nine months ended September 30, 2003 of $1.3 million, or $0.04 per share. During the corresponding period of the prior year, we reported net income of $7.5 million, or $0.23 per share. The decrease in net income is due to impairment charges of $93.8 million and the impact of a cumulative effect of accounting change. The pre-tax non-cash impairment charges consist of an $87.9 million expenditure related to the liquidation of a limited partnership interest in the Kurten field and a $5.9 million expenditure related to a field in the East. These charges were partially offset by a pre-tax gain of $7.6 million recognized on the sale of oil and gas properties. The cumulative effect of accounting change is related to a $6.8 million charge from the adoption of SFAS 143. These amounts were substantially offset by the impact of an increase in our realized natural gas and crude oil prices. Operating income increased by $1.8 million compared to the comparable period of the prior year. The increase in operating income was due to an increase in our realized natural gas and crude oil prices, substantially offset by the impairment charges.
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Natural Gas Production Revenues
The average total company realized natural gas production sales price, including the impact of derivative instruments, was $4.53 per Mcf. Due to derivative instruments this price was reduced by $0.84 per Mcf. The following table excludes the impact of the change in derivative fair value of $(0.3) million and $(1.0) million for the nine months ended September 30, 2003 and 2002, respectively. These amounts have been included in the Natural Gas Production revenues line item on the Statement of Operations.
NINE MONTHS ENDED SEPTEMBER 30, | Variance | |||||||||||||
2003 | 2002 | Amount | Percent | |||||||||||
Natural Gas Production (Bcf) | ||||||||||||||
Gulf Coast | 21.8 | 23.2 | (1.4 | ) | (6 | %) | ||||||||
West | 18.0 | 19.0 | (1.0 | ) | (5 | %) | ||||||||
East | 13.9 | 13.5 | 0.4 | 3 | % | |||||||||
Total Company | 53.7 | 55.7 | (2.0 | ) | (4 | %) | ||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||
Gulf Coast | $ | 4.83 | $ | 3.07 | $ | 1.76 | 57 | % | ||||||
West | $ | 3.65 | $ | 2.18 | $ | 1.47 | 67 | % | ||||||
East | $ | 5.17 | $ | 3.07 | $ | 2.10 | 68 | % | ||||||
Total Company | $ | 4.53 | $ | 2.76 | $ | 1.77 | 64 | % | ||||||
Natural Gas Production Revenue(in millions) | ||||||||||||||
Gulf Coast | $ | 105.6 | $ | 71.0 | $ | 34.6 | 49 | % | ||||||
West | 65.6 | 41.4 | 24.2 | 58 | % | |||||||||
East | 72.0 | 41.3 | 30.7 | 74 | % | |||||||||
Total Company | $ | 243.2 | $ | 153.7 | $ | 89.5 | 58 | % | ||||||
Price Variance Impact on Natural Gas Production Revenue | ||||||||||||||
Gulf Coast | $ | 38.6 | ||||||||||||
West | 26.4 | |||||||||||||
East | 29.3 | |||||||||||||
Total Company | $ | 94.3 | ||||||||||||
Volume Variance Impact on Natural Gas Production Revenue | ||||||||||||||
Gulf Coast | $ | (4.1 | ) | |||||||||||
West | (2.2 | ) | ||||||||||||
East | 1.5 | |||||||||||||
Total Company | $ | (4.8 | ) | |||||||||||
The decline in natural gas production is due substantially to the size and timing of Gulf Coast and West drilling program, along with the natural decline of existing production. The increase in the realized natural gas price combined with the decline in production resulted in a net revenue increase of $89.5 million.
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Brokered Natural Gas Revenue and Cost
NINE MONTHS ENDED SEPTEMBER 30, | Variance | |||||||||||
2003 | 2002 | Amount | Percent | |||||||||
Brokered Natural Gas Revenues | $ | 74.0 | $ | 40.2 | ||||||||
Brokered Natural Gas Cost | 66.4 | 36.6 | ||||||||||
Brokered Natural Gas Margin | $ | 7.6 | $ | 3.6 | $ | 4.0 | 111 | % | ||||
Brokered Natural Gas Volume (Bcf) | 14.7 | 14.7 | ||||||||||
Sales Price Variance Impact on Revenue | $ | 33.7 | ||||||||||
Volume Variance Impact on Revenue | 0.1 | |||||||||||
$ | 33.8 | |||||||||||
Purchase Price Variance Impact on Purchases | $ | 29.7 | ||||||||||
Volume Variance Impact on Purchases | 0.1 | |||||||||||
$ | 29.8 | |||||||||||
Crude Oil and Condensate Revenues
The average total company realized crude oil sales price, including the impact of derivative instruments, was $29.53 per Bbl for the third quarter of 2003. Due to derivative instruments this price was reduced by $1.31 per Bbl. The following table excludes the impact of the change in derivative fair value of $0.3 million and $1.6 million for the nine months ended September 30, 2003 and 2002, respectively. These amounts have been included in the Crude Oil and Condensate revenues line item on the Statement of Operations.
NINE MONTHS ENDED SEPTEMBER 30, | Variance | |||||||||||||
2003 | 2002 | Amount | Percent | |||||||||||
Crude Oil Production (Mbbl) | ||||||||||||||
Gulf Coast | 2,027 | 1,963 | 64 | 3 | % | |||||||||
West | 146 | 164 | (18 | ) | (11 | %) | ||||||||
East | 20 | 24 | (4 | ) | (17 | %) | ||||||||
Total Company | 2,193 | 2,151 | 42 | 2 | % | |||||||||
Crude Oil Sales Price ($/Bbl) | ||||||||||||||
Gulf Coast | $ | 29.50 | $ | 23.27 | $ | 6.23 | 27 | % | ||||||
West | $ | 30.07 | $ | 24.71 | $ | 5.36 | 22 | % | ||||||
East | $ | 28.67 | $ | 21.34 | $ | 7.33 | 34 | % | ||||||
Total Company | $ | 29.53 | $ | 23.36 | $ | 6.17 | 26 | % | ||||||
Crude Oil Revenue(in millions) | ||||||||||||||
Gulf Coast | $ | 59.8 | $ | 45.6 | $ | 14.2 | 31 | % | ||||||
West | 4.4 | 4.1 | 0.3 | 7 | % | |||||||||
East | 0.6 | 0.5 | 0.1 | 20 | % | |||||||||
Total Company | $ | 64.8 | $ | 50.2 | $ | 14.6 | 29 | % | ||||||
Price Variance Impact on Crude Oil Revenue | ||||||||||||||
Gulf Coast | $ | 12.7 | ||||||||||||
West | 0.8 | |||||||||||||
East | 0.1 | |||||||||||||
Total Company | $ | 13.6 | ||||||||||||
Volume Variance Impact on Crude Oil Revenue | ||||||||||||||
Gulf Coast | $ | 1.5 | ||||||||||||
West | (0.4 | ) | ||||||||||||
East | (0.1 | ) | ||||||||||||
Total Company | $ | 1.0 | ||||||||||||
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The increase in crude oil production is due substantially to drilling success in the Gulf Coast drilling program. The increase in the realized crude oil price combined with the increase in production resulted in a net revenue increase of $14.6 million.
Other Net Operating Revenues
Other operating revenues increased $0.8 million. This change was a result of increased natural gas liquids revenue combined with an increase in transportation revenue.
Operating Expenses
Total costs and expenses from operations increased $143.5 million for the nine months ended September 30, 2003 compared to the comparable period of the prior year. The primary reasons for this fluctuation are as follows:
• | Brokered natural gas cost increased $29.8 million. For additional information related to this increase see the analysis performed for Brokered Natural Gas Revenue and Cost. |
• | Exploration expense increased $15.4 million primarily as a result of higher dry hole and seismic expense in 2003. |
• | Impairment of long-lived assets expense increased $92.7 million. These pre-tax non-cash impairment charges consist of an $87.9 million expenditure related to the liquidation of a limited partnership interest in the Kurten field and a $5.9 million expenditure related to a field in the East. |
• | Taxes other than income increased $9.3 million as a result of higher commodity prices realized this quarter. |
Interest Expense
Interest expense decreased $0.3 million as a result of a lower average level of outstanding debt during the nine months ended September 30, 2003 when compared to the corresponding period of the prior year and a decline in interest rates on the revolving credit facility, partially offset by a charge related to the adoption of SFAS 150.
Income Tax Expense
Income tax expense increased $1.4 million due to a comparable increase in our pre-tax net income.
Recently Issued Accounting Pronouncements
In June 2001, the FASB approved for issuance Statement of Financial Accounting Standards (SFAS) 143, “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived asset, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003. The impact on the financial statements of adopting SFAS 143 is disclosed in Note 12, “Adoption of SFAS 143, Accounting for Asset Retirement Obligations,” to the financial statements.
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In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002. We are evaluating the adoption of the recognition provisions of SFAS 123, as amended by SFAS 148. The adoption of the recognition provisions would impact our financial position and results of operations. See Note 13, “Stock Based Compensation,” to the financial statements.
In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities — An Interpretation of ARB No. 51” (FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. However, on October 8, 2003, the FASB decided to grant a broader deferral FIN 46. Pursuant to this deferral, public companies must complete their evaluations of VIEs that existed prior to February 1, 2003, and the consolidation of those for which they are the primary beneficiary for financial statements issued for the first period ending after December 15, 2003. For calendar year companies, consolidation of previously existing VIEs will be required in their December 31, 2003 financial statements.
There was only one entity that could potentially be a VIE. We had a one percent general partner interest in a partnership which held an interest in the Kurten field. However, pursuant to the partnership agreement, the limited partner elected to liquidate the partnership; the liquidation was effective July 31, 2003. See Note 11 for additional information related to this partnership.
In April 2003 the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 30, 2003 (with a few exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 did not have an impact on our condensed consolidated financial statements.
In May 2003 the FASB issued SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. This Statement was developed in response to concerns expressed by preparers, auditors, regulators, investors, and other users of financial statements about issuers’ classification in the statement of financial position of certain financial instruments that have characteristics of both liabilities and equity but that have been presented either entirely as equity or between the liabilities section and the equity section of the statement of financial position. This Statement also addresses questions about the classification of certain financial instruments that embody obligations to issue equity shares.
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In accordance with SFAS 150, companies with consolidated entities that will terminate by a specified date, such as limited-life partnerships, will have to measure the liabilities for the other owners’ interests in those limited-life entities based on the fair values of the limited-life entities’ assets. Period-to-period changes in the liabilities are to be reported in the consolidated income statement as interest costs. As a result of SFAS 150, liability amounts and related interest costs may be significantly greater than the minority interests previously recognized. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this standard did not have a material impact on our results of operations, financial position or cash flows.
We have been made aware of an issue regarding the application of provisions of SFAS 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets ( SFAS 142 ) to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, Cabot and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities ( SFAS 69 ). Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.
If it is ultimately determined that SFAS 142 requires us to reclassify costs associated with mineral rights from property and equipment to intangible assets, management currently believes that its results of operations and financial condition would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. In addition, costs associated with mineral rights would continue to be characterized as oil and gas property costs in our required disclosures under SFAS 69.
At September 30, 2003, we had undeveloped leaseholds of approximately $39.1 million that would be classified on our balance sheet as intangible undeveloped leaseholds and developed leaseholds of approximately $354.1 million (net of accumulated depletion) that would be classified as intangible developed leaseholds if we applied the interpretation currently being discussed.
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.
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ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Swaps and Options
Our hedging policy 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 against declines in oil and gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices. Please read the discussion below related to commodity price swaps and Note 8 of the Notes to the Interim Condensed Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.
Hedges on Production – Swaps
From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. Under our Revolving Credit Agreement, the aggregate level of commodity hedging must not exceed 80% of the anticipated future equivalent production during the period covered by the hedges. During the first nine months of 2003, natural gas price swaps covered 25,908 Mmcf, or 48% of our gas production, fixing the sales price of this gas at an average of $4.47 per Mcf.
At September 30, 2003, we had open natural gas price swap contracts covering our 2003 and 2004 production as follows:
Natural Gas Price Swaps | ||||||||
Contract Period | Volume in Mmcf | Weighted Average Contract Price | Unrealized Loss (In Thousands) | |||||
As of September 30, 2003 | ||||||||
Natural Gas Price Swaps on Production in: | ||||||||
Fourth Quarter 2003 | 8,898 | 4.54 | ||||||
Three Months Ended December 31, 2003 | 8,898 | $ | 4.54 | $ | 4,510 | |||
First Quarter 2004 | 4,218 | $ | 5.06 | |||||
Second Quarter 2004 | 3,348 | 4.65 | ||||||
Third Quarter 2004 | 3,384 | 4.65 | ||||||
Fourth Quarter 2004 | 3,384 | 4.65 | ||||||
Full Year 2004 | 14,334 | $ | 4.77 | $ | 8,005 |
From time to time the Company enters into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At September 30, 2003, the Company had five open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of $0.4 million and $0.2 million recognized in Operating Revenues, respectively.
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Hedges on Production – Options
Throughout 2002 and 2003, we believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our production through the use of natural gas and crude oil collars. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index falls below the floor price, the counterparty pays us.
During the first nine months of 2003, natural gas price collars covered 11,853 Mmcf, or 22% of our gas production, with a weighted average floor of $4.46 per Mcf and a weighted average ceiling of $5.40 per Mcf. Additionally, during the first nine months of 2003, we had crude oil price collars which covered 362 Mbbls, or 25% of our production, with a weighted average floor of $24.75 per bbl and a weighted average ceiling of $28.86 per bbl. These crude oil contracts expired in June 2003.
At September 30, 2003, we had open natural gas price collar contracts covering our 2003 and 2004 production as follows:
Natural Gas Price Collars | ||||||||
Contract Period | Volume in Mmcf | Weighted Average Ceiling / Floor | Unrealized Loss (In Thousands) | |||||
As of September 30, 2003 | ||||||||
Natural Gas Price Collars on Production in: | ||||||||
Fourth Quarter 2003 | 4,283 | $ | 5.42 / $4.46 | |||||
Three Months Ended December 31, 2003 | 4,283 | $ | 5.42 / $4.46 | $ | 1.0 | |||
First Quarter 2004 | 3,821 | $ | 5.42 / $4.45 | |||||
Second Quarter 2004 | 3,821 | $ | 5.42 / $4.45 | |||||
Third Quarter 2004 | 3,863 | $ | 5.42 / $4.45 | |||||
Fourth Quarter 2004 | 3,863 | $ | 5.42 / $4.45 | |||||
Full Year 2004 | 15,368 | $ | 5.42 / $4.45 | $ | 3,397 |
At September 30, 2003, we have no open crude oil price collar arrangements to cover our 2003 or 2004 production.
We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.
The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See Forward-Looking Information on page 29.
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ITEM | 4. Controls and Procedures |
As of the end of the current reported period, 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-14 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 issuer in the reports that it files or submits under the Exchange Act.
There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation.
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PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K
(a) | Exhibits |
15.1 | - Awareness letter of PricewaterhouseCoopers LLP | |
15.2 | - Consent of Brown, Drew & Massey, LLP | |
31.1 | - 302 Certification - Chairman, President and Chief Executive Officer | |
31.2 | - 302 Certification - Vice President and Chief Financial Officer | |
32.1 | - 906 Certification |
(b) | Reports on Form 8-K |
None
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CABOT OIL & GAS CORPORATION (Registrant) | ||||||||
October 29, 2003 | By: | /s/ Dan O. Dinges | ||||||
Dan O. Dinges Chairman, President and Chief Executive Officer (Principal Executive Officer) |
October 29, 2003 | By: | /s/ Scott C. Schroeder | ||||||
Scott C. Schroeder Vice President and Chief Financial Officer (Principal Financial Officer) |
October 29, 2003 | By: | /s/ Henry C. Smyth | ||||||
Henry C. Smyth Vice President, Controller and Treasurer (Principal Accounting Officer) |
34