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 March 31, 2003 [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
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(Exact name of registrant as specified in its charter)
DELAWARE 04-3072771 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number)
DELAWARE 04-3072771 (State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
1200 Enclave Parkway, Houston, Texas 77077
(Address(Address of principal executive offices including Zip Code)
(281) 589-4600
(Registrant's(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
Xx No___ ---¨Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes
Xx No___ ---¨As of
AprilOctober 28, 2003, there were32,188,41332,493,157 shares of Common Stock, Par Value $.10 Per Share, outstanding.-1-CABOT OIL & GAS CORPORATION
Page Part I. Financial Information Page ----Item 1. Financial Statements
3 4 5 Notes to the Condensed Consolidated Financial Statements
.....................................6 17 Item 2. Management's18 Item 3A.3.Quantitative and Qualitative Disclosures about Market Risk
.............................. 2630 Item 4. Controls and Procedures
................................................................. 2832 Part II. Other Information
Item 6. 33 34 -2-PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In(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.
CONDENSED CONSOLIDATED BALANCE SHEET
(In Thousands,
Except Per Share Amounts)except share amounts)
THREE MONTHS ENDED MARCH 31, --------------------------------------- 2003 2002 --------------- ----------------NET OPERATING REVENUES Natural Gas Production ................................................... $ 78,173 $ 46,506 Brokered Natural Gas ..................................................... 31,850 13,698 Crude Oil and Condensate ................................................. 23,174 13,718 Change in Derivative Fair Value (Note 8) ................................. (544) (616) Other .................................................................... 3,263 1,767 --------------- ---------------- 135,916 75,073 OPERATING EXPENSES Brokered Natural Gas Cost ................................................ 28,261 12,267 Direct Operations - Field and Pipeline ................................... 10,926 12,235 Exploration .............................................................. 13,391 7,056 Depreciation, Depletion and Amortization ................................. 23,507 23,210 Impairment of Unproved Properties ........................................ 2,337 2,337 Impairment of Long-Lived Assets (Note 11) ................................ 87,926 1,063 General and Administrative ............................................... 6,595 5,739 Taxes Other Than Income .................................................. 10,224 6,152 --------------- ---------------- 183,167 70,059 Gain (Loss) on Sale of Assets ............................................. 560 (18) --------------- ---------------- INCOME (LOSS) FROM OPERATIONS ............................................. (46,691) 4,996 Interest Expense and Other ................................................ 5,625 6,226 --------------- ---------------- Loss Before Income Taxes .................................................. (52,316) (1,230) Income Tax Benefit ........................................................ (19,940) (432) --------------- ---------------- NET LOSS BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE .................... (32,376) (798) CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 12) .......................... (6,847) - --------------- ---------------- NET LOSS .................................................................. $ (39,223) $ (798) =============== ================ Basic Loss Per Share - Before Cumulative Effect of Accounting Change ...... $ (1.02) $ (0.03) Diluted Loss Per Share - Before Cumulative Effect of Accounting Change .... $ (1.02) $ (0.03) Basic Loss Per Share - Cumulative Effect of Accounting Change............. $ (0.21) $ - Diluted Loss Per Share - Cumulative Effect of Accounting Change............ $ (0.21) $ - Basic Loss Per Share ...................................................... $ (1.23) $ (0.03) Diluted Loss Per Share .................................................... $ (1.23) $ (0.03) Average Common Shares Outstanding ......................................... 31,837 31,604
SEPTEMBER 30,
2003DECEMBER 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.
-3-CONDENSED CONSOLIDATED
BALANCE SHEETSTATEMENT OF CASH FLOWS (Unaudited)(In Thousands, except share amounts)
MARCH 31, DECEMBER 31, -------------- -------------- 2003 2002 -------------- --------------ASSETS Current Assets Cash and Cash Equivalents .................................... $ 1,223 $ 2,561 Accounts Receivable .......................................... 108,470 70,028 Inventories .................................................. 9,656 15,252 Other ........................................................ 5,480 5,280 -------------- -------------- Total Current Assets ...................................... 124,829 93,121 Properties and Equipment, Net (Successful Efforts Method) ........ 881,783 971,754 Other Assets ..................................................... 7,214 7,013 -------------- -------------- $ 1,013,826 $ 1,071,888 ============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts Payable ............................................. $ 88,910 $ 73,578 Accrued Liabilities .......................................... 70,785 48,312 -------------- -------------- Total Current Liabilities ................................. 159,695 121,890 Long-Term Debt ................................................... 338,000 365,000 Deferred Income Taxes ............................................ 161,641 200,207 Other Liabilities ................................................ 55,452 34,134 Stockholders' Equity Common Stock: Authorized -- 80,000,000 Shares of $.10 Par Value Issued and Outstanding -- 32,160,913 Shares and 32,133,118 Shares in 2003 and 2002, Respectively .......... 3,216 3,213 Additional Paid-in Capital ................................... 353,963 353,093 Retained Earnings (Accumulated Deficit) ...................... (28,822) 11,674 Accumulated Comprehensive Loss (Note 9) ...................... (24,935) (12,939) Less Treasury Stock, at Cost: 302,600 Shares in 2003 and 2002 ........................... (4,384) (4,384) -------------- -------------- Total Stockholders' Equity ................................ 299,038 350,657 -------------- -------------- $ 1,013,826 $ 1,071,888 ============== ==============(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
integralintergral part of these condensed consolidated financial statements.-4-CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (In Thousands)
THREE MONTHS ENDED MARCH 31, --------------------------------------- 2003 2002 -------------- --------------CASH FLOWS FROM OPERATING ACTIVITIES Net Loss ..................................................... $ (39,223) $ (798) Adjustment to Reconcile Net Income to Cash Provided by Operating Activities: Cumulative Effect of Accounting Change ................. 6,847 - Depletion, Depreciation and Amortization ............... 23,507 23,210 Impairment of Undeveloped Leasehold .................... 2,337 2,337 Impairment of Long-Lived Assets ........................ 87,926 1,063 Deferred Income Tax Expense ............................ (27,010) (471) (Gain) Loss on Sale of Assets .......................... (560) 18 Exploration Expense .................................... 13,391 7,056 Change in Derivative Fair Value ........................ 544 616 Other .................................................. (139) 1,364 Changes in Assets and Liabilities: Accounts Receivable .................................... (38,442) (924) Inventories ............................................ 5,596 5,495 Other Current Assets ................................... (621) (3,235) Other Assets ........................................... (201) 93 Accounts Payable and Accrued Liabilities ............... 22,988 (6,100) Other Liabilities ...................................... 2,607 (175) -------------- -------------- Net Cash Provided by Operating Activities ........... 59,547 29,549 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital Expenditures ......................................... (21,321) (41,062) Proceeds from Sale of Assets ................................. 1,602 (2) Exploration Expense .......................................... (13,391) (7,056) -------------- -------------- Net Cash Used by Investing Activities ............... (33,110) (48,120) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES Increase in Debt ............................................. 64,000 56,000 Decrease in Debt ............................................. (91,000) (37,000) Sale of Common Stock ......................................... 498 105 Dividends Paid ............................................... (1,273) (1,264) -------------- -------------- Net Cash Provided (Used) by Financing Activities .... (27,775) 17,841 -------------- -------------- Net Decrease in Cash and Cash Equivalents ........................ (1,338) (730) Cash and Cash Equivalents, Beginning of Period ................... 2,561 5,706 -------------- -------------- Cash and Cash Equivalents, End of Period ......................... $ 1,223 $ 4,976 ============== ==============The accompanying notes are an integral part of these condensed consolidated financial statements. -5-CABOT OIL & GAS CORPORATIONNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. FINANCIAL STATEMENT PRESENTATION
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'smanagement’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
StandardStandards (SFAS) 143,"Accounting“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“Adoption of SFAS 143, Accounting for Asset Retirement Obligations,"” to the financial statements.In December 2002, the FASB issued SFAS 148,
"Accounting“Accounting for Stock-Based Compensation-— Transition and Disclosure."” SFAS 148 amendsFASB StatementSFAS 123,"Accounting“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 ofStatementSFAS 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 SFAS148 are effective for financial statements for fiscal years ending after December 15, 2002.123, as amended by SFAS 148. The adoption ofthis statement did notthe recognition provisions would impact theCompany'sCompany’s financial position and results ofoperations or cash flows.operations. See Note13, "Stock1, “Stock Based Compensation,"” to the financial statements.In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation“Consolidation of Variable Interest Entities-— An Interpretation of Accounting Research Bulletin (ARB)51"51” (FIN 46 or Interpretation). FIN 46 is an interpretation of ARB 51,"Consolidated“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 theentity'sentity’s expected losses if they occur, receive a majority of theentity'sentity’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,-6-and to VIEs in which an enterprise obtains an interest after that date. It applies inHowever, 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 firstfiscalperiod ending after December 15, 2003. For calendar yearor interim period beginning after June 15,companies, consolidation of previously existing VIEs will be required in their December 31, 2003to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time there isfinancial statements.There was only one entity that could potentially be a VIE. The Company
is evaluating this potential VIE, in which it hashad a one percent general partner interestand that holdsin a partnership which held an interest in the Kurtenfield, to determine if it is a VIE.field. However, pursuant to the partnership agreement, the limited partnerhaselected to liquidate the partnership;it is anticipated that thisthe liquidationwill be completed prior to thewas effectivedate of the Interpretation.July 31, 2003. See Note 11 for additional information related to the partnership.2. PROPERTIES AND EQUIPMENTIn 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.
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 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:
MARCH 31, DECEMBER 31, 2003 2002 -------------- -------------- (In Thousands)Unproved Oil and Gas Properties .................................. $ 78,940 $ 76,959 Proved Oil and Gas Properties .................................... 1,494,855 1,459,240 Gathering and Pipeline Systems ................................... 137,546 137,137 Land, Building and Improvements .................................. 4,884 4,884 Other ............................................................ 29,450 29,457 -------------- -------------- 1,745,675 1,707,677 Accumulated Depreciation, Depletion and Amortization ............. (863,892) (735,923) -------------- -------------- $ 881,783 $ 971,754 ============== ==============
SEPTEMBER 30,
2003DECEMBER 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,
at December 31, 2002,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.
-7-3. ADDITIONAL BALANCE SHEET INFORMATION
3. ADDITIONAL BALANCE SHEET INFORMATION Certain balance sheet amounts are comprised of the following:
SEPTEMBER 30,
2003DECEMBER 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
MARCH 31, DECEMBER 31, 2003 2002 -------------- -------------- (In Thousands)Accounts Receivable Trade Accounts ............................................... $ 106,905 $ 65,796 Joint Interest Accounts ...................................... 4,436 6,601 Current Income Tax Receivable ................................ 2,481 2,479 Other Accounts ............................................... 115 619 -------------- -------------- 113,937 75,495 Allowance for Doubtful Accounts .................................. (5,467) (5,467) -------------- -------------- $ 108,470 $ 70,028 ============== ============== Other Current Assets Commodity Hedging Contracts .................................. $ 213 $ 634 Drilling Advances ............................................ 1,545 558 Prepaid Balances ............................................. 1,867 2,131 Restricted Cash and Other Accounts ........................... 1,855 1,957 -------------- -------------- $ 5,480 $ 5,280 ============== ============== Accounts Payable Trade Accounts ............................................... $ 16,236 $ 13,317 Natural Gas Purchases ........................................ 15,856 6,058 Royalty and Other Owners ..................................... 30,070 20,254 Capital Costs ................................................ 10,928 13,900 Taxes Other Than Income ...................................... 3,760 3,076 Drilling Advances ............................................ 3,336 7,254 Wellhead Gas Imbalances ...................................... 2,280 2,817 Other Accounts ............................................... 6,444 6,902 -------------- -------------- $ 88,910 $ 73,578 ============== ============== Accrued Liabilities Employee Benefits ............................................ $ 5,001 $ 8,751 Taxes Other Than Income ...................................... 13,224 9,887 Interest Payable ............................................. 5,153 7,076 Commodity Hedging Contracts - Short-Term ..................... 37,847 20,680 Other Accrued ................................................ 9,560 1,918 -------------- -------------- $ 70,785 $ 48,312 ============== ============== Other Liabilities Postretirement Benefits Other Than Pension ................... $ 1,900 $ 1,843 Accrued Pension Cost ......................................... 9,055 8,486 Commodity Hedging Contracts - Long-Term ...................... 2,789 - Accrued Plugging and Abandonment Liability ................... 35,687 18,151 Taxes Other Than Income and Other ............................ 6,021 5,654 -------------- -------------- $ 55,452 $ 34,134 ============== ==============4. LONG-TERM DEBT -8-4. LONG-TERM DEBTAt
March 31,September 30, 2003, the Company had$68$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 thebank'sbank’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. AtMarch 31,September 30, 2003,excess capacity totaled $182the Company had $235 millionor 73%of credit available on thetotal availablerevolving creditline.facility.In addition to the credit facility, the Company has the following debt outstanding:
.. $100$100 million of 12-year 7.19% Notes to be repaid in five annual installments of $20 million beginning in November 2005.. $75$75 million of 10-year 7.26% Notes due in July 2011.. $75$75 million of 12-year 7.36% Notes due in July 2013.. $20$20 million of 15-year 7.46% Notes due in July 20165. EARNINGS PER SHARE
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
first three monthsperiod (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 theyearapplicable period werebased on the year-to-dateexercised for common stock.The following is a calculation of basic and diluted weighted average shares outstanding
of 31,836,505 infor the three and nine months ended September 30, 2003 and31,603,717 in 2002. The diluted earnings per share amounts are based on weighted average shares outstanding plus common stock equivalents. The computation of diluted earnings per share to determine common stock equivalents includes both stock awards and stock options and did not assume conversion of these instruments due to the antidilutive effect on loss per share. Stock awards and stock options excluded from the calculation of diluted loss per share because the effect was antidilutive were 1,561,973 and 1,755,223 for the first quarter of 2003 and 2002, respectively. 6. ENVIRONMENTAL LIABILITY Environmental Liability2002:
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"(“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.The EPA is also pursuing the owners/operators of the Site to pay for remediation. The Company received documents with the notification from the EPA indicating that the Company used the Site principally to dispose of salt water from two wells over a period from 1976 to 1979. There is no allegation that the Company violated any laws in the disposal of material at the Site. The EPA's actions stem from the fact that the owners/operators of the Site do not have the financial means to implement a closure plan for the Site.A group of potentially responsible parties, including the Company, formed a group, called the Casmalia Negotiating Committee
("CNC"(“CNC”). The CNChashad extensive settlement discussions with the EPA andhasentered into a consent decreewhich will requirerequiring 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 anescrow account, representing its volumetric share of the CNC/United States settlement.
This cash settlement, once released fromThe consent decree was approved by the court on August 14, 2003 and the funds in the escrowandaccount were paid to thefederalgovernmentafter the consent decree is entered by the court, will resolveon September 8, 2003. The settlement has resolved all federal claims against the Company for response costs andwill releasereleases 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.-9-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'sState’s claim and the number of parties allegedly responsible, theCompany'sCompany’s share of this claim is not expected to beimmaterial. Thematerial.With the entry of the consent decree and the purchase of the insurance, any potential material claims against the Company
has established a reserve that management believesrelated tobe adequateCasmalia have been resolved and the Company does not plan toprovide forreport on thisenvironmental liability and related legal costs. 7. COMMITMENTS AND CONTINGENCIESSite 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'sCompany’s defenses are supported by Wyoming case law,a recenttwo letterdecisiondecisions handed down byastate district court judges inanother case doesother cases do not support certain of the defenses. Thedecision hasdecisions have not been reduced toaformalorderorders and it is not known what effect, if any, thedecisiondecisions will have on the pending cases. In addition, in 2000 a district court judge’s decision supported theCompany'sdefenses 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
recentlyagreed 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 certifyonea question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner checkstub reportingstubs that had been decided adversely to theCompany'sCompany’s position in the state district court letter decision. After the federaljudge'sjudge’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,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
-10-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.
No trial orThe 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 dateshave been set and limited factual discovery is ongoing.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'sCompany’s financial position.Texas Title Litigation
On January 6, 2003, the Company was served with
Plaintiffs'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.-11-Lease Commitments The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. Leases for the Company's offices in Houston and Denver each run for approximately seven more years. Rent expense under such arrangements totaled $1.9 million and $2.1 million for the three months ended March 31, 2003, and 2002, respectively. Most of the other leases expire within five years and may be renewed. Future minimum rental commitments under non-cancelable leases in effect at March 31, 2003, are as follows: (In thousands) ------------------------------------------ 2003 $ 4,193 2004 4,805 2005 4,419 2006 3,732 2007 3,488 Thereafter 5,119 -------- $ 25,756 ======== Minimum rental commitments are not reduced by an insignificant amount of minimum sublease rental income due in the future under non-cancelable subleases. 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. At
March 31,September 30, 2003, the Company had2431 cash flow hedges open:eight10 natural gas price collar arrangements14and 21 natural gas price swaparrangements and two crude oil price collararrangements. Additionally, the Company hadthreefive crude oilprice range swapsfinancial instruments and one natural gas financial instrument open atMarch 31,September 30, 2003, that did not qualify for hedge accounting under SFAS 133. AtMarch 31,September 30, 2003, a$38.1$16.2 million ($23.610.0 million net of tax) unrealized loss was recorded to Other Comprehensive Income, along with a$40.6$19.8 million derivative liability and a$0.7$2.4 million derivative receivable.A chargeThe 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
Operating Incomenatural gas production revenue and unrealized income of $0.3 million iscomprisedreflected 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$0.4$48.3 millionand $0.1($45.4 million for gasderivative instrumentsandoil derivative instruments,$2.9 million for oil) and $8.6 million ($7.9 million for gas and $0.7 million for oil), respectively,inclusivein 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
range swaps described below.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
range swaps with counterparties. These derivativesswap arrangements that do not qualify for hedge accountingunderin accordance with SFAS133 and133. These financial instruments are recorded at fair value at the balance sheet date. AtMarch 31,September 30, 2003, the Company hadthreefive open crude oilrangeswap arrangements and one natural gas swap arrangement with an unrealized net loss of$0.8$0.4 millionreflectedand $0.2 million recognized in OperatingRevenue. -12-9. COMPREHENSIVE INCOMERevenue, respectively.
9. COMPREHENSIVE INCOME Comprehensive Income includes Net Income and certain items recorded directly to
Stockholders'Stockholders’ Equity and classified as Other Comprehensive Income. The following table illustrates the calculation of Comprehensive Income for thethree-monthnine-month periods endedMarch 31: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 )
THREE MONTHS ENDED ----------------------------------------------------- MARCH 31, 2003 MARCH 31, 2002 ------------------------- ----------------------- (In Thousands)Accumulated Other Comprehensive Income (Loss) - Beginning of Period ......................... $ (12,939) $ 835 Net Loss ........................................ $ (39,223) $ (798) Other Comprehensive Loss (Net of Tax) Reclassification Adjustments for Settled Contracts ........................ (16,131) (1,592) Changes in Fair Value of Outstanding Hedge Positions .......................... 4,135 (7,831) ---------- ---------- ---------- --------- Total Other Comprehensive Loss .................. $ (11,996) $ (11,996) $ (9,423) $ (9,423) ---------- ---------- ---------- --------- Comprehensive Loss .............................. $ (51,219) $ (10,221) ========== ========== Accumulated Comprehensive Loss - End of Period ............................... $ (24,935) $ (8,588) ========== =========10. RETIREMENT OF EXECUTIVE OFFICER 10. RETIREMENT OF EXECUTIVE OFFICERIn May 2002, Ray Seegmiller retired as the
Company'sCompany’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'sSeegmiller’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'sSeegmiller’s previously awarded stock grants and options vested upon retirement, resulting in compensation expense of approximately $1.7 million.-13-11. ACQUISITION OF CODY COMPANY
11. ACQUISITION OF CODY COMPANY In August 2001, the Company acquired the stock of Cody Company, the parent of Cody Energy LLC
("(“Codyacquisition"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 theCompany'sCompany’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 currentCompany’s interest in Kurteniswas approximately 25%, including a one percent interest in the partnership. Under the partnership agreement, the Company
hashad 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 partnerhashad the sole option to trigger a liquidation of the partnership. Effective February 13, 2003, the Kurten partnership commenced liquidation at the limitedpartner'spartner’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 Companywoulddid 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 limitedpartners' decision and ourpartners’ 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 theCompany'sCompany’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.12. ADOPTION OF SFAS 143, "ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS"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“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 theassetsasset’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 theCompany'sCompany’s cash flows as a result of adopting SFAS 143. See Note 2 for additional information on plugging and abandonment costs.-14-Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement liabilities, settled liabilities,
accretion expenseand 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.
QUARTER ENDED MARCH 31, 2002 -------------------------- (In Thousands) (Except Per Share Amounts) Net Loss $ (1,409) -------------- Per Share - Basic ....... $ (0.04) Per Share - Diluted ..... $ (0.04) 13. 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. 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. QUARTER ENDED MARCH 31, ----------------------- (In Thousands, Except Per Share Amounts) 2003 2002 - ------------------------------------------------------------------------------- Net Loss, as reported $ (39,223) $ (798) Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax (1,802) (1,469) --------- ---------- Pro forma net loss $ (41,025) $ (2,267) ========= ========== Earnings per share: Basic - as reported $ (1.23) $ (0.03) Basic - pro forma $ (1.29) $ (0.07) Diluted - as reported $ (1.23) $ (0.03) Diluted - pro forma $ (1.29) $ (0.07) -15-The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table. QUARTER ENDED MARCH 31, -------------------------- (In Thousands, Except Per Share Amounts) 2003 2002 - ------------------------------------------------------------------------------- Compensation Expense in Net Income, as reported (1) $ 248 $ 339 Weighted Average Value of Options Granted During the Quarter (2) $ 6.75 $ 6.02 Assumptions Stock Price Volatility 35.4% 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. 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. -16-
PERIOD ENDING
SEPTEMBER 30, 2002QUARTER 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 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"“Company”) as ofMarch 31,September 30, 2003, and the related condensed consolidated statements of operations and cash flows for each of the three-month and nine-month periods endedMarch 31,September 30, 2003 andMarch 31,September 30, 2002. These interim financial statements are the responsibility of theCompany'sCompany’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'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.As discussed in Notes 1 and 12 to the condensed consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" effective January 1, 2003. PricewaterhouseCoopersPRICEWATERHOUSECOOPERS LLP
Houston, Texas
April 25,October 29, 2003
-17-ITEM 2.
Management'sManagement’s Discussion and Analysis of Financial Condition and Results of OperationsThe following review of operations for the third quarter and first
quarternine 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 andManagement'sManagement’s Discussion and Analysis included in the Cabot Oil & Gas Form 10-K for the year ended December 31, 2002.Overview
In the first
quarternine months of 2003, we produced21.967.1 Bcfea decreasecompared to production of3% over68.7 Bcfe for the2002 first quarter.comparable period of the prior year. Natural gas production was17.253.7 Bcfdown 1.2 Bcf, or 7%, compared to the 2002 first quarter. Oiland oil production was750 Mbbls, up 82 Mbbls, or 12% over the comparable quarter of last year. Production2,193 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.Our currentThe decline in our natural gas productionlevels areis essentially attributable todrilling successes inthe size and timing of the Gulf Coast andEastern regions. Commodity prices were unusually high duringWest regions drilling program, along with thefirst quarternatural decline of2003, and our financial results reflected their impact.existing production.In the
first quarternine months ended September 30, 2003, we drilled123 gross wells (106 development and 17 exploratory wells) with a success rate of2003, natural gas prices were 80% higher90% compared to 85 gross wells (79 development andcrude oil prices were 50% higher thansix 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.Although our hedge positions limited the upside in the first quarter, the strong commodity price environment resulted in an increase to gas revenueWe had net income of
$31.7$1.3 million, or68%,$0.04 per share, for the nine months ended September 30, 2003 despite impairment charges of $93.8 million andan increase in oil revenuethe $6.8 million impact of$9.5 million, or 69%. Operating cash flows were similarly impacted, increasing by $30.0 million, or 102%, over last year. Despite the increase in commodity prices our first quarter resulted inanet losscumulative effect of$39.2 million, or $1.23 per share. This loss is substantially attributable to anaccounting change. The pre-tax non-cash impairment charges consist of $87.9 millionnon-cash impairmentrelated to the liquidation of a limited partnership interest in the Kurten field(see Note 11)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 SFAS143 (see Note 12).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
quarternine 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 wedrilled 25 gross wells (22 developmentexpect 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 andthree exploratory wells) withother factors. As asuccess rateresult, 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
88% comparedcrude oil and natural gas reserves at economical costs are critical to21 gross wells (17 development and four exploratory wells) and a 95% success rate in the first quarter of 2002. For the full year,our long-term success. In 2003, excluding acquisitions, weplanexpect todrill 180 gross wells andspend approximately$153.0$172.0 million in capital and explorationexpenditures compared to 108 gross wells and $126.3expenditures. For the nine months ended September 30, 2003, $127.7 million of capital and exploration expendituresin 2002. Total capital and exploration expenditures were $31.7 million for the first quarter of 2003, compared to $34.5 million for the comparable period in 2002.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.Mexico and Canada. We believe these strategies are appropriate in the current industry environmentenablingand 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
25.29.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
quarterhalf of 2002 into the summer and continued to strengthen throughthe first quarter of2003. Prices in the firstquarternine months of 2003 were the result of a higher demand associated with colder than normal winter temperatures, combined withhistorical low inventory levels. -18-higher storage injection demand in the second and third quarters. Our primary source of cash during the first
quarternine months of 2003 was from funds generated from operations. Cash was primarily used to fund exploration and development expenditures, reduce debt andtopay dividends. We had a net cashoutflowinflow of$1.3$1.8 millioninfor thefirst quarternine months ended September 30, 2003. See below for additional discussion and analysis of2003.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
inflows from operating activities totaled $59.5 million in the current quarter. The $34.7 million of capitalflow discussion andexploration expenditures were funded with our operating cash flows. THREE MONTHS ENDED MARCH 31, 2003 2002 -------- -------- (In millions) Cash Flows Provided by Operating Activities .. $ 59.5 $ 29.6 ======== ========analysis:Cash flows from operating activitiesin the 2003 first quarter were $29.9 million higher than the corresponding quarter of 2002 primarilyincreased due to higher commodity prices partially offset by lower natural gasand oil prices. THREE MONTHS ENDED MARCH 31, 2003 2002 --------- --------- (In millions) Cash Flows Used by Investing Activities ..... $ (33.1) $ (48.1) ========= =========production sales volumes.
Cash flows usedbyin investing activities increased due to an increase inthe first quarter of 2003 were substantially attributable to capital andexplorationexpenditures of $34.7 million, partially offset by proceeds from the sale of certain oil and gas properties of $1.6 million.expense.Cash flows usedby investing activitiesinthe first quarter of 2002 were entirely for capital and exploration expenditures of $48.1 million. THREE MONTHS ENDED MARCH 31, 2003 2002 --------- ----------- (In millions) Cash Flows Provided (Used) by Financing Activities ...................................... $ (27.8) $ 17.8 ========= ======== Cash flows used byfinancing activitiesin the first quarter of 2003 consist primarily of $27.0 million of borrowing repayments on the revolving credit facility and $1.3 million of dividend payments. Cash flows provided by financing activities in the first quarter of 2002 consist primarily of $19.0 million inincreasedborrowings on the revolving credit facility. Partially offsetting the use of cash flow by financing activities were proceeds from the exercise of stock options in the first quarter of $0.5 million in 2003 and $0.1 million in 2002. Our 2003 interest expense is expecteddue tobe approximately $23.6 million.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'sbank’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.Capitalization
Our capitalization information is as follows:
SEPTEMBER 30,
2003DECEMBER 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 flowDiscretionary Cash Flow andnet incomeNet Income andearnings per share,Earnings Per Share, excluding selected items. These non-GAAP financial measure calculationsand reconciliations to the most comparable GAAP financial measure for the period aremay be presentedwith eachin earningsreleasereleases of the Company, furnished in Form 8-K to the Securities and ExchangeCommission.Commission, along with reconciliations to the most comparable GAAP financial measure for the period.Discretionary
cash flowCash Flow is defined as Net Income plus non-cash charges and Exploration Expense. Discretionarycash flowCash Flow is widely accepted as a financial indicator of an oil and gascompany'scompany’s ability to generate cash which is used to internally fund exploration and development activities, pay dividends and service debt. Discretionarycash flowCash Flow is presented based onmanagement'smanagement’s belief that this non-GAAP measure isuseful informationhelpful to investorsbecause it is widely used by professional research analysts in -19-when comparing our cash flow with the valuation, comparison, rating and investment recommendationscash flow of other companieswithinthat use the Full Cost method of accounting foroil and gas
explorationproducing activities or have different financing andproduction industry. Many investors use the published research of these analysts in making their investment decisions.capital structures or tax rates. Discretionarycash flowCash 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
managementsmanagement’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 aBeneficial Comparisonbeneficial comparison toSimilarlysimilarly 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.Capitalization Our capitalization information is as follows: MARCH 31, DECEMBER 31, 2003 2002 --------- ------------ (In millions) Debt ........................ $ 338.0 $ 365.0 Stockholders' Equity /(1)/ .. 299.0 350.7 -------- -------- Total Capitalization ........ $ 637.0 $ 715.7 ======== ======== DebtCritical 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
Capitalization 53.1% 51.0% /(1)/ Includes common stock, netmake estimates and judgments that affect the reported amounts oftreasury stock. No shares of preferred stock were outstanding. Duringassets, liabilities, revenues and expenses. See thefirst quarter of 2003, we paid dividends of $1.3 millionCompany’s Annual Report onthe 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 flowsForm 10-K for theyear. The following table presents major components of capital and exploration expenditures: THREE MONTHS ENDED MARCHyear ended December 31,20032002,----------- ----------- (In millions) Capital Expenditures Drilling and Facilities ...... $ 14.5 $ 25.9 Leasehold Acquisitions ....... 2.8 1.0 Pipeline and Gathering ....... 1.0 0.2 Other ........................ 0.0 0.3 -------- -------- 18.3 27.4 Exploration Expenses ............. 13.4 7.1 -------- -------- Total ........................ $ 31.7 $ 34.5 ======== ======== Total capital and exploration expenditures in the first quarter of 2003 decreased $2.8 million compared to the same quarter of 2002, primarily as a result of decreased drilling activity. We plan to drill 180 gross wells in 2003 compared with 108 gross wells drilled in 2002. This 2003 drilling program includes approximately $153.0 million in total capital and exploration expenditures, up -20-from $126.3 million in 2002. Budgeted spending in 2003 includes approximately $89 millionfordrilling and dry hole exposure, $11 million for lease acquisition and $13 million in geological and geophysical expenses. In addition to the drilling and exploration program, other 2003 capital expenditures are planned primarily for production equipment, workovers, and for gathering and pipeline infrastructure maintenance and construction. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly. -21-further discussion. Results of Operations
Selected Financial and Operating Data
THREE MONTHS ENDED MARCH 31, -------------------------------- 2003 2002 -------- -------- (In millions, except where noted)Operating Revenues ....................................................... $ 135.9 $ 75.1 Operating Expenses ....................................................... 183.2 70.1 Operating Income (Loss) .................................................. (46.7) 5.0 Interest Expense ......................................................... 5.6 6.2 Net Loss, Before Accounting Change ....................................... (32.4) (0.8) Net Loss ................................................................. (39.2) (0.8) Loss Per Share - Basic, Before Accounting Change ......................... $ (1.02) $ (0.03) Loss Per Share - Diluted, Before Accounting Change ....................... $ (1.02) $ (0.03) Loss Per Share - Basic, Accounting Change................................. $ (0.21) $ 0.00 Loss Per Share - Diluted, Accounting Change............................... $ (0.21) $ 0.00 Loss Per Share - Basic ................................................... $ (1.23) $ (0.03) Loss Per Share - Diluted ................................................. $ (1.23) $ (0.03) Natural Gas Production (Bcf) Gulf Coast .......................................................... 6.7 7.5 West ................................................................ 6.1 6.4 East ................................................................ 4.4 4.5 ------- ------ Total Company ....................................................... 17.2 18.4 ======= ====== Natural Gas Production Sales Prices ($/Mcf) Gulf Coast .......................................................... $ 4.88 $ 2.67 West ................................................................ $ 3.61 $ 2.14 East ................................................................ $ 5.35 $ 2.85 Total Company ....................................................... $ 4.55 $ 2.53 Crude Oil Production (Mbbl) Gulf Coast .......................................................... 696 610 West ................................................................ 48 50 East ................................................................ 6 8 ------- ------- Total Company ....................................................... 750 668 ======= ======= Crude Oil Production Sales Prices ($/Bbl) Gulf Coast .......................................................... $ 30.84 $ 20.57 West ................................................................ $ 32.05 $ 20.97 East ................................................................ $ 25.79 $ 16.41 Total Company ....................................................... $ 30.88 $ 20.55 Brokered Natural Gas Margin Volume (Bcf) ........................................................ 3.9 3.2 Margin ($/Mcf)/(1)/ ................................................. $ 0.92 $ 0.45 (1) Amount represents brokered natural gas revenue less brokered natural gas cost, divided by brokered natural gas volumes.FirstThird Quarters of 2003 and 2002 Compared
Net Income and
Revenues.Operating RevenueWe reported
anetlossincome in thefirstthird quarter of 2003 of$39.2$22.7 million, or$1.23$0.70 per share. During the corresponding quarter of 2002, we reportedanetlossincome of$0.8$6.1 million, or$0.03$0.19 per share.Net operating revenuesOperating income increased by$60.8$28.5 millionor 81%compared to the comparable period of the prior year. The increase in net income andoperating income decreased by $51.7 million. The decrease inoperating income was substantially due tothe impairment on the Kurten field (Note 11). Natural gas sales made up 58%, or $78.2 million, of operating revenue. The 81% increase in -22-operating revenues was primarily due toan80% and 50%increase in our realizedaveragenatural gaspriceand crude oilprice, respectively, compared to the first quarter of 2002, as well as a 12% increase in crude oil production, partially offset by a 7% decrease in natural gas production. Operating revenues were also impacted by an increase in our brokered natural gas revenues.prices.Natural Gas Production Revenues
The average
realizedtotal company realized natural gas production sales price, including the impact of derivative instruments, was$4.55$4.53 perMcf for the first quarter of 2003.Mcf. Due tocertainderivative instruments this price was reduced by$1.46$0.42 per Mcf. Theaverage Gulf Coastfollowing 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.
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,
increased $2.21including the impact of derivative instruments, was $28.40 perMcf, or 83%,Bbl for the third quarter of 2003. Due to$4.88, increasing operating revenuesderivative instruments this price was reduced byapproximately $14.8 million. In$1.00 per Bbl. The following table excludes theWestern region,impact of theaverage natural gas production sales price increased $1.47 per Mcf, or 69%, to $3.61, increasing operating revenues by approximately $9.0 million. The average Eastern region natural gas production sales price increased $2.50 per Mcf, or 88%, to $5.35, increasing operating revenues by approximately $11.0 million. The overall weighted average natural gas production sales price increased $2.02 per Mcf, or 80%, to $4.55, increasing revenues by $34.8 million. Natural gas production volumechange in derivative fair value of $0.5 million and $1.6 million for the three months ended September 30, 2003 and 2002, respectively. These amounts have been included in theGulf Coast region was down 0.8 Bcf, or 11%, to 6.7 Bcf primarilyCrude Oil and Condensate revenues line item on the Statement of Operations.
THREE MONTHS ENDED
SEPTEMBER 30,Variance 2003 2002 Amount Percent Crude Oil Production (Mbbl)
Gulf Coast
683 697 (14 ) (2 %) West
46 61 (15 ) (25 %) East
7 8 (1 ) (13 %) Total Company
736 766 (30 ) (4 %) Crude Oil Sales Price ($/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 ) 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.
Natural gas production volumeThe increase in theWestern region decreased 0.3 Bcf, or 5%, to 6.1 Bcf primarily due to natural declines and a small drilling programrealized crude oil price combined with the decline in2002. Natural gasproductionvolume in the Eastern region was substantially the same as the comparable quarter of 2002 at 4.4 Bcf. The decrease in total natural gas production of 1.2 Bcf, or 7%,resulted in adecrease to natural gasnet revenue increase of$3.0 million in the first quarter of 2003. The average realized total company crude oil sales price was $30.88 per Bbl first quarter of 2003. Due to certain derivative instruments this price was reduced by $2.54 per Bbl. The volume of crude oil sold in the quarter increased by 82 Mbbls, or 12%, to 750 Mbbls, increasing operating revenues by $1.7$1.8 million.This increase in crude oil production was substantially due to production increases in the Gulf Coast region. Additionally, crude oil prices increased $10.33 per Bbl, or 50%, to $30.88, resulting in an increase to operating revenues of $7.8 million. In total, revenue from crude oil sales increased $9.5 million, or 69%, above the 2002 first quarter. Brokered natural gas revenue increased $18.2 million, or 133%, over the first quarter of last year. The sales price of brokered natural gas rose 89%, resulting in an increase in revenue of $15.0 million, combined with a 24% increase in volume of natural gas brokered this quarter, increasing revenues by $3.2 million. After including the related brokered natural gas costs, we realized a net margin of $3.6 million in the first quarter of 2003 and $1.4 million in the comparable quarter of 2002.Other Net Operating Revenues
Other operating revenues
increased $1.5 million to $3.3decreased $1.2 million. This change wasprimarilya resultof: . A $0.4 million increase in transportation revenue due toof asubstantial increase in volumes, offset slightly by a decrease in price. . A $0.8 million increasedecline in natural gasliquidsliquid revenueas a resultcombined with the expiration ofincreased volumes in the current quarter. . A $0.3 million increase in natural gas processing plant revenue. -23-Costs and Expenses.section 29 tax credits at December 31, 2002.Operating Expenses
Total costs and expenses from operations increased
$113.1$18.6 million in thefirstthird quarter of 2003 compared to the same quarter of 2002. The primary reasons for this fluctuation are as follows:.Brokered natural gas cost increased$16.0 million, or 130%, from$6.8 million. For additional information related to this increase see thefirst quarter of last year. The cost of brokered natural gas rose 86%, resulting in an increase to expense of $13.1 million. Additionally, a 24% increase in volume of natural gas brokered this quarter increased costs by $2.9 million. . Direct operating expense decreased $1.3 million, or 11%. Operating costs have decreased in the Gulf Coast,analysis performed for Brokered Natural Gas Revenue andto a lesser extent in the Rocky Mountains. The decrease in the Gulf Coast is attributable to timing of expenditures. The decrease in the Rocky Mountains is due to a milder winter, which resulted in less required maintenance, and to a lesser extent, timing of expenditures. On a per unit basis, operating expense declined from $0.54 to $0.50 per Mcfe produced in the first quarter of 2002 and 2003, respectively. .Cost.Exploration expense increased$6.3$4.2 millionor 90%, primarilyas a result ofincreased spending on geological and geophysical expenses andhigher dry hole expense in 2003. During thefirstthird quarter of 2003, wespent an additional $5.2 million on geological and geophysical activities and incurred an additional $0.7 milliondrilled 10 exploratory wells compared to 1 indry hole expense. .the corresponding period of 2002.Impairment oflong-lived assetsnatural gas producing properties expense increased$86.9 million due to the impairment on the Kurten field (see Note 11). . General and administrative costs increased $0.9 million, or 15%, as a result of an increase in employee fringe benefit expenses. .$5.9 million.Taxes other than income increased$4.1$4 millionor 66%,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.
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.
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 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
$0.6$0.3 million as a result of a lower average level of outstanding debt during thefirst quarter ofnine months ended September 30, 2003 when compared to thefirst quartercorresponding period of2002the prior year and a decline in interest rates on the revolving creditfacility.facility, partially offset by a charge related to the adoption of SFAS 150.Income Tax Expense
Income tax
benefitexpense increasedfrom $0.4$1.4 millionto $19.9 million in the first quarter of 2002 and 2003, respectively. The increase isdue to a comparable increase in our pre-tax netloss.income.Recently Issued Accounting Pronouncements
In June 2001, the FASB approved for issuance Statement of Financial Accounting
StandardStandards (SFAS) 143,"Accounting“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“Adoption of SFAS 143, Accounting for Asset Retirement Obligations,"” to the financial statements.In December 2002, the FASB issued SFAS No. 148,
"Accounting“Accounting for Stock-Based Compensation-— Transition and Disclosure."” SFAS 148 amendsFASB StatementSFAS 123,"Accounting“Accounting for Stock-BasedCompensation"Compensation”, to provide alternative methods of transition for a voluntary change to the fair value based-24-method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of StatementSFAS 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 ofthis statement did notthe recognition provisions would impactthe Company'sour financial position and results ofoperations, or cash flows.operations. See Note 13,"Stock“Stock Based Compensation,"” to the financial statements.In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation“Consolidation of Variable Interest Entities-— An Interpretation of ARB51"No. 51” (FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research Bulletin 51,"Consolidated“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 theentity'sentity’s expected losses if they occur, receive a majority of theentity'sentity’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.It applies inHowever, 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 firstfiscalperiod ending after December 15, 2003. For calendar yearor interim period beginning after June 15,companies, consolidation of previously existing VIEs will be required in their December 31, 2003to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time we havefinancial statements.There was only one entity that could potentially be a VIE. We
are evaluating this potential VIE, in which we havehad a one percent general partner interestand that holdsin a partnership which held an interest in the Kurtenfield, to determine if it is a VIE.field. However, pursuant to the partnership agreement, the limited partnerhaselected to liquidate the partnership;it is anticipated that thisthe liquidationwill be completed prior to thewas effectivedate of the Interpretation.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.
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"“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.Conclusion Our financial results depend upon many factors, particularly the price of natural gas and oil and our ability to market gas and oil on economically attractive terms. The average produced natural gas sales price received in the first three months of 2003 was 80% higher than in 2002 and the average oil sales price was 50% higher than in the comparable period of 2002. The volatility of natural gas prices in recent years remains prevalent in 2003 with wide price swings in day-to-day trading on the NYMEX futures market. Additionally, we have natural gas price swaps and collars in place through December 2004 and oil price collars and range swaps in place through June 2003 and December 2003, respectively, which all offer some protection against price volatility. Given this continued price volatility, we cannot predict with certainty what pricing levels will be in the future. Because future cash flows are subject to these variables, we cannot assure you that our operations will provide cash sufficient to fully fund our planned capital expenditures. See Item 3A., "Quantitative and Qualitative Disclosures about Market Risk" for additional information regarding these derivative instruments. We believe our capital resources, supplemented with external financing, if necessary, are adequate to meet our capital requirements. The preceding paragraphs contain forward-looking information. See Forward-Looking Information above. -25-ITEM
3A.3. Quantitative and Qualitative Disclosures about Market RiskCommodity Price Swaps and Options
Our hedging policy is designed to reduce the risk of price volatility for our production in the natural gas
natural gas liquidsand 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
-– SwapsFrom 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
quarternine months of 2003, natural gas price swaps covered8,75425,908 Mmcf, or51%48% of ourfirst quartergas production, fixing the sales price of this gas at an average of $4.47 per Mcf.During the first quarter of 2002, we did not have any natural gas price swaps covering our production. During the first quarter of 2003 and 2002, we did not have any crude oil price swaps covering our production that qualified for hedge accounting.At
March 31,September 30, 2003, we had open natural gas price swap contracts covering our 2003 and 2004 production as follows:
Natural Gas Price Swaps ----------------------------------------------- Volume Weighted Unrealized in Average Loss Contract Period Mmcf Contract Price (In Thousands) - ----------------------------------------------------------------------------------------------------As of March 31, 2003 Natural Gas Price Swaps on Production in: Second Quarter 2003 7,950 $ 4.31 Third Quarter 2003 8,037 4.31 Fourth Quarter 2003 8,037 4.31 ----------------------------------------------- Nine Months Ended December 31, 2003 24,024 $ 4.31 $ 25,850 First Quarter 2004 2,089 $ 4.42 Second Quarter 2004 2,089 4.42 Third Quarter 2004 2,112 4.42 Fourth Quarter 2004 2,112 4.42 ----------------------------------------------- Full Year 2004 8,402 $ 4.42 $ 5,153
Natural Gas Price Swaps Contract Period
Volume
in
MmcfWeighted
Average
Contract PriceUnrealized
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
we enterthe Company enters into natural gas and crude oilrange swaps with counterparties. These derivativesderivative arrangements that do not qualify for hedge accounting under SFAS133 and133. These financial instruments are recorded at fair value at the balance sheet date. AtMarch 31,September 30, 2003,these instruments resulted inthe Company had five open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss of$0.8$0.4 million and $0.2 million recognized inoperating revenue. -26-Operating Revenues, respectively. Hedges on Production
-– OptionsThroughout 2002 and
the first quarter of2003, 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 theapplicableindex falls below the floor price, the counterparty pays us.The 2003 and 2004 natural gas price collar hedges included several collar arrangements based on eight price indexes at which we sell a portion of our production.During the first
quarternine months of 2003, natural gas price collars covered3,33311,853 Mmcf, or19%22% of ourfirst quartergas production, with a weighted average floor of $4.46 per Mcf and a weighted average ceiling of$5.35$5.40 per Mcf.DuringAdditionally, during the firstquarternine months of2002, natural gas2003, we had crude oil price collars which covered12,109 Mmcf,362 Mbbls, or66%25% of our production, with a weighted averagepricefloor of$2.68$24.75 perMcfbbl and a weighted averagepriceceiling of$3.53$28.86 perMcf.bbl. These crude oil contracts expired in June 2003.At
March 31,September 30, 2003, we had open natural gas price collar contracts covering our 2003 and 2004 production as follows:
Natural Gas Price Collars ----------------------------------------------- Volume Weighted Unrealized in Average Loss Contract Period Mmcf Ceiling / Floor (In Thousands) - ---------------------------------------------------------------------------------------------------As of March 31, 2003 Natural Gas Price Collars on Production in: Second Quarter 2003 4,237 $5.42 / $4.46 Third Quarter 2003 4,283 $5.42 / $4.46 Fourth Quarter 2003 4,283 $5.42 / $4.46 ----------------------------------------------- Nine Months Ended December 31, 2003 12,803 $5.42 / $4.46 $ 6,636 First Quarter 2004 2,955 $5.78 / $4.32 Second Quarter 2004 2,955 $5.78 / $4.32 Third Quarter 2004 2,988 $5.78 / $4.32 Fourth Quarter 2004 2,988 $5.78 / $4.32 ----------------------------------------------- Full Year 2004 11,886 $5.78 / $4.32 $ 1,420We have 2003 crude oil price collars in place for the months of January through June, covering 362 Mbbls of production with a weighted average price floor of $24.75 per Mbbl and a weighted average price ceiling of $28.86 per Mbbl.
Natural Gas Price Collars Contract Period
Volume
in
MmcfWeighted
Average
Ceiling / FloorUnrealized
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
March 31,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
25. -27-ITEM 4. Controls and Procedures Within29.
ITEM 4. Controls and Procedures As of the
90-dayend of the current reported period,prior to the date of this report,the Company carried out an evaluation, under the supervision and with the participation of theCompany'sCompany’s management, including theCompany'sCompany’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of theCompany'sCompany’s disclosure controls and procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934 (the"Exchange Act"“Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that theCompany'sCompany’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 theCommission'sCommission’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'sCompany’s internal controls or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation.-28-PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits 4.3 - Rights Agreement dated as of March 28, 1991, between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477). (a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994). (b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form 8-K for December 21, 2000). (c) Amendment No. 3 to the Rights Agreement dated January 1, 2003. 10.16 - Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001 ). (a) First Amendment to the Cabot Oil & Gas Corporation Second Amended and Restated 1994 Non-Employee Director Stock Option Plan dated March 17, 2003. 15.1 - Awareness letter of PricewaterhouseCoopers LLP 15.2 - Consent of Brown, Drew & Massey, LLP (b) Reports on Form 8-K Item 5: Other Events filing made on February 13, 2003, includes Item 7. Press Release dated February 13, 2003, and titled "Cabot Oil & Gas Announces First Quarter Impairment and SFAS 143 Adoption." -29-SIGNATURE
(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
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) April 30, 2003 By: /s/ Dan O. Dinges ------------------------------------------- Dan O. Dinges Chairman of the Board, Chief Executive Officer and President (Principal Executive Officer) April 30, 2003 By: /s/ Scott C. Schroeder ------------------------------------------- Scott C. Schroeder Vice President and Chief Financial Officer (Principal Financial Officer) April 30, 2003 By: /s/ Henry C. Smyth ------------------------------------------- Henry C. Smyth Vice President, Controller and Treasurer (Principal Accounting Officer) -30-CERTIFICATIONS I, Dan O. Dinges, certify that: 1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: April 30, 2003 /s/ Dan O. Dinges -------------------------------------- Dan O. Dinges Chairman of the Board, Chief Executive Officer and President -31-I, Scott C. Schroeder, certify that: 1. I have reviewed this quarterly report on Form10-Q of Cabot Oil & Gas Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: April 30, 2003 /s/ Scott C. Schroeder ------------------------------------------ Scott C. Schroeder Vice President and Chief Financial Officer -32-
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