-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, WAHKJkClxxkDq5aYMVLM3Y7EWkmZ4P046Zb0jpUnqVp9A9Ue6U8pAl7ivWpux51o M5evRSKKMhFUZMWB5qTC/g== 0000909334-04-000342.txt : 20041115 0000909334-04-000342.hdr.sgml : 20041115 20041115172406 ACCESSION NUMBER: 0000909334-04-000342 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20040930 FILED AS OF DATE: 20041115 DATE AS OF CHANGE: 20041115 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONTINENTAL RESOURCES INC CENTRAL INDEX KEY: 0000732834 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 730767549 STATE OF INCORPORATION: OK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 333-61547 FILM NUMBER: 041146949 BUSINESS ADDRESS: STREET 1: 302 NORTH INDEPENDENCE, SUITE 1400 CITY: ENID STATE: OK ZIP: 73702 BUSINESS PHONE: 5802338955 10-Q 1 criform10q-111504.txt United States SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2004 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________to _________ Commission File Number: 333-61547 CONTINENTAL RESOURCES, INC. (Exact name of registrant as specified in its charter) Oklahoma 73-0767549 - ------------------------------- -------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 302 N. Independence, Suite 1500, Enid, Oklahoma 73701 - ----------------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (580) 233-8955 Securities registered pursuant to Section 12 (b) of the Act: None Securities registered pursuant to Section 12 (g) of the Act: None 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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ ] No [X] The Registrant is not subject to the filing requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, but files reports required by those sections pursuant to contractual obligation requirements. Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act.) Yes [ ] No [X] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Class Outstanding as of November 15, 2004 - ---------------------------- ----------------------------------- Common Stock, $.01 par value 14,368,919 shares TABLE OF CONTENTS PART I. Financial Information ITEM 1. Financial Statements Condensed Consolidated Balance Sheets.......................4 Condensed Consolidated Income Statements....................5 Condensed Consolidated Statements of Cash Flows.............7 Notes to Condensed Consolidated Financial Statements........8 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations...........................................19 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk........28 ITEM 4. Controls and Procedures...........................................30 PART II. Other Information ITEM 1. Legal Proceedings.................................................30 ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.......30 ITEM 3. Defaults Upon Senior Securities...................................30 ITEM 4. Submission of Matters to a Vote of Security Holders...............30 ITEM 5. Other Information.................................................30 ITEM 6. Exhibits..........................................................31 Signatures.................................................................32 Certifications Pursuant to Item 302 of the Sarbanes-Oxley Act of 2002......33 PART I. Financial Information ITEM 1. FINANCIAL STATEMENTS CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (Dollars in thousands)
December 31, September 30, Assets 2003 2004 ------------------------ ------------------------ Current assets: (Unaudited) Cash and cash equivalents $ 2,277 $ 13,991 Accounts receivable: Oil and gas sales 19,035 25,314 Joint interest and other, net 13,577 8,266 Inventories 5,465 4,857 Prepaid expenses 336 1,195 Fair value of derivative contracts 151 406 ------------------- ------------------- Total current assets 40,841 54,029 Property and equipment, at cost: Oil and gas properties, based on successful efforts accounting 601,325 650,094 Gas gathering and processing facilities 49,600 748 Service properties, equipment and other 19,515 18,697 ------------------- ------------------- Total property and equipment 670,440 669,539 Less accumulated depreciation, depletion and amortization 231,008 249,155 ------------------- ------------------- Net property and equipment 439,432 420,384 Other assets: Debt issuance costs, net 4,707 4,755 Other assets 8 4 ------------------- ------------------- Total other assets 4,715 4,759 ------------------- ------------------- Total assets $ 484,988 $ 479,172 =================== =================== Liabilities and stockholders' equity Current liabilities: Accounts payable $ 27,950 $ 18,507 Current portion of long-term debt 5,776 3,348 Revenues and royalties payable 8,250 10,443 Accrued liabilities: Interest 6,312 6,313 Other 7,212 2,473 Fair value of derivative contracts 640 1,208 ------------------- ------------------- Total current liabilities 56,140 42,292 Long-term debt, net of current portion 285,144 289,560 Asset retirement obligation 26,608 27,167 Other noncurrent liabilities 164 171 Stockholders' equity: Preferred stock, $0.01 par value, 1,000,000 shares authorized, no shares issued and outstanding - - Common stock, $0.01 par value, 20,000,000 shares authorized, 14,368,919 shares issued and outstanding 144 144 Additional paid-in-capital 25,087 25,087 Retained earnings 92,190 95,956 Accumulated other comprehensive income (489) (1,205) ------------------- ------------------- Total stockholders' equity 116,932 119,982 ------------------- ------------------- Total liabilities and stockholders' equity $ 484,988 $ 479,172 =================== ===================
The accompanying notes are an integral part of these condensed consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) (Dollars in thousands, except share data)
Three Months Ended September 30, -------------------------------- 2003 2004 -------------- --------------- Revenues: (restated) Oil and gas sales $ 34,350 $ 47,900 Crude oil marketing and trading 39,698 46,422 Change in derivative fair value 519 - Oil and gas service operations 2,291 2,904 --------------- --------------- Total revenues 76,858 97,226 Operating costs and expenses: Production 10,127 10,328 Production taxes 2,551 3,196 Exploration 3,495 3,970 Crude oil marketing and trading 39,002 46,056 Oil and gas service operations 1,445 1,701 Depreciation, depletion and amortization of oil and gas properties 8,134 7,224 Depreciation and amortization of other property and equipment 368 352 Property impairments 1,309 5,363 Asset retirement obligation accretion 341 264 General and administrative 2,219 2,763 --------------- --------------- Total operating costs and expenses 68,991 81,217 Operating income 7,867 16,009 Other income (expense): Interest income 24 21 Interest expense (4,899) (5,369) Other income, net 13 598 Gain (loss) on disposition of assets 90 (38) --------------- --------------- Total other income (expense) (4,772) (4,788) --------------- --------------- Income from continuing operations $ 3,095 $ 11,221 Income (loss) from discontinued operations (63) 119 Loss on sale of discontinued operations - (632) --------------- --------------- Net income $ 3,032 $ 10,708 =============== =============== Basic earnings per common share Income from continuing operations $ 0.22 $ 0.78 Income from discontinued operations $ - $ 0.01 Loss on sale of discontinued operations $ - $ (0.04) --------------- --------------- Basic $ 0.22 $ 0.75 =============== =============== Diluted earnings per common share Income from continuing operations $ 0.21 $ 0.78 Income from discontinued operations $ - $ 0.01 Loss on sale of discontinued operations - $ (0.05) --------------- --------------- Diluted $ 0.21 $ 0.74 =============== ===============
The accompanying notes are an integral part of these condensed consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) (Dollars in thousands, except share data)
Nine Months Ended September 30, ------------------------------------ 2003 2004 ------------------------------------ Revenues: (restated) Oil and gas sales $ 103,419 $ 124,130 Crude oil marketing and trading 120,046 158,733 Change in derivative fair value 926 404 Oil and gas service operations 6,596 7,627 ------------------ ------------------ Total revenues 230,987 290,894 Operating costs and expenses: Production 29,882 30,955 Production taxes 7,586 8,414 Exploration 7,548 9,278 Crude oil marketing and trading 118,878 158,645 Oil and gas service operations 4,178 5,071 Depreciation, depletion and amortization of oil and gas properties 23,350 27,281 Depreciation and amortization of other property and equipment 1,436 1,052 Property impairments 3,861 9,062 Asset retirement obligation accretion 1,045 788 General and administrative 7,176 7,552 ------------------ ------------------ Total operating costs and expenses 204,940 258,098 Operating income 26,047 32,796 Other income (expense): Interest income 81 60 Interest expense (14,685) (15,725) Other income, net 60 629 Gain (loss) on disposition of assets 367 (141) ------------------ ------------------ Total other income (expense) (14,177) (15,177) ------------------ ------------------ Income from continuing operations 11,870 17,619 Discontinued operations 2,242 1,680 Loss on sale of discontinued operations - (632) ------------------ ------------------ Income before change in accounting principle 14,112 18,667 Cumulative effect of change in accounting principle 273 - ------------------ ------------------ Net income $ 14,385 $ 18,667 ================== ================== Basic earnings per common share: From continuing operations $ 0.83 $ 1.23 From discontinued operations $ 0.16 $ 0.11 Loss on sale of discontinued operations $ - $ (0.04) ------------------ ------------------ Before cumulative effect of change in accounting principle $ 0.99 $ 1.30 Cumulative effect of change in accounting principle $ 0.02 $ - ------------------ ------------------ Basic $ 1.01 $ 1.30 ================== ================== Diluted earnings per common share: From continuing operations $ 0.82 $ 1.22 From discontinued operations $ 0.16 $ 0.11 Loss on sale of discontinued operations $ - $ (0.04) ------------------ ------------------ Before cumulative effect of change in accounting principle $ 0.98 $ 1.29 Cumulative effect of change in accounting principle $ 0.02 $ - ------------------ ------------------ Diluted $ 1.00 $ 1.29 ================== ==================
The accompanying notes are an integral part of these condensed consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Dollars in thousands)
Nine Months Ended September 30, ---------------------------------- 2003 2004 ---------------- ---------------- Cash flows from operating activities: (restated) Net income $ 14,385 $ 18,667 Adjustments to reconcile net income to net cash provided by operating activities- Depreciation, depletion and amortization 26,953 30,346 Accretion of asset retirement obligation 1,055 788 Impairment of properties 3,861 9,062 Change in derivative fair value (926) (404) Amortization of debt issuance costs 1,190 1,290 (Gain) loss on disposition of assets (359) 1,066 Change in accounting principle (2,162) - Dry hole costs 4,834 7,153 Cash provided by (used in) changes in assets and liabilities- Accounts receivable (6,790) (969) Inventories (202) 608 Prepaid expenses 312 (859) Accounts payable 7,360 (9,442) Revenues and royalties payable 1,594 2,193 Accrued liabilities and other (2,359) (4,737) Other noncurrent liabilities 39 12 ---------------- ---------------- Net cash provided by operating activities 48,785 54,774 Cash flows from investing activities: Exploration and development (79,425) (56,686) Gas gathering and processing facilities and service properties, equipment and other (16,529) 3,364 Purchase of oil and gas properties (101) (627) Proceeds from disposition of assets 4,768 22,710 ---------------- ---------------- Net cash used in investing activities (91,287) (31,239) Cash flows from financing activities: Proceeds from line of credit and other debt 46,062 12,149 Repayment of debt (2,956) (7,732) Dividend to stockholders - (14,900) Paid-in capital - - Debt issuance costs (125) (1,338) ---------------- ---------------- Net cash provided by financing activities 42,981 (11,821) Net increase in cash 479 11,714 Cash and cash equivalents, beginning of year 2,520 2,277 ---------------- ---------------- Cash and cash equivalents, end of period $ 2,999 $ 13,991 ================ ================
The accompanying notes are an integral part of these condensed consolidated financial statements. CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. CONTINENTAL RESOURCES, INC.'S FINANCIAL STATEMENTS: Organization In the opinion of management of Continental Resources, Inc., or CRI, or the Company, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly the Company's financial position as of September 30, 2004, and the results of operations for the three and nine months ended September 30, 2003 and 2004, and cash flows for the nine months ended September 30, 2003 and 2004. Such adjustments are of a normal recurring nature. The unaudited condensed consolidated financial statements for the interim periods presented do not contain all information required by accounting principles generally accepted in the United States. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's annual report on form 10-K for the year ended December 31, 2003. Certain reclassifications have been made to prior year amounts to conform to the current year presentation. The Company is an S-Corporation under Subchapter S of the Internal Revenue Code. As a result, income taxes, if any, will be payable by the shareholders of the Company. Recent Accounting Standards In 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method and the liability should be accreted to its estimated amount. The primary impact of this standard relates to oil and gas wells on which the Company has a legal obligation to plug and abandon the wells. The Company adopted SFAS No. 143 on January 1, 2003, that originally resulted in a cumulative effect adjustment of a $4.1 million increase in net income. SFAS No. 143 requires the Company to make certain estimates, including estimates related to the future plugging costs of wells, the future salvage value of equipment, and estimated life of the Company's wells. In the fourth quarter of 2003, the Company made certain adjustments to its assumptions used in its initial SFAS No. 143 estimates to better reflect its future plugging costs and future salvage values. These changes resulted in a decrease in the cumulative effect adjustment from the $4.1 million originally reported during the quarter ended March 31, 2003, to $2.2 million. The following table details the amounts originally reported for the nine months ended September 30, 2003, compared to the current restated amount:
Nine Months Ended September 30, 2003 -------------------------------------------- (Dollars in thousands, except share data) Originally Reported Restated - -------------------------------------------------------------------------------- ---------------------- Net income before change in accounting principle $12,223 $12,223 Cumulative effect of change in accounting principle of continuing operations 1,953 273 Cumulative effect of change in accounting principle of discontinued operations 2,137 1,889 ---------------------- ---------------------- Net income $16,313 $14,385 Basic earnings per share $ 1.14 $ 1.01 Diluted earnings per share $ 1.13 $ 1.00
The following table shows the effect on net income and net income per share if the Company had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation:
Three Months Ended Nine Months Ended September 30, September 30, ---------------------------- -------------------------- (Dollars in thousands, except share data) 2003 2004 2003 2004 ---------- ----------- ----------- ---------- Net Income on continuing operations $ 3,148 $ 11,221 $ 11,870 $ 17,619 Net income on discontinued operations (116) 119 2,242 1,680 Loss of sale of discontinued operations - (632) - (632) Cumulative effect of change in accounting principle - - 273 - --------- ---------- ---------- ---------- Net Income, as reported $ 3,032 $ 10,708 $ 14,385 $ 18,667 Deduct: Total stock-based compensation expense determined under fair value based method for all awards relating to continuing operations (41) (54) (125) (161) Total stock-based compensation expense determined under fair value based method for all awards relating to discontinued operations (8) (10) (23) (29) --------- ---------- ---------- ---------- Pro Forma, net income $ 2,983 $ 10,644 $ 14,237 $ 18,477 ========= ========== ========== ========== Basic earnings from continuing operations for common stockholders per common share: As reported $ 0.22 $ 0.78 $ 0.83 $ 1.23 Pro forma $ 0.21 $ 0.78 $ 0.82 $ 1.21 Diluted earnings from continuing operations for common stockholders per common share: As reported $ 0.21 $ 0.78 $ 0.82 $ 1.22 Pro forma $ 0.21 $ 0.77 $ 0.81 $ 1.21 Basic earnings for common stockholders per common share: As reported $ 0.22 $ 0.75 $ 1.01 $ 1.30 Pro forma $ 0.21 $ 0.74 $ 0.99 $ 1.29 Diluted earnings for common stockholders per common share: As reported $ 0.21 $ 0.74 $ 1.00 $ 1.29 Pro forma $ 0.21 $ 0.74 $ 0.98 $ 1.28
2. ACQUISITIONS AND OTHER SIGNIFICANT EVENTS: On July 19, 2004, the Company paid a cash dividend of $14.9 million to its shareholders. On July 21, 2004, the Company completed the sale of all of the outstanding stock in CGI to the Company's shareholders, (the "Buyers") for $22.6 million in cash. The sales price was representative of the fair value of the net assets based on an appraisal by an independent third party who also provided the Company with an opinion of the fairness from a financial point of view, of the sale of CGI to the Buyers. The CGI assets included seven gas gathering systems, three gas-processing plants, and approximately 750 miles of gas gathering lines. These assets represented the entire gas gathering, marketing and processing segment of the Company. The assets and liabilities of CGI included within the related discontinued operations are as follows (dollars in thousands):
July 21 2004 ------- Cash $ 1,681 Accounts receivable 9,592 Inventories 153 Prepaid expenses 4 ------- Total current assets of discontinued operations $11,430 Property and equipment, net $38,894 Other noncurrent assets 225 ------- Total noncurrent assets of discontinued operations $39,119 ------- Total assets $50,549 ======= Accounts Payable $10,566 Current portion of long-term debt 2,429 Accrued expense and other current liabilities 92 ------- Total current liabilities of discontinued $13,087 Long-term debt, net of current portion $13,357 Other noncurrent liabilities 377 ------- Total noncurrent liabilities of discontinued operations $13,734 Stockholder's equity $23,728 ------- Total liabilities and stockholder's equity $50,549 =======
The results of operations of CGI prior to its disposition are included within income from discontinued operations in the following periods (dollars in thousands):
Three Months Ended Nine Months Ended September 30, September 30, 2003 2004 2003 2004 --------- --------- --------- -------- Revenues $ 23,407 $ 6,057 $ 51,767 $ 50,956 Net Income (Loss) (63) (513) 2,242 1,048
CGI operations are reported through July 21, 2004, the date of the sale of the CGI stock. The loss on disposition of discontinued operations was $632,000. 3. LONG-TERM DEBT: Long-term debt as of December 31, 2003, and September 30, 2004, consisted of the following:
December 31, September 30, 2003 2004 (Dollars in thousands) ------------ ------------- 10.25% Senior Subordinated Notes due Aug.1, 2008 $127,150 $119,500 Credit Facility due March 31, 2007 132,900 137,049 Credit Facility due March 31, 2006 - 25,000 Credit Facility due September 30, 2006 17,000 - Capital Lease Agreement 13,827 11,325 Ford Credit 43 34 ------------ ------------- Outstanding Debt 290,920 292,908 Less Current Portion 5,776 3,348 ------------ ------------- Total Long-Term Debt $285,144 $289,560 ============ =============
On March 31, 2002, the Company entered into a Fourth Amended and Restated Credit Agreement (the "Credit Agreement") providing for a $175.0 million senior secured revolving credit facility with a borrowing base of $150.0 million. Borrowings under the Credit Agreement are secured by liens on all oil and gas properties and associated assets of the Company. Borrowings under the Credit Agreement bear interest, payable quarterly, at (a) a rate per annum equal to the rate at which eurodollar deposits for one, two, three or six months are offered by the lead bank plus a margin ranging from 150 to 250 basis points, or (b) at the lead bank's reference rate plus an applicable margin ranging from 25 to 50 basis points. At September 30, 2004, the lead bank's reference rate plus margins on the revolving credit facility was 3.96%. The Company paid approximately $2.2 million in debt issuance fees for the credit facility, which have been capitalized as other assets and are being amortized on a straight-line basis over the life of the Credit Agreement. The credit facility maturity date was extended on April 14, 2004, to March 31, 2007. At November 15, 2004, the outstanding balance under the revolving loan facility of the Credit Agreement was $137.0 million. On October 22, 2003, the Company executed the Second Amendment to the Credit Agreement and CGI was removed as a guarantor of the Company's obligations under the Credit Agreement. The borrowing base under the Second Amendment to the Credit Agreement was revised to $145.0 million and $17.0 million funded by CGI as disclosed below reduced the outstanding balance. On April 14, 2004, the Company executed the Third Amendment to the Credit Agreement that provided for the addition of a term facility in an amount up to $25.0 million that matures on March 31, 2006. The amendment increased the borrowing base to $150.0 million. Borrowings under the term facility have margins of 5.5% on LIBOR loans and 3% on reference rate loans. On April 14, 2004, the Company drew $25.0 million on the term facility and paid down the balance of the revolving credit facility. At September 30, 2004, the lead bank's reference rate plus margins on this term credit facility was 7.25%. At November 15, 2004, the outstanding balance on the term loan was $25.0 million. On July 21, 2004, the Company executed the Fourth Amendment to the Credit Agreement that modified the definitions to delete any reference to CGI. On October 22, 2003, CGI entered into a new $35.0 million secured credit facility consisting of a senior secured term loan facility of up to $25.0 million, and a senior revolving credit facility of up to $10.0 million. The initial advance under the term loan facility was $17.0 million, which CGI paid to CRI who used the payment to reduce the outstanding balance on CRI's credit facility. No funds were initially advanced under the revolving loan facility. At September 30, 2004, CRI was not a guarantor and had no obligation under the CGI credit facility. On July 21, 2004, CRI sold all of the outstanding capital stock of CGI, to CRI's shareholders for $22.6 million in cash. The sales price was representative of the fair value of the net assets based on an appraisal by an independent third party who also provided the Company with an opinion of the fairness from a financial point of view, of the sale of CGI. The CGI assets included seven gas gathering systems, three gas-processing plants, and approximately 750 miles of gas gathering lines. These assets represented the Company's entire gas gathering, marketing and processing segment. On September 3, 2004, the Company executed the Fifth Amendment to the Credit Agreement that contained a one-time waiver of the requirement to comply with the hedging covenant set forth in Section 5.35 of the Credit Agreement, which states, the Company should maintain hedge agreements for at least 50% of the oil estimated to be produced during the ensuing six-month period, on a rolling six-month basis. The waiver is effective only until the earlier of: (i) the date on which the Administrative Agent, on behalf of the Required Banks, provides the Company written notice that the covenant set forth in Section 5.35 is to be reinstated and (ii) the last business day of any period of ten (10) consecutive business days during which the 6-month NYMEX strip price for light, sweet crude oil has averaged less than or equal to $30.00 per barrel. 4. DERIVATIVE CONTRACTS: The Company utilizes derivative contracts, consisting primarily of fixed price physical delivery contracts, fixed price basis contracts, collars and floors to reduce its exposure to unfavorable changes in oil and gas prices that are subject to significant and often volatile fluctuation. Under fixed price physical delivery contracts, the Company receives the fixed price stated in the contract. Under the fixed price basis contracts, the price the Company receives is determined based on a published index price plus or minus a fixed basis. Under collars and floors, if the market price of crude oil exceeds the ceiling strike price or falls below the floor strike price, then the Company receives the fixed price ceiling or floor. If the market price is between the floor strike price and the ceiling strike price, the Company receives market price. The Company has designated its fixed price physical delivery contracts and fixed price basis contracts as "normal sales" contracts under SFAS No. 133, Accounting for Derivative and Hedging Activities and are therefore not marked to market as derivatives. The Company's collars and floors have been designated as cash flow hedges under SFAS No. 133 and are being accounted for accordingly. At September 30, 2004, the Company had no fixed price physical delivery contracts in place. The following table summarizes the Company's collars and floors in place at September 30, 2004:
Crude Oil Collars and Floors for 2004: Contract Weighted-average Volumes (Bbls) Fixed Price per Bbl ---------------- ------------------ Oct Floor 116,000 $ 22.00 Oct Floor 100,000 $ 24.00 Nov - Dec, Floor 230,000 $ 24.50 ----------------- 446,000 ================= Oct Ceiling 100,000 $ 36.00 Nov - Dec, Ceiling 230,000 $ 45.00 ----------------- 330,000 =================
The Company engages in a series of contracts in order to exchange its crude oil production in the Rocky Mountain area for equal quantities of crude oil located at Cushing, Oklahoma. Such activity enables the Company to take advantage of better pricing and reduce the Company's credit risk associated with its first purchaser. This purchase and sale activity is presented gross in the accompanying income statement as crude oil marketing revenues and expenses under the guidance provided by Emerging Issues Task Force Consensus 99-19, Reporting Revenues Gross as a Principal and Net as an Agent. Additionally, in the first quarter of 2004, the Company engaged in certain crude oil trading activities, exclusive of its own production, utilizing fixed price and variable priced physical delivery contracts. The Company's derivatives associated with this activity are being marked to market with all changes in fair value being recorded in the income statement under the accounting prescribed by SFAS No. 133, Accounting for Derivative and Hedging Activities. At September 30, 2004, the Company had closed its open trading positions, resulting in a gain of $404,100 on such contracts. 5. ASSET RETIREMENT OBLIGATIONS: Asset retirement obligations include plugging, abandonment, decommission and remediation costs, which are included in property and equipment. The following is reconciliation at September 30, 2004, of the asset retirement obligation liability (dollars in thousands):
2003 2004 ------------- ------------ (restated) Asset Retirement Obligation liability at January 1, $ 23,966 $ 26,608 Asset Retirement Obligation accretion expense 1,055 797 Plus: Additions for new assets 1,807 418 Less: Plugging costs and sold assets (777) (656) ------------- ------------ Asset Retirement Obligation liability at September 30, $ 26,051 $ 27,167 ============= ============
6. EARNINGS PER SHARE: Basic earnings per common share is computed by dividing income available to common shareholders by the weighted-average number of shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if stock options were exercised, using the treasury stock method of calculation. The weighted-average number of shares used to compute basic earnings per common share was 14,368,919 for the three and nine months ended September 30, 2003 and 2004. The weighted-average number of shares used to compute diluted earnings per share was 14,463,210 for the three and nine months ended September 30, 2003, and 14,439,053 for the three and nine months ended September 30, 2004. 7. GUARANTOR SUBSIDIARIES: The Company's wholly owned subsidiaries, Continental Resources of Illinois, Inc. (CRII), and Continental Crude Co. (CCC), have guaranteed the Company's obligations under its outstanding 10 1/4% Senior Subordinated Notes due August 1, 2008. CCC has not engaged in any business activities since its inception. The following is a summary of the condensed consolidating balance sheets of the Company and its guarantor subsidiaries as of December 31, 2003, and September 30, 2004, and the results of operations and cash flows for the three-month and nine-month periods ended September 30, 2003, and 2004. As of December 31, 2003 Condensed Consolidating Balance Sheet - --------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Current Assets $ 11,162 $ 44,428 $(14,749) $ 40,841 Property and Equipment 58,826 380,606 - 439,432 Other Assets 281 4,448 (14) 4,715 -------- -------- -------- -------- Total Assets $ 70,269 $429,482 $(14,763) $484,988 Current Liabilities $ 18,512 $ 44,694 $ (7,066) $ 56,140 Long-Term Debt 22,286 270,541 (7,683) 285,144 Other Liabilities 4,943 21,829 - 26,772 Stockholders' Equity 24,528 92,418 (14) 116,932 -------- -------- -------- -------- Total Liabilities and Stockholders' Equity $ 70,269 $429,482 $(14,763) $484,988 ======== ======== ======== ========
As of September 30, 2004 Condensed Consolidating Balance Sheet - ---------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Current Assets $ 4,340 $ 62,388 $(12,699) $ 54,029 Property and Equipment 17,874 402,510 - 420,384 Other Assets 3 4,759 (3) 4,759 -------- -------- -------- -------- Total Assets $ 22,217 $469,657 $(12,702) $479,172 Current Liabilities $ 4,045 $ 41,549 $ (3,302) $ 42,292 Long-Term Debt 9,419 289,538 (9,397) 289,560 Other Liabilities 4,703 22,635 - 27,338 Stockholders' Equity 4,050 115,935 (3) 119,982 -------- -------- -------- -------- Total Liabilities and Stockholders' Equity $ 22,217 $469,657 $(12,702) $479,172 ======== ======== ======== ========
For the Three Months Ended September 30, 2003 Condensed Consolidating Income Statement - ---------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Total Revenue $ 3,158 $ 73,700 $ - $ 76,858 Operating Expense (2,725) (66,266) - (68,991) Other Expense (293) (4,479) - (4,772) -------- -------- -------- -------- Net Income from continuing operations 140 2,955 - 3,095 Net Income from discontinued operations (63) - - (63) -------- -------- -------- -------- Net Income $ 77 $ 2,955 $ - $ 3,032 ======== ======== ======== ========
For the Three Months Ended September 30, 2004 Condensed Consolidating Income Statement - ---------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Total Revenue $ 3,863 $ 93,363 $ - $ 97,226 Operating Expense (2,473) (78,744) - (81,217) Other Expense (155) (4,633) - (4,788) -------- -------- -------- -------- Net Income from continuing operations 1,235 9,986 - 11,221 Net Income from discontinued operations 119 - - 119 Loss on sale of discontinued operations (632) - - (632) -------- -------- -------- -------- Net Income $ 722 $ 9,986 $ - $ 10,708 ======== ======== ======== ========
For the Nine Months Ended September 30, 2003 Condensed Consolidating Income Statement - ---------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Total Revenue $ 10,224 $220,763 $ - $230,987 Operating Expense (7,366) (197,574) - (204,940) Other Expense (847) (13,330) - (14,177) Cumulative Effect of Change in Accounting Principle (1,939) 2,212 - 273 -------- -------- -------- -------- Net Income from continuing operations 72 12,071 - 12,143 Net Income from discontinued operations 2,242 - - 2,242 -------- -------- -------- -------- Net Income $ 2,314 $ 12,071 $ - $ 14,385 ======== ======== ======== ========
For the Nine Months Ended September 30, 2004 Condensed Consolidating Income Statement - ---------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Total Revenue $ 10,890 $280,004 $ - $290,894 Operating Expense (7,245) (250,853) - (258,098) Other Expense (421) (14,756) - (15,177) -------- -------- -------- -------- Net Income from continuing operations 3,224 14,395 - 17,619 Net Income from discontinued operations 1,680 - - 1,680 Loss on sale of discontinued operations (632) - - (632) -------- -------- -------- -------- Net Income $ 4,272 $ 14,395 $ - $ 18,667 ======== ======== ======== ========
For the Nine Months Ended September 30, 2003 Condensed Consolidated Cash Flows Statements - ---------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Cash Flows From Operating Activities $ 7,357 $ 74,104 $(32,676) $ 48,785 Cash Flows From Investing Activities (16,878) (74,409) - (91,287) Cash Flows From Financing Activities 9,924 33,057 - 42,981 -------- -------- -------- -------- Net Increase (Decrease) in Cash 403 32,752 (32,676) 479 Cash at Beginning of Period 456 2,064 - 2,520 -------- -------- -------- -------- Cash at End of Period $ 859 $ 34,816 $(32,676) $ 2,999 ======== ======== ======== ========
For the Nine Months Ended September 30, 2004 Condensed Consolidated Cash Flow Statements - ---------------------------------------------------------------------------------------------
($ in thousands) Guarantor Subsidiaries Parent Eliminations Consolidated ---------------------------------------------------------------- Cash Flow From Operating Activities $ 9,710 $ 47,028 $ (1,964) $ 54,774 Cash Flow From Investing Activities 7,948 (39,187) - (31,239) Cash Flow From Financing Activities (16,326) 2,541 1,964 (11,821) -------- -------- -------- -------- Net Increase in Cash 1,332 10,382 - 11,714 Cash at Beginning of Period 702 1,575 - 2,277 -------- -------- -------- -------- Cash at End of Period $ 2,034 $ 11,957 $ - $ 13,991 ======== ======== ======== ========
8. BUSINESS SEGMENTS: As a result of the sale of CGI, the Company's only reportable segment pursuant to Statement of Financial Accounting Standards (SFAS) No. 131, Disclosure About Segments of an Enterprise and Related Information, is exploration and production. The gas gathering, marketing and processing segment is presented as discontinued operations. The Company's reportable business segments were identified based on the differences in products or services provided. Revenues from the exploration and production segment are derived from the production and sale of crude oil and natural gas. Revenues from the gas gathering, marketing and processing segment came from the transportation and sale of natural gas and natural gas liquids at retail. The accounting policies of the segments are the same. Financial information by operating segment is presented below:
Exploration For the Three Months Ended and Discontinued September 30, 2003 Production Operations Intersegment Total - ------------------------------------------- ------------ ----------- ------------ ---------- (Dollars in thousands) REVENUES: Oil and gas sales $ 34,350 $ - $ - $ 34,350 Crude oil marketing and trading 39,698 - - 39,698 Change in derivative fair value 519 - - 519 Gas gathering, marketing and processing - 23,407 (123) 23,284 Oil and gas service operations 2,291 - - 2,291 --------- --------- --------- --------- Total revenues $ 76,858 $ 23,407 $ (123) $ 100,142 OPERATING COSTS AND EXPENSES: Production expenses 10,127 - - 10,127 Production taxes 2,551 - - 2,551 Exploration 3,495 - - 3,495 Crude oil marketing and trading 39,002 - - 39,002 Gas gathering, marketing and processing - 22,198 (123) 22,075 Oil and gas service operations 1,445 - - 1,445 Depreciation, depletion and amortization of oil and gas properties 8,134 - - 8,134 Depreciation and amortization of other property and equipment 368 856 - 1,224 Property impairments 1,309 - - 1,309 Asset retirement accretion 341 5 - 346 General and administrative 2,219 236 - 2,455 --------- --------- --------- --------- Total operating costs and expenses $ 68,991 $ 23,295 $ (123) $ 92,163 Total operating income $ 7,867 $ 112 $ - $ 7,979 OTHER INCOME (EXPENSE): Interest income 477 2 (454) 25 Interest expense (5,352) (177) 454 (5,075) Other income, net 13 - - 13 Gain on disposition of assets 90 - - 90 --------- --------- --------- --------- Total other income (expense) $ (4,772) $ (175) $ - $ (4,947) Net income (loss) $ 3,095 $ (63) $ - $ 3,032 ========= ========= ========= ========= Total assets $ 450,362 $ 49,389 $ (14,763) $ 484,988 ========= ========= ========= ========= Capital expenditures $ 29,974 $ 13,353 $ - $ 43,327 ========= ========= ========= =========
Exploration For the Three Months Ended and Discontinued September 30, 2003 Production Operations Intersegment Total - ------------------------------------------- ------------ ----------- ------------ ---------- (Dollars in thousands) REVENUES: Oil and gas sales $ 47,900 $ - $ - $ 47,900 Crude oil marketing and trading 46,422 - - 46,422 Change in derivative fair value - - - - Gas gathering, marketing and processing - 6,057 (1,022) 5,035 Oil and gas service operations 2,904 - - 2,904 --------- --------- --------- --------- Total revenues $ 97,226 $ 6,057 $ (1,022) $ 102,261 OPERATING COSTS AND EXPENSES: Production expenses 10,328 - - 10,328 Production taxes 3,196 - - 3,196 Exploration 3,970 - - 3,970 Crude oil marketing and trading 46,056 - - 46,056 Gas gathering, marketing and processing - 5,302 (1,022) 4,280 Oil and gas service operations 1,701 - - 1,701 Depreciation, depletion and amortization of oil and gas properties 7,224 - - 7,224 Depreciation and amortization of other property and equipment 352 248 - 600 Property impairments 5,363 - - 5,363 Asset retirement accretion 264 (7) - 257 General and administrative 2,763 60 - 2,823 --------- --------- --------- --------- Total operating costs and expenses $ 81,217 $ 5,603 $ (1,022) $ 85,798 Total operating income $ 16,009 $ 454 $ - $ 16,463 OTHER INCOME (EXPENSE): Interest income 153 1 (132) 22 Interest expense (5,502) (43) 132 (5,413) Other income, net 598 2 - 600 Loss on disposition of assets (37) (927) - (964) --------- --------- --------- --------- Total other income (expense) $ (4,788) $ (967) $ - $ (5,755) Net income (loss) $ 11,221 $ (513) $ - $ 10,708 ========= ========= ========= ========= Total assets $ 491,874 $ - $ (12,702) $ 479,172 ========= ========= ========= ========= Capital expenditures $ 21,134 $ - $ - $ 21,134 ========= ========= ========= =========
Exploration For the None Months Ended and Discontinued September 30, 2003 Production Operations Intersegment Total - ------------------------------------------- ------------ ----------- ------------ ---------- (Dollars in thousands) REVENUE: Oil and gas sales $ 103,419 $ - $ - $ 103,419 Crude oil marketing and trading 120,046 - - 120,046 Change in derivative fair value 926 - - 926 Gas gathering, marketing and processing - 51,767 (1,633) 50,134 Oil and gas service operations 6,596 - - 6,596 --------- --------- --------- --------- Total revenues $ 230,987 $ 51,767 $ (1,633) $ 281,121 OPERATING COSTS AND EXPENSES: Production expenses 29,882 - - 29,882 Production taxes 7,586 - - 7,586 Exploration 7,548 - - 7,548 Crude oil marketing and trading 118,878 - - 118,878 Gas gathering, marketing and processing - 48,330 (1,633) 46,697 Oil and gas service operations 4,178 - - 4,178 Depreciation, depletion and amortization of oil and gas properties 23,350 - - 23,350 Depreciation and amortization of other property and equipment 1,436 2,167 - 3,603 Property impairments 3,861 - - 3,861 Asset retirement accretion 1,045 10 - 1,055 General and administrative 7,176 601 - 7,777 --------- --------- --------- --------- Total operating costs and expenses $ 204,940 $ 51,108 $ (1,633) $ 254,415 Total operating income $ 26,047 $ 659 $ - $ 26,706 OTHER INCOME (EXPENSE): Interest income 1,289 5 (1,208) 86 Interest expense (15,893) (306) 1,208 (14,991) Other income, net 60 3 63 Gain (loss) on disposition of assets 367 (8) - 359 --------- --------- --------- --------- Total other income (expense) $ (14,177) $ (306) $ - $ (14,483) Total income from operations $ 11,870 $ 353 $ - $ 12,223 --------- --------- --------- --------- Cumulative effect of change in accounting principle 273 1,889 2,162 Net income $ 12,143 $ 2,242 $ - $ 14,385 ========= ========= ========= ========= Total assets $ 450,362 $ 49,389 $ (14,763) $ 484,988 ========= ========= ========= ========= Capital expenditures $ 79,886 $ 16,169 $ - $ 96,055 ========= ========= ========= =========
Exploration For the Nine Months Ended and Discontinued September 30, 2004 Production Operations Intersegment Total - ------------------------------------------- ------------ ----------- ------------ ---------- (Dollars in thousands) REVENUES: Oil and gas sales $ 124,130 $ - $ - $ 124,130 Crude oil marketing and trading 158,733 - - 158,733 Change in derivative fair value 404 - - 404 Gas gathering, marketing and processing - 50,956 (10,620) 40,336 Oil and gas service operations 7,627 - - 7,627 --------- --------- --------- --------- Total revenues $ 290,894 $ 50,956 $ (10,620) $ 331,230 OPERATING COSTS AND EXPENSES: Production expenses 30,955 - - 30,955 Production taxes 8,414 - - 8,414 Exploration 9,278 - - 9,278 Crude oil marketing and trading 158,645 - - 158,645 Gas gathering, marketing and processing - 46,008 (10,620) 35,388 Oil and gas service operations 5,071 - - 5,071 Depreciation, depletion and amortization of oil and gas properties 27,281 - - 27,281 Depreciation and amortization of other property and equipment 1,052 1,996 - 3,048 Property impairments 9,062 - - 9,062 Asset retirement accretion 788 1 - 789 General and administrative 7,552 566 - 8,118 --------- --------- --------- --------- Total operating costs and expenses $ 258,098 $ 48,571 $ (10,620) $ 296,049 Total operating income $ 32,796 $ 2,385 $ - $ 35,181 OTHER INCOME (EXPENSE): Interest income 545 5 (485) 65 Interest expense (16,210) (428) 485 (16,153) Other income, net 629 13 642 Loss on disposition of assets (141) (927) - (1,068) --------- --------- --------- --------- Total other income (expense) $ (15,177) $ (1,337) $ - $ (16,514) Net income $ 17,619 $ 1,048 $ - $ 18,667 ========= ========= ========= ========= Total assets $ 491,874 $ - $ (12,702) $ 479,172 ========= ========= ========= ========= Capital expenditures $ 59,608 $ 3,430 $ - $ 63,038 ========= ========= ========= =========
9. COMPREHENSIVE INCOME: The components of total comprehensive income for the three and nine months ended September 30, 2003 and 2004 are as follows:
Three Months Ended September 30, Nine Months Ended September 30, --------------------------------------- --------------------------------------- 2003 2004 2003 2004 --------------------------------------- --------------------------------------- (Dollars in thousands) (restated) (restated) Net Income $ 3,032 $ 10,708 $ 14,385 $ 18,667 Other Comprehensive Income (Loss) - net of income tax: Deferred Hedging Loss - (558) - (1,205) --------------------------------------- --------------------------------------- Total Comprehensive Income $ 3,032 $ 10,150 $ 14,385 $ 17,462 ======================================= =======================================
10. SUBSEQUENT EVENTS: On October 6, 2004, CRI notified the Trustee under the Indenture dated July 24, 1998, that the Company would redeem all of its outstanding 10 1/4% Senior Subordinated Notes due 2008 on November 22, 2004, pursuant to the optional redemption provisions contained in Section 3.7 of the indenture. The outstanding principal amount of the Senior Subordinated Notes is $119.5 million. The Company expects a loss on the early redemption of $4.1 million and a write off of debt issuance costs of $2.8 million. The Company is negotiating a new, $250.0 million credit facility and will use borrowings under the new credit facility as well as a loan from the Company's principal shareholders to redeem the Senior Subordinated Notes. Due to the sale of CGI, a meeting was held on October 8, 2004, and the Company agreed to pay the president of CGI $687,500 for his stock options. On July 21, 2004, CRI acquired $7.65 million of its 10 1/4% Senior Subordinated Notes due August 1, 2008, from its principal shareholder and certain of his affiliates. These Notes were retired on October 20, 2004. Through November 15, 2004, CRI has purchased and retired an aggregate of $30.5 million principal amount of its Senior Subordinated Notes. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements, and the notes thereto that appear elsewhere in this report, and our annual report on Form 10-K for the year ended December 31, 2003. Our operating results for the periods discussed may not be indicative of future performance. Statements concerning future results are forward-looking statements. In the text below, financial statement numbers have been rounded; however, the percentage changes are based on amounts that have not been rounded. OVERVIEW We foresee continued growth through the end of 2004. During 2004, we have experienced relatively high oil and gas prices coupled with increases in production, which we expect to continue for the remainder of 2004. Our Cedar Hills North Unit and West Cedar Hills Unit are responding to high-pressure air injection, or HPAI, and to water injection, substantially as initially forecast by our resource development group. Our oil production in the Cedar Hills Units at September 30, 2004, was approximately 4,731 Bbls per day, an increase of 2,148 Bbls per day, or BOPD, since November 2003, and approximately 3,000 BOPD over projected primary rates of production without enhanced recovery. During the nine months ended September 30, 2004, 17.5 million net barrels of reserves in the Cedar Hills Units were moved from proved undeveloped, or PUD, reserves to proved developed producing, or PDP, reserves and 10.1 million net barrels were re-classified to proved developed non-producing, or PDNP, reserves from PUD reserves. Currently, we anticipate that the 10.1 million barrels will be re-classified to PDP by mid-year 2005 as response to HPAI continues. In addition, we expect our oil production in the Cedar Hills Units, on a daily basis, to reach 6,200 BOPD by the end of 2004 and to exceed 7,100 BOPD by mid-year 2005. The following table reflects our production from the Cedar Hills Units beginning in November 2003, when we first experienced HPAI response, through September 2004:
Monthly Production (Bbls) ---------------------------- Increase Property Nov 2003 Sep 2004 Bbls per Day - --------------------- ---------------------------- ------------- Cedar Hills North Unit 69,800 132,790 2,100 West Cedar Hills Unit 7,700 9,145 48 ---------------------------------------- Total 77,500 141,935 2,148
Currently, lifting costs in our Rocky Mountain region are significantly higher than our historic average due to the energy costs and other associated costs used in HPAI recovery, coupled with the conversion of producing wells to injector wells to complete the injection pattern engineered for the field. Thus, less production is available at a time when injection costs are high. However, lifting costs per barrel have been declining dramatically in the Rocky Mountain region as response and increased production continues. We project a reduction of more than $5.00 per barrel in lifting costs for the Rocky Mountain region by late 2004 or early 2005. Excluding Cedar Hills, we completed 23 wells during the third quarter of 2004, resulting in 17 producers and 6 dry holes for a success rate of 74% for the quarter. Of these 17 wells, 5 are located in the Rocky Mountain region, 10 wells are in the Mid-Continent region and 2 wells are in the Gulf Coast region. In the Rockies, the Paula 1-7H completed flowing rates as high as 1,050 BOPD and 400 MCFD. CRI owns 71% working interest in the Paula 1-7H. The Fink Farms 1-29H, in which CRI has a 39% working interest, completed flowing approximately 800 BOPD and 400 MCFD. In the Mid Continent region, the Jackal 1-16, which CRI owns 50% working interest, completed flowing at rates up to 825MCFD. In the Gulf Coast the JISM #5 well logged 400-500 net feet of productive sands and is producing 200BOPD and 400MCFD from the first 30 feet of perforation from the lowest of the pay sands. CRI owns 50% working interest in the JISM #5. We currently have 5 wells drilling and 4 wells waiting on completion. We continue to experience 100% success drilling wells in our Middle Bakken, or MB project, located in Richland County, Montana. Since completing our first well in the third quarter of 2003, we have drilled and completed 12 wells, (7.2 net wells) to date. These wells have added an estimated 6.6 MMBOE of gross PDP reserves (2.9 MMBOE net) for an average of 550 MBOE per gross well. These reserve figures are in line with expectations. Initial flow rates have ranged from 400 BOPD to 1,600 BOPD. We currently own approximately 93,000 net acres in the MB project with an inventory of 124 gross well locations (62 net wells) to be drilled. During the fourth quarter of 2004, we will be adding a fourth rig and anticipate completing an additional 6 wells (4.4 net wells) bringing the total producing well count in the MB project to 18 gross wells (11.6 net wells) by year-end 2004. Using the MB project as our model, we have expanded our search for Bakken oil reserves into North Dakota. During the first three quarters of 2004, we have invested approximately $8.7 million acquiring 232,000 net leasehold acres on opportunities in North Dakota identified by our geotechnical staff. Late in the third quarter, we elected to lease additional acreage in select areas in response to positive results. This leasing targets an additional 10,000 net acres with projected expenditures under $1.0 million. The net reserve potential of these new leases could exceed those in the MB project but remains unproven at this time. As a result of the additional leasing in MB and the new North Dakota projects, leasing expenditures for 2004 are projected to total an estimated $21.0 million or $13.3 million over the $7.7 million originally budgeted for the year. During the third quarter 2004, our subsidiary CRII, initiated development of two waterflood projects and performed several workovers on existing properties. The Cypress Bend property that we acquired during the second quarter of 2004 became operational effective November 1, 2004. We initiated development of the Aux Vases and Lower Renault reservoirs for water flooding in the third quarter of 2004. The Peabody-Stovall properties were also unitized, and installation of a Paint Creek reservoir waterflood is currently underway. The Peabody-Stovall Waterflood Unit will become effective on December 1, 2004 and is scheduled for first injection by the year-end 2004. There was also continued development of the Roland Unit Waterflood, with the Benoist zone injection beginning during the third quarter 2004. Additional workovers within the Roland Unit were also performed to clean out and acid stimulate producing wells. During the third quarter, CRII performed a total of eight workovers/conversions throughout its property base. Additional workovers are targeted for the fourth quarter 2004. In the third quarter of 2004, drilling activity increased as CRII drilled two wells. Both wells were drilled and abandoned Warsaw tests in Posey County, Indiana. The Wolf #2 also in Posey County was a re-entry and resulted in an O'Hara lime producing well. CRII participated in the drilling of three non-operated wells. The Hermann #1 was a drilled and abandoned Warsaw test in Posey County, Indiana, while the drilling of two development wells in Franklin County, Illinois were completed and put on production. CRII has scheduled eight prospects for drilling in the fourth quarter of this year. The differential between the NYMEX oil price and the price received by Continental Resources of Illinois, Inc. for Illinois Basin oil continues to increase. Work is ongoing with several options to decrease this differential. Our capital expenditure budget for 2004 is $83.3 million. Through the first nine months of 2004, our aggregate capital expenditures were $65.3 million. THREE MONTHS ENDED SEPTEMBER 30, 2003, COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 Certain reclassifications have been made to prior year amounts to conform to the current year presentation. The following reflects our income and expense from operations for the third quarter of 2004 compared to the third quarter of 2003 with dollar and percentage increases or decreases:
Three Months Ended September 30, ------------------------------------ Increase Increase REVENUES: 2003 2004 (Decrease) (Decrease) -------------------- ---------------- ------------------- ------------ Oil and gas sales $ 34,350 $ 47,900 $ 13,550 39.45 Crude oil marketing and trading 39,698 46,422 6,724 16.94% Change in derivative fair value 519 - (519) -100.00% Oil and gas service operations 2,291 2,904 613 26.76% -------------------- ---------------- ----------------- ------------ Total revenues $ 76,858 $ 97,226 $ 20,368 26.50% OPERATING COSTS AND EXPENSES: Production $ 10,127 $ 10,328 $ 201 1.98% Production taxes 2,551 3,196 645 25.28% Exploration 3,495 3,970 475 13.59% Crude oil marketing and trading 39,002 46,056 7,054 18.09% Oil and gas service operations 1,445 1,701 256 17.72% DD&A of oil and gas properties 8,134 7,224 (910) -11.19% D&A of other assets 368 352 (16) -4.35% Property impairments 1,309 5,363 4,054 309.70% Asset retirement obligation accretion 341 264 (77) -22.58% General and administrative 2,219 2,763 544 24.52% -------------------- ---------------- ----------------- ------------ Total operating costs and expenses $ 68,991 $ 81,217 $ 12,226 17.72% OPERATING INCOME $ 7,867 $ 16,009 $ 8,142 103.50% OTHER INCOME (EXPENSE): Interest income $ 24 $ 21 $ (3) -12.50% Interest expense (4,899) (5,369) (470) 9.59% Other income, net 13 598 585 - Gain (loss) on disposition of assets 90 (38) (128) - -------------------- ---------------- ----------------- ------------ Total other income (expense) $ (4,772) $ (4,788) $ (16) - INCOME FROM CONTINUING OPERATIONS $ 3,095 $ 11,221 $ 8,126 262.55% INCOME FROM DISCONTINUED OPERATIONS (63) 119 182 - LOSS ON DISCONTINUED OPERATIONS - (632) (632) - -------------------- ---------------- ----------------- ------------ NET INCOME $ 3,032 $ 10,708 $ 7,676 253.17% ==================== ================ ================= ============
RESULTS OF OPERATIONS The following table sets forth certain information regarding our production volumes, oil and gas sales, average sales prices and expenses for the periods indicated:
For the Three Months Ended September 30, ---------------------- 2003 2004 ---------------------- NET PRODUCTION: Oil (MBbl) 854 964 Gas (MMcf) 2,537 2,243 Oil equivalent (MBoe) 1,277 1,338 OIL AND GAS SALES (dollars in thousands) Oil sales, excluding hedges $ 23,920 $ 39,438 Hedges (1,293) (2,764) -------- -------- Total oil sales, including hedges 22,627 36,674 Gas sales 11,724 11,226 -------- -------- Total oil and gas sales $ 34,351 $ 47,900 ======== ======== AVERAGE SALES PRICE: Oil, excluding hedges (dollar per barrel) $ 28.01 $ 40.91 Oil, including hedges (dollar per barrel) $ 26.50 $ 38.04 Gas (dollar per Mcf) $ 4.62 $ 5.00 Oil equivalent, excluding hedges (dollar per Boe) $ 27.91 $ 37.87 Oil equivalent, including hedges (dollar per Boe) $ 26.90 $ 35.80 EXPENSES (dollars per Boe): Production expenses (including taxes) $ 9.93 $ 10.11 General and administrative $ 1.74 $ 2.11 DD&A (on oil and gas properties) $ 6.37 $ 5.40
REVENUES GENERAL For the three months ended September 30, 2004, we experienced an increase in revenues attributable, in part, to oil prices being $11.54 per barrel higher than in the same period in 2003, and to a 111,000 barrel increase in production compared to the same period in 2003. We also realized an increase in our oil marketing program due to the increase in prices and volumes in the 2004 period. OIL AND GAS SALES The increase in oil and gas sales revenue was primarily attributable to higher oil and gas prices in 2004 and volumes increased to 1,338 thousand barrels of oil equivalent, or MBoe, in the three months ended September 30, 2004, from 1,277 MBoe during the three months ended September 30, 2003. The following table shows our production by region for the three months ended September 30, 2003 and 2004:
Three Months Ended September 30, ------------------------------------------------------ 2003 2004 ------------------------------------------------------ MBoe Percent MBoe Percent ------------ -------------- ----------- -------------- Rocky Mountain 717 56.15% 859 64.20% Mid-Continent 398 31.17% 382 28.55% Gulf 162 12.69% 97 7.25% ============ ============== =========== ============== 1,277 100.00% 1,338 100.00%
CRUDE OIL MARKETING AND TRADING We enter into a series of contracts in order to exchange our crude oil production in our Rocky Mountain Region for equal quantities of crude oil located at Cushing, Oklahoma. Through this activity, we take advantage of better pricing and reduce our credit risk associated with our first purchaser. In our income statement, we present this purchase and sale activity separately as crude oil marketing revenues and crude oil marketing expenses, based on guidance provided by EITF 99-19, Reporting Revenues Gross as a Principal and or Net as an Agent. CHANGE IN DERIVATIVE FAIR VALUE The change in derivative fair value for the three months ended September 30, 2003, is related to a crude oil derivative contract used to reduce our exposure to changes in crude oil prices that did not qualify for special hedge accounting under SFAS No. 133. Such contract expired at December 31, 2003. OIL AND GAS SERVICE OPERATIONS We initiated sales of HPAI services to a third party in 2004, which increased our oil and gas service operations $0.5 million in the third quarter of 2004 compared to the third quarter of 2003. COSTS AND EXPENSES PRODUCTION EXPENSES AND TAXES Our production expenses including taxes for the third quarter of 2004 compared to the third quarter of 2003 increased $0.8 million, or 7%. Most of the increase was due to production taxes which are generally assessed as a percent of oil and gas revenues. Our production expenses including taxes per BOE for the third quarter of 2004 increased to $10.11 from $9.93 for the third quarter of 2003. EXPLORATION EXPENSES The $0.5 million increase in exploration expense for the three months ended September 30, 2004, compared to the same period in 2003 was primarily due to an increase in our dry hole costs in the Gulf Coast region, which were amplified by significant mechanical problems and cost overruns while drilling the Shaffer D-2 well in Nueces County, Texas. CRUDE OIL MARKETING AND TRADING The $7.1 million increase in our crude oil marketing expense for the three months ended September 30, 2004 compared to the same period in 2003 was primarily due to increased prices for oil that we purchased. OIL AND GAS SERVICE OPERATIONS The $0.3 million increase in our oil and gas service operations expense for the third quarter of 2004 compared to the third quarter of 2003 was due to increased cost of purchasing and treating reclaimed oil for resale. DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES (DD&A) Depletion decreased $0.9 million in the third quarter of 2004 compared to the third quarter of 2003, due to additional impairments on our Gulf of Mexico properties and less activity in this area in 2004, which lowered our depletion. In the third quarter of 2004, our DD&A expense on our oil and gas properties was calculated at $5.40 per BOE, compared to $6.37 per BOE for the third quarter of 2003. DEPRECIATION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT The change in our depreciation and amortization of other property and equipment expense for the third quarter of 2004 compared to the third quarter of 2003 was immaterial. PROPERTY IMPAIRMENTS The $4.1 million increase in our property impairments for the three months ended September 30, 2004, compared to the same period in 2003 was primarily due to increased impairment on capitalized costs of our Gulf of Mexico properties and other Southern Region wells. In 2003 we assessed non-producing properties annually and in 2004, we are assessing these properties quarterly. ASSET RETIREMENT ACCRETION We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003. The change in our asset retirement accretion expense for the third quarter of 2004 compared to the third quarter of 2003 was immaterial. GENERAL AND ADMINISTRATIVE (G&A) Our G&A expense for the third quarter of 2004 compared to the third quarter of 2003 increased $0.5 million due to increased employee expenses primarily related to employee bonuses. Our G&A expense per BOE for the third quarter of 2004 increased to $2.07 from $1.74 for the third quarter of 2003. INTEREST EXPENSE The $0.5 million increase in our interest expense for the three months ended September 30, 2004, compared to the same period in 2003 was due to additional interest on higher average debt balances outstanding under our credit facilities and higher interest rates during the third quarter of 2004 compared to the third quarter of 2003. NINE MONTHS ENDED SEPTEMBER 30, 2003, COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004. Certain reclassifications have been made to prior year amounts to conform to the current year presentation. The following table shows our income statement for the nine months ended September 30, 2003, compared to the nine months ended September 30, 2004, with dollar and percentage increases or decreases:
Nine Months Ended September 30, ------------------------------------ Increase Increase REVENUES: 2003 2004 (Decrease) (Decrease) ------------------ ------------------ ------------------------------ Oil and gas sales $ 103,419 $ 124,130 $ 20,711 20.03% Crude oil marketing and trading 120,046 158,733 38,687 32.23% Change in derivative fair value 926 404 (522) -56.37% Oil and gas service operations 6,596 7,627 1,031 15.63% ------------------ ------------------ ---------------- ------------- Total revenues $ 230,987 $ 290,894 $ 59,907 25.94% OPERATING COSTS AND EXPENSES: Production $ 29,882 $ 30,955 $ 1,073 3.59% Production taxes 7,586 8,414 828 10.91% Exploration 7,548 9,278 1,730 22.92% Crude oil marketing and trading 118,878 158,645 39,767 33.45% Oil and gas service operations 4,178 5,071 893 21.37% DD&A of oil and gas properties 23,350 27,281 3,931 16.84% DD&A of other assets 1,436 1,052 (384) -26.74% Property impairments 3,861 9,062 5,201 134.71% Asset retirement obligation accretion 1,045 788 (257) -24.59% General and administrative 7,176 7,552 376 5.24% ------------------ ------------------ ---------------- ------------- Total operating costs and expenses $ 204,940 $ 258,098 $ 53,158 25.94% OPERATING INCOME $ 26,047 $ 32,796 $ 6,749 25.91% OTHER INCOME (EXPENSE): Interest income $ 81 $ 60 $ (21) -25.93% Interest expense (14,685) (15,725) (1,040) 7.08% Other income, net 60 629 569 - Gain (loss) on disposition of assets 367 (141) (508) - ------------------ ------------------ ---------------- ------------- Total other income (expense) $ (14,177) $ (15,177) $ (1,000) - INCOME FROM CONTINUING OPERATIONS $ 11,870 $ 17,619 $ 5,749 48.43% DISCONTINUED OPERATIONS 2,242 1,680 (562) -25.07% LOSS ON SALE OF DISCONTINUED OPERATIONS - (632) (632) - ------------------ ------------------ ---------------- ------------- INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE $ 14,112 18,667 4,555 32.28% CHANGE IN ACCOUNTING PRINCIPLE 273 $ - $ (273) - ------------------ ------------------ ---------------- ------------- NET INCOME $ 14,385 $ 18,667 $ 4,282 29.77% ================== ================== ================ =============
RESULTS OF OPERATIONS The following table sets forth certain information regarding our production volumes, oil and gas sales, average sales prices and expenses for the periods indicated:
For the Nine Months Ended September 30, --------------- ---------------- 2003 2004 --------------- ---------------- NET PRODUCTION: (restated) Oil (MBbl) 2,645 2,610 Gas (MMcf) 7,496 6,712 Oil equivalent (MBoe) 3,894 3,728 OIL AND GAS SALES (dollars in thousands) Oil sales, excluding hedges $ 76,694 $ 95,354 Hedges (8,597) (4,487) -------------- -------------- Total oil sales, including hedges 68,097 90,867 Gas sales 35,322 33,263 -------------- -------------- Total oil and gas sales $ 103,419 $ 124,130 AVERAGE SALES PRICE: Oil, excluding hedges (dollar per barrel) $ 29.00 $ 36.53 Oil, including hedges (dollar per barrel) $ 25.75 $ 34.81 Gas (dollar per Mcf) $ 4.71 $ 4.96 Oil equivalent, excluding hedges (dollar per Boe) $ 28.77 $ 34.50 Oil equivalent, including hedges (dollar per Boe) $ 26.56 $ 33.30 EXPENSES (dollars per Boe): Production expenses (including taxes) $ 9.62 $ 10.56 General and administrative $ 1.84 $ 2.18 DD&A (on oil and gas properties) $ 6.00 $ 7.32
REVENUES GENERAL Our revenues increased due to higher oil and gas prices realized on our oil and gas production in the 2004 period. Oil prices increased $9.06 per barrel and gas increased $0.25 per Mcf in the nine months of 2004 compared to the same period in 2003. Revenues from our oil marketing program also increased in the nine months of 2004 compared to the same period in 2003 due to the increased oil price. OIL AND GAS SALES Although our volumes for the first nine months of 2004 decreased 166 MBoe compared to the first nine months of 2003, our oil and gas sales revenues for the same 2004 period increased $20.7 million compared to the same period of 2003 due predominately to higher oil prices. The following table shows our production by region for the nine months ended September 30, 2003 and 2004:
Nine Months Ended September 30, --------------------------------------------------- 2003 2004 --------------------------------------------------- MBoe Percent MBoe Percent --------- -------------- ----------- -------------- Rocky Mountain 2,240 57.52% 2,299 61.67% Mid-Continent 1,188 30.51% 1,107 29.69% Gulf 466 11.97% 322 8.64% ========= ============== =========== ============== 3,894 100.00% 3,728 100.00%
CRUDE OIL MARKETING AND TRADING We enter into a series of contracts in order to exchange our crude oil production in our Rocky Mountain Region for equal quantities of crude oil located at Cushing, Oklahoma. Through this activity, we take advantage of better pricing and reduce our credit risk associated with our first purchaser. In our income statement, we present this purchase and sale activity separately as crude oil marketing revenues and crude oil marketing expenses, based on guidance provided by EITF 99-19, Reporting Revenues Gross as a Principal and or Net as an Agent. Additionally, in the first five months of 2004, we engaged in certain crude oil trading activities, exclusive of our own production, utilizing fixed price and variable priced physical delivery contracts. Our derivative trading activities are being marked to market with all changes in fair value being recorded in the income statement under the accounting prescribed by SFAS No. 133, Accounting for Derivative and Hedging Activities. Effective May 2004, we closed out all open trading positions and have terminated our derivative trading activities. CHANGE IN DERIVATIVE FAIR VALUE The change in derivative fair value for the nine months ended September 30, 2003, is related to a crude oil derivative contract used to reduce our exposure to changes in crude oil prices that did not qualify for special hedge accounting under SFAS No. 133. Such contract expired at December 31, 2003. The change in derivative fair value for the nine months ended September 30, 2004, is the result of those derivative trading contracts described in Note 4 to our Condensed Consolidated Financial Statements. OIL AND GAS SERVICE OPERATIONS We initiated the sale of HPAI services to a third party in 2004 which increased our oil and gas service operations $1.0 million in the first nine months of 2004 compared to the first nine months of 2003. COSTS AND EXPENSES PRODUCTION EXPENSES AND TAXES Our production expense including taxes for the first nine months of 2004 compared to the first nine months of 2003 increased $1.9 million, or 5% from the same period in 2003. The 11% increase in taxes is the result of higher prices for oil and gas production in the 2004 period compared to the 2003 period. Our production expenses including taxes per BOE for the first nine months of 2004 was $10.51 compared to $9.57 for the first nine months of 2003. EXPLORATION EXPENSES The $1.7 million increase in exploration expense for the nine months ended September 30, 2004, compared to the same period in 2003 was primarily due to an increase in our dry hole costs in the Gulf Coast region, which were amplified by significant mechanical problems and cost overruns associated with the Shaffer D-2 well in Nueces County, Texas in the first nine months of 2004 compared to the first nine months of 2003. CRUDE OIL MARKETING AND TRADING The $39.8 million increase in our crude oil marketing expense for the nine months ended September 30, 2004, compared to the same period in 2003 was primarily due to increased prices for oil we purchased and greater volumes marketed and traded. OIL AND GAS SERVICE OPERATIONS The $0.9 million increase in our oil and gas service operations expense for the nine months ended September 30, 2004, compared to the same period in 2003 was due to higher prices paid for purchasing and treating reclaimed oil for resale in 2004. DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES ("DD&A") For the nine months ended September 30, 2004, DD&A of our oil and gas properties increased $3.8 million due to certain developmental dry hole costs being added to our amortization base and depleted with the costs of the related property offsets and due to slightly higher production decline rates in the Gulf Coast region. In the first nine months of 2004, our DD&A expense on oil and gas properties was calculated at $7.30 per BOE compared to $6.02 per BOE for the first nine months of 2003. DEPRECIATION AND AMORTIZATION OF OTHER ASSETS ("D&A") The change in depreciation and amortization expense related to our other properties and equipment decreased $0.4 million. The company jet was fully depreciated by June 2003, which made up most of the $0.4 million decrease. Some computer equipment and company vehicles were also fully depreciated. PROPERTY IMPAIRMENTS Property impairments for the nine months ended September 30, 2004, increased $5.2 million compared to the nine months ended September 30, 2003. Individually significant non-producing properties are periodically assessed for impairment of value and a loss is recognized if there is no firm plan for the property. In 2003, we only assessed properties annually and in 2004 we are assessing these properties quarterly. The increase in 2004 was due to increased impairment on capitalized costs of our undeveloped leasehold and impairment primarily of our Gulf of Mexico properties. ASSET RETIREMENT ACCRETION Recalculation of our asset retirement obligation lowered our obligation and accretion expense by $0.3 million in the first nine months of 2004 compared to the first nine months of 2003. GENERAL AND ADMINISTRATIVE (G&A) Our G&A expense for the nine months of 2004 compared to the nine months of 2003 did not change significantly, but the decrease in volumes from the same periods caused our G&A expense per BOE for the first half of 2004 to increase to $2.03 from $1.84 for the same period in 2003. INTEREST EXPENSE The increase in our interest expense was due to additional interest on higher average debt balances outstanding under our credit facilities and increase interest rates during the nine months ended September 30, 2004, compared to the nine months ended September 30, 2003. DISCONTINUED OPERATIONS The $0.6 million decrease in income from discontinued operations, formerly our gas gathering, marketing and processing segment, for the nine month period from 2003 to 2004 is primarily due to the period covered in 2004 only includes results through July 21, 2004, while the 2003 period includes results for the full nine month period. LIQUIDITY AND CAPITAL RESOURCES CASH FLOW FROM OPERATIONS Net cash provided by our operating activities for the nine months ended September 30, 2004, was $54.8 million, an increase of $6.0 million from $48.8 million provided by our operating activities during the comparable 2003 period. Our cash balance as of September 30, 2004, was $14.0 million, an increase of $11.7 million from our cash balance of $2.3 million held at December 31, 2003. DEBT Our long-term debt at December 31, 2003, and September 30, 2004, consisted of the following:
December 31, September 30 (Dollars in thousands) 2003 2004 --------------- --------------- 10.25% Senior Subordinated Notes due Aug. 1, 2008 $ 127,150 $ 119,500 Credit Facility due March 31, 2007 132,900 137,049 Credit Facility due March 31, 2006 - 25,000 Credit Facility due September 30, 2006 17,000 - Capital Lease Agreement 13,827 11,325 Ford Credit 43 34 --------------- --------------- Outstanding Debt 290,920 292,908 Less Current Portion 5,776 3,348 --------------- --------------- Total Long-Term Debt $ 285,144 $ 289,560 =============== ===============
CREDIT FACILITY On July 21, 2004, we executed the Fourth Amendment to our credit Agreement that modified the definitions to delete any reference to CGI. On April 14, 2004, we executed the Third Amendment to our Credit Agreement that added a $25.0 million term facility that matures on March 31, 2006. The amendment also extended the maturity date of the revolving credit facility to March 31, 2007. Borrowings under the term facility have margins of 5.5% on LIBOR loans and 3% on reference rate loans. On April 14, 2004, we drew $25.0 million on the new term facility and reduced the balance of the revolving credit facility. Borrowings under the revolving credit facility bear interest based on an annual rate equal to the rate at which eurodollar deposits for one, two, three or six months are offered by the lead bank plus an applicable margin ranging from 150 to 250 basis points or the lead bank's reference rate plus an applicable margin ranging from 25 to 50 basis points. The effective rate of interest on our borrowings under our revolving credit facility was 3.96% and the effective rate of interest on our borrowings under our term facility was 7.25% at September 30, 2004. The borrowing base of our credit facility was $150.0 million on September 30, 2004, and is re-determined semi-annually. Borrowings under our Credit Agreement are secured by liens on substantially all of our assets. We paid a cash dividend to our shareholders on July 19, 2004 that was funded with short-term borrowings under our Credit Agreement and we used corporate funds to acquire $7.65 million of our 10 1/4% Senior Subordinated Notes, or Notes, on July 21, 2004. These Notes were retired on October 20, 2004 reducing our outstanding balance to $119.5 million at November 15, 2004. At November 15, 2004, the outstanding balances under our revolving credit facility and the term loan were $137.0 million and $25.0 million, respectively. At November 15, 2004, we had $13.0 million of availability under our revolving credit facility. We are currently negotiating a new, $250.0 million credit facility and expect to use proceeds under this new facility, together with funds provided by our principal shareholders, to redeem our outstanding Notes and fund our capital budget. On October 22, 2003, our subsidiary, CGI, established a new $35.0 million secured credit facility consisting of a senior secured term loan facility of up to $25.0 million and a senior revolving credit facility of up to $10.0 million. On that date, CGI ceased to be a guarantor of our obligations under our credit agreement. On July 21, 2004, but effective May 31, 2004, we sold all of the outstanding capital stock of CGI to our shareholders. Section 4.10 of our indenture requires that within 360 days after the receipt of any net proceeds from any asset sale, we may apply such net proceeds, at our option, in any order or combination, (a) to reduce Senior Debt or Guarantor Senior Debt, (b) to make permitted investments, (c) to make investments in interests in oil and gas businesses or (d) to make capital expenditures in respect of our Restricted Subsidiaries' oil and gas business. Pending the final application of any such net proceeds, we may temporarily reduce indebtedness under our revolving credit facility or otherwise invest such net proceeds in any manner that is not prohibited by the indenture. We intend to use the proceeds from the sale of the stock of CGI to fund our drilling program for the next three months. On September 3, 2004, the Company executed the Fifth Amendment to the Credit Agreement that contained a one-time waiver of the requirement to comply with the hedging covenant set forth in Section 5.35 of the Credit Agreement, which states, the Company should maintain hedge agreements for at least 50% of the oil estimated to be produced during the ensuing six-month period, on a rolling six-month basis. The waiver is effective only until the earlier of: (i) the date on which the Administrative Agent, on behalf of the Required Banks, provides the Company written notice that the covenant set forth in Section 5.35 is to be reinstated and (ii) the last business day of any period of ten (10) consecutive business days during which the 6-month NYMEX strip price for light, sweet crude oil has averaged less than or equal to $30.00 per barrel. Our credit agreement contains certain financial and other covenants. At September 30, 2004, we were in compliance with all of the covenants. CAPITAL EXPENDITURES Our 2004 capital expenditures budget, exclusive of acquisitions, is $83.3 million, of which $6.7 million was dedicated to our Cedar Hills Field secondary recovery project. During the nine months ended September 30, 2004, we incurred $65.3 million of capital expenditures, compared to $96.1 million during the comparable nine-month period of 2003. Of the total $65.3 million of capital expenditures, we expended $46.7 million in exploration and development, $4.4 million on secondary recovery operations, and $10.5 million on leasing. We used the majority of the remaining $3.7 million for additions to our gas gathering systems. The $30.8 million decrease in our capital expenditures during the first nine months of 2004 compared to the first nine months of 2003 was the result of our completion of the high-pressure air injection project in the Cedar Hills Field in our Rocky Mountain Region. We expect to fund the remainder of our 2004 capital budget through cash flows from operations and the proceeds from the sale of CGI. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This report includes "forward-looking statements". All statements other than statements of historical fact, including, without limitation, statements contained under "Management's Discussion and Analysis of Financial Condition and Results of Operations" regarding our financial position, business strategy, plans and objectives of our management for future operations and industry conditions, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Important factors that could cause actual results to differ materially from our expectations ("Cautionary Statements") include, without limitation, future production levels, future prices and demand for oil and gas, results of future exploration and development activities, future operating and development costs, the effect of existing and future laws and governmental regulations (including those pertaining to the environment) and the political and economic climate of the United States as discussed in this quarterly report and the other documents we previously filed with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the Cautionary Statements. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK GENERAL We are exposed to market risks, including commodity price risk and interest rate risk, in the normal course or our business operations. Information regarding our exposures to these market risks is provided below. COMMODITY PRICE EXPOSURE Non-trading We utilize fixed-price contracts, fixed price basis contracts, collars and floors to reduce exposure to the unfavorable changes in oil and gas prices that are subject to significant and often volatile fluctuation. Under the fixed price physical delivery contracts we receive the fixed price stated in the contract. Under the fixed price basis contracts, the price we receive is determined based on a published regional index price plus or minus a fixed basis. Under the collars and floors, if the market price of crude oil exceeds the ceiling strike price or falls below the floor strike price, then we receive the fixed price ceiling or floor. If the market price is between the floor strike price and the ceiling strike price, we receive market price. These contracts allow us to predict with greater certainty the effective oil and gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, we will not benefit from market prices that are higher than the fixed, or ceiling prices in the contracts for hedged production. On September 3, 2004, the Company executed the Fifth Amendment to the Credit Agreement that contained a one-time waiver of the requirement to comply with the hedging covenant set forth in Section 5.35 of the Credit Agreement, which states, the Company should maintain hedge agreements for at least 50% of the oil estimated to be produced during the ensuing six-month period, on a rolling six-month basis,. The waiver is effective only until the earlier of: (i) the date on which the Administrative Agent, on behalf of the Required Banks, provides the Company written notice that the covenant set forth in Section 5.35 is to be reinstated and (ii) the last business day of any period of ten (10) consecutive business days during which the 6-month NYMEX strip price for light, sweet crude oil has averaged less than or equal to $30.00 per barrel. At September 30, 2004, we had a mark-to-market unrealized loss of approximately $1,205,000 on our collar and floor contracts. As such contracts have been designated and qualify as cash flow hedges, the loss has been recorded as a component of Accumulated Other Comprehensive Income at September 30, 2004. The ineffectiveness associated with our cash flow hedging strategy was immaterial. The following table summarizes our non-trading contracts in place at September 30, 2004:
Crude Oil Collars and Floors for 2004: Contract Weighted-average Volumes (Bbls) Fixed Price per Bbl ---------------------- ------------------- Oct Floor 116,000 $ 22.00 Oct Floor 100,000 $ 24.00 Nov - Dec, Floor 230,000 $ 24.50 ---------------------- 446,000 ====================== Oct Ceiling 100,000 $ 36.00 Nov - Dec, Ceiling 230,000 $ 45.00 ---------------------- 330,000 ======================
Trading In the first five months of 2004, we engaged in certain crude oil trading activities, exclusive of our own production, utilizing fixed price and variable price physical delivery contracts. At September 30, 2004, we had no open trading derivative contracts in place. INTEREST RATE RISK Our exposure to changes in interest rates relates primarily to long-term debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. The fair value of long-term debt is estimated based on quoted market prices and management's estimate of current rates available for similar issues. The following table itemizes our long-term debt maturities and the weighted-average interest rates by maturity date.
September 30, 2004 (Dollars in thousands) 2004 2005 2006 2007 Thereafter Total Fair Value - ------------------------------------------------------------------------------------------------------------- Fixed rate debt: Senior subordinated notes Principal amount $ - $ - $ - $ - $119,500 $119,500 $123,583 Weighted-average interest rate 10.25% 10.25% 10.25% 10.25% 10.25% Variable rate debt: Credit facility-Tranch A Principal amount $ - $ - $ - $137,049 $ - $137,049 $137,049 Weighted-average interest rate 3.96% 3.96% 3.96% 3.96% 3.96% Variable rate debt: Credit facility-Tranch B Principal amount $ - $ - $ 25,000 $ - $ - $ 25,000 $ 25,000 Weighted-average interest rate 7.25% 7.25% 7.25% 7.25% 7.25% Variable rate debt: Capital lease agreement Principal amount $ 834 $ 3,336 $ 3,336 $ 3,336 $ 483 $ 11,325 $ 11,325 Weighted-average interest rate 4.00% 4.00% 4.00% 4.00% 4.00% Variable rate debt: Ford Credit agreement Principal amount $ 3 $ 13 $ 13 $ 4 $ - $ 33 $ 33 Weighted-average interest rate 5.50% 5.50% 5.50% 5.50% 5.50%
ITEM 4. CONTROLS AND PROCEDURES The Securities and Exchange Commission rules require that we maintain disclosure controls and procedures to provide reasonable assurance that we are able to record, process, summarize and report the information required in quarterly and annual reports filed under the Securities Exchange Act of 1934. While we believe that our existing disclosure controls and procedures are reasonably adequate to accomplish these objectives, we intend to continue to examine, refine and formalize our disclosure controls and procedures and to maintain ongoing developments in this area. As of the end of the period covered by this report, our principal executive officer and principal financial officer have evaluated our disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934) and concluded that our disclosure controls and procedures are effective. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls, since the date the controls were evaluated. PART II. Other Information ITEM 1. LEGAL PROCEEDINGS From time to time, we are a party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not involved in any legal proceedings nor are we a party to any pending or threatened claims that could reasonably be expected to have a material adverse effect on our financial condition or results of operations. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS (a) EXHIBITS: DESCRIPTION AND METHOD OF FILING 3.1 Amended and Restated Certificate of Incorporation of Continental Resources, Inc. [3.1](1) 3.2 Amended and Restated Bylaws of Continental Resources, Inc. [3.2](1) 4.1 Fourth Amended and Restated Credit Agreement dated March 28, 2002, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. [10.1](3) 4.1.1 First Amendment to the Revolving Credit Agreement dated June 12, 2003, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. [10.1](4) 4.1.2 Second Amendment to the Revolving Credit Agreement dated October 22, 2003, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. [10.1](5) 4.1.3 Third Amendment to the Revolving Credit Agreement dated April 14, 2004, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc. [10.1](7) 4.1.4 Fourth Amendment to the Revolving Credit Agreement dated July 21, 2004, among the Registrant, Union Bank of California, N. A., Guaranty Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc. 4.1.5* Fifth Amendment to Fourth Amended and Restated Credit Agreement dated September 3, 2004, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc. 4.2 Indenture dated as of July 24, 1998, between Continental Resources, Inc. as Issuer, the Subsidiary Guarantors named therein and the United States Trust Company of New York, as Trustee. [4.2](1) 10.1 Unlimited Guaranty Agreement dated March 28, 2002. [10.2](3) 10.2 Security Agreement dated March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent. [10.3](3) 10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent. [10.4](3) 10.4+ Continental Resources, Inc. 2000 Stock Option Plan. [10.6](2) 10.5+ Form of Incentive Stock Option Agreement. [10.7](2) 10.6+ Form of Non-Qualified Stock Option Agreement. [10.8](2) 10.7 Collateral Assignment of Contracts dated March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent. [10.5](3) 10.8 Stock Purchase Agreement dated July 19, 2004, among the Registrant, Harold Hamm and Bert H. Mackie, as Trustee of the Harold Hamm DST Trust and the Harold Hamm HJ Trust, providing for the sale of all of the outstanding capital stock of Continental Gas, Inc. to the shareholders of the Registrant [10] (6) 12.1* Statement re computation of ratio of debt to Adjusted EBITDA. 12.2* Statement re computation of ratio of earning to fixed charges. 31.1* Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002 - Chief Executive Officer 31.2* Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002 - Chief Financial Officer _______________ * Filed herewith + Represents management compensatory plans or agreements (1) Filed as an exhibit to the Company's Registration Statement on Form S-4, as amended (No. 333-61547), which was filed with the Securities and Exchange Commission. The exhibit number is indicated in brackets and is incorporated herein by reference. (2) Filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2000. The exhibit number is indicated in brackets and is incorporated herein by reference. (3) Filed as an exhibit to Registrant's current report on Form 8-K dated April 11, 2002. The exhibit number is indicated in brackets and is incorporated herein by reference. (4) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2003. The exhibit number is indicated in brackets and is incorporated herein by reference. (5) Filed as an exhibit to Registrant's current report on Form 8-K dated October 22, 2003. The exhibit number is indicated in brackets and is incorporated herein by reference. (6) Filed as an exhibit to the Registrant's current report on Form 8-K dated August 5, 2004. The exhibit number is indicated in brackets and is incorporated herein by reference. (7) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2004. The exhibit number is indicated in brackets and is incorporated herein by reference. (b) REPORTS ON FORM 8-K: On August 5, 2004, the Registrant filed a current report on Form 8-K to report under Item 2. Acquisition or Disposition of Assets the Registrant's sale of all the issued and outstanding capital stock of Continental Gas, Inc. to the Registrant's shareholders. On August 18, 2004, the Registrant filed a current report on Form 8-K to report under Item 4. Changes in Registrant's Certifying Accountant the Registrant's notice on August 13, 2004, that Ernst & Young had resigned from serving as the independent accountant for the Registrant. On September 22, 2004, the Registrant filed a current report on Form 8-K to report under Item 4.01 Changes in Registrant's Certifying Accountant the Registrant's engagement of Grant Thornton LLP to act as the independent accountant. On October 8, 2004, the Registrant filed a current report on Form 8-K to report under Item 2.04 Triggering Events That Accelerate or Increase a Direct Financial Obligation or an Obligation Under an Off-Balance Sheet Arrangement the Registrant provided notice to the Trustee that the Registrant will redeem all of the outstanding Notes on November 22, 2004. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. Continental Resources, Inc. Date: November 11, 2004 By: /S/ ROGER V. CLEMENT Roger V. Clement Senior Vice President and Chief Financial Officer EXHIBIT INDEX Exhibit No. Description Method of Filing --- ----------- ---------------- 3.1 Amended and Restated Certificate of Incorporated herein by reference Incorporation of Continental Resources, Inc. 3.2 Amended and Restated Bylaws of Incorporated herein by reference Continental Resources, Inc. 4.1 Fourth Amended and Restated Credit Incorporated herein by reference Agreement dated March 28, 2002, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. 4.1.1 First Amendment to the Revolving Credit Incorporated herein by reference Agreement dated June 12, 2003, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. 4.1.2 Second Amendment to the Revolving Incorporated herein by reference Credit Agreement dated October 22, 2003, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. 4.1.3 Third Amendment to the Revolving Credit Incorporated herein by reference Agreement dated April 14, 2004, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc. 4.1.4 Fourth Amendment to the Revolving Incorporated herein by reference Credit Agreement dated July 21, 2004, among the Registrant, Union Bank of California, N. A., Guaranty Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc. 4.1.5 Fifth Amendment to Fourth Amended and Filed herewith electronically Restated Credit Agreement dated September 3, 2004, among the Registrant, Union Bank of California, N.A., Guaranty Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc. 4.2 Indenture dated as of July 24, 1998, Incorporated herein by reference between Continental Resources, Inc. as Issuer, the Subsidiary Guarantors named therein and the United States Trust Company of New York, as Trustee. 10.1 Unlimited Guaranty Agreement dated Incorporated herein by reference March 28, 2002. 10.2 Security Agreement dated March 28, Incorporated herein by reference 2002, between Registrant and Guaranty Bank, FSB, as Agent. 10.3 Stock Pledge Agreement dated March 28, Incorporated herein by reference 2002, between Registrant and Guaranty Bank, FSB, as Agent. 10.4 Continental Resources, Inc. 2000 Stock Incorporated herein by reference Option Plan. 10.5 Form of Incentive Stock Option Incorporated herein by reference Agreement. 10.6 Form of Non-Qualified Stock Option Incorporated herein by reference Agreement. 10.7 Collateral Assignment of Contracts Incorporated herein by reference dated March 28, 2002, between Registrant and Guaranty Bank, FSB, as Agent. 10.8 Stock Purchase Agreement dated July 19, Incorporated herein by reference 2004, among the Registrant, Harold Hamm and Bert H. Mackie, as Trustee of the Harold Hamm DST Trust and the Harold Hamm HJ Trust, providing for the sale of all of the outstanding capital stock of Continental Gas, Inc. to the shareholders of the Registrant 12.1 Statement re computation of ratio of Filed herewith electronically debt to Adjusted EBITDA. 12.2 Statement re computation of ratio of Filed herewith electronically earning to fixed charges. 31.1 Certification pursuant to section 302 Filed herewith electronically of the Sarbanes-Oxley Act of 2002 - Chief Executive Officer 31.2 Certification pursuant to section 302 Filed herewith electronically of the Sarbanes-Oxley Act of 2002 - Chief Financial Officer EX-4.1.5 2 criex415form10q-111504.txt FIFTH AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT This Fifth Amendment ("Fifth Amendment") to Fourth Amended and Restated Credit Agreement dated as of March 28, 2002, as amended by the First Amendment thereto dated as of June 12, 2003, the Second Amendment thereto dated as of October 22, 2003, the Third Amendment thereto dated as of April 14, 2004 and the Fourth Amendment thereto dated July 21, 2004 (as amended, the "Credit Agreement"), originally by and among CONTINENTAL RESOURCES, INC., an Oklahoma corporation (the "Borrower"), UNION BANK OF CALIFORNIA, N.A., as LC Issuer, Bank, Lead Arranger, Fronting Bank and Administrative Agent (in such latter capacity and together with its successors and permitted assigns in such capacity the "Administrative Agent"), GUARANTY BANK, FSB, as Co-Arranger, Bank and Collateral/Documentation Agent, and FORTIS CAPITAL CORP., as Co-Arranger, Bank and Syndication Agent, and the several banks and financial institutions from time to time parties to the Credit Agreement (the "Banks") is entered into this 3rd day of September 2004. W I T N E S S E T H: WHEREAS, Borrower desires to amend certain provisions of the Credit Agreement and of Administrative Agent and the Banks are willing to agree to do so subject to the terms and conditions set forth herein; NOW, THEREFORE, in consideration of the premises and for Ten Dollars ($10.00) and other good and valuable consideration received by each party hereto, and each intending to be legally bound hereby, the parties agree as follows. I. Amendments to Credit Agreement. Article I, DEFINITIONS, of the Credit Agreement is hereby modified by adding the following definitions: "Fourth Amendment" means the Fourth Amendment to Credit Agreement dated July 21, 2004. "Fifth Amendment" means the Fifth Amendment to Credit Agreement dated September 3, 2004. II. Certain Waiver. The Bank Parties hereby grant a limited one-time waiver, as specifically set forth herein, of Borrower's requirement to comply with the hedging covenant set forth in Section 5.35, as added to the Credit Agreement by the First Amendment thereto, as amended by the Second Amendment thereto, the Third Amendment and the Fourth Amendment thereto. The waiver set forth above shall be effective only until the earlier of: (i) the date on which the Administrative Agent, on behalf of the Required Banks, provides Borrower written notice that the covenant set forth in Section 5.35 is to be reinstated and (ii) the last Business Day of any period of ten (10) consecutive Business Days during which the 6-month NYMEX strip price for light, sweet crude oil has averaged less than or equal to $30.00 per barrel (the "Hedge Reinstatement Date"). Within five (5) days after the Hedge Reinstatement Date, Borrower shall enter into Hedge Agreements to satisfy the covenants set forth in Section 5.35. Borrower hereby acknowledges and agrees that the requirement to enter into such Hedge Agreements as provided herein is an affirmative covenant under Section 5.35, and the breach of such covenant shall entitle the Bank Parties to all rights and remedies under the Credit Agreement and the applicable Loan Documents. This limited one-time waiver is not intended to establish any course of dealing between the Bank Parties and Borrower, or to indicate any intention or agreement to grant future waivers of any non-compliance by Borrower with any of the terms of the Credit Agreement. Any future waivers must be in writing and signed by the Bank Parties, and any alleged waiver that is not in writing and signed by the Bank Parties shall be subject to the provisions of Section 9.07 of the Credit Agreement. III. Conditions Precedent in Connection with the Fifth Amendment. The Fifth Amendment shall not be binding on the Banks until satisfaction of the following conditions precedent: A. Administrative Agent shall have received fully executed counterparts, in the number of multiple originals requested by Administrative Agent, of the Fifth Amendment, duly executed by an authorized officer for Borrower. B. The representations and warranties contained in Article IV of the Credit Agreement shall be true and correct in all material respects on the date of the Fifth Amendment with the same effect as though such representations and warranties had been made on such date; and no Event of Default shall have occurred and be continuing or will have occurred upon the execution of the Fifth Amendment. C. All legal matters incident to the consummation of the transactions contemplated by the Fifth Amendment shall be satisfactory to special counsel for the Banks. D. All reasonable and documented legal fees owed by the Banks to Porter & Hedges, L.L.P. in connection with the Fifth Amendment shall have been paid by Borrower. IV. Representations and Warranties. To induce the Banks to enter into this Fifth Amendment, the Borrower hereby reaffirms, as of the date hereof, its representations and warranties contained in Article IV of the Credit Agreement and in all other documents executed pursuant thereto, and additionally represents and warrants as follows: A. The execution and delivery of this Fifth Amendment and the performance by the Borrower of its obligations under this Fifth Amendment are within the Borrower's power, have been duly authorized by all necessary corporate action, have received all necessary governmental approval (if any shall be required), and do not and will not contravene or conflict with any provision of law or of the charter or by-laws of the Borrower or of any agreement binding upon the Borrower. B. The Credit Agreement as amended by this Fifth Amendment represents the legal, valid and binding obligations of the Borrower, enforceable against the Borrower in accordance with their respective terms subject as to enforcement only to bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors' rights generally. C. No Event of Default or Unmatured Event of Default has occurred and is continuing as of the date hereof. D. Since the date of the Agreement, Borrower has not formed or created any new Subsidiaries. V. Defined Terms. Except as amended hereby, terms used herein that are defined in the Credit Agreement shall have the same meanings herein. VI. Reaffirmation of Credit Agreement. This Fifth Amendment shall be deemed to be an amendment to the Credit Agreement, and the Credit Agreement, as further amended hereby, is hereby ratified, approved and confirmed in each and every respect. All references to the Credit Agreement herein and in any other document, instrument, agreement or writing shall hereafter be deemed to refer to the Credit Agreement as amended hereby. VII. Entire Agreement. The Credit Agreement, as hereby amended, embodies the entire agreement between the Borrower and the Banks and supersedes all prior proposals, agreements and understandings relating to the subject matter hereof. The Borrower certifies that it is relying on no representation, warranty, covenant or agreement except for those set forth in the Credit Agreement, as hereby amended, and in the other documents previously executed or executed of even date herewith. VIII. Governing Law. THIS FIFTH AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS AND THE APPLICABLE LAWS OF THE UNITED STATES OF AMERICA. This Fifth Amendment has been entered into in Harris County, Texas, and it shall be performable for all purposes in Harris County, Texas. Courts within the State of Texas shall have jurisdiction over any and all disputes between the Borrower and the Banks, whether in law or equity, including, but not limited to, any and all disputes arising out of or relating to this Fifth Amendment or any other Security Instrument; and venue in any such dispute whether in federal or state court shall be laid in Harris County, Texas. IX. Severability. Whenever possible each provision of this Fifth Amendment shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Fifth Amendment shall be prohibited by or invalid under applicable law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Fifth Amendment. X. Execution in Counterparts. This Fifth Amendment may be executed in any number of counterparts and by the different parties on separate counterparts, and each such counterpart shall be deemed to be an original, but all such counterparts shall together constitute but one and the same agreement. XI. Section Captions. Section captions used in this Fifth Amendment are for convenience of reference only, and shall not affect the construction of this Fifth Amendment. XII. Successors and Assigns. This Fifth Amendment shall be binding upon the Borrower and the Banks and their respective successors and assigns, and shall inure to the benefit of the Borrower and the Banks, and the respective successors and assigns of the Banks. XIII. Non-Application of Chapter 346 of Texas Finance Codes. In no event shall Chapter 346 of the Texas Finance Code (which regulates certain revolving loan accounts and revolving tri-party accounts) apply to this Credit Agreement as hereby further amended or any other Loan Documents or the transactions contemplated hereby. XIV. Notice. THIS FIFTH AMENDMENT TOGETHER WITH THE LOAN AGREEMENT, AND THE OTHER SECURITY INSTRUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO WRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. [signature pages follow] IN WITNESS WHEREOF, the parties hereto have caused this Fifth Amendment to be duly executed as of the day and year first above written. BORROWER: CONTINENTAL RESOURCES, INC. By: ROGER CLEMENT Roger Clement Senior Vice President and Chief Financial Officer ADMINISTRATIVE AGENT, LEAD ARRANGER, LC ISSUER, FRONTING BANK AND A BANK: UNION BANK OF CALIFORNIA, N.A. By: RANDALL OSTERBERG Randall Osterberg, Senior Vice President By: JOHN CLARK John Clark, Vice President COLLATERAL/DOCUMENTATION AGENT, CO-ARRANGER AND A BANK: GUARANTY BANK, FSB By: RICHARD MENCHACA Richard Menchaca, Senior Vice President SYNDICATION AGENT, CO-ARRANGER AND A BANK: FORTIS CAPITAL CORP. By: DARRELL W. HOLLEY Darrell W. Holley, Managing Director By: CHRISTOPHER S. PARADA Christopher S. Parada, Vice President CO-AGENT AND A BANK: THE ROYAL BANK OF SCOTLAND plc By: CHRIS H. CLARKE Name: Chris H. Clarke Title: Senior Vice President BANK: WASHINGTON MUTUAL BANK, FA By: DAVID W. PHILLIPS David W. Phillips, Vice President EX-12.1 3 criex121form10q-111504.txt Continental Resources, Inc. Exhibit 12.1 - COMPUTATION OF RATIO OF DEBT TO ADJUSTED EBITDA
Nine months ended YEAR ENDED DECEMBER 31, September 30, --------------------------------------------------------- ----------------- 1999 2000 2001 2002 2003 2004 ----------------------------------------------------------------------- NET INCOME (LOSS) 3,920 37,780 11,667 (20,032) 2,340 18,667 INCOME TAXES - - - - - - INTEREST EXPENSE 17,370 16,514 15,674 18,401 20,258 16,152 DD&A 19,549 19,552 27,731 31,380 42,367 30,329 ACCRETION EXPENSE - - - - 1,151 788 PROPERTY IMPAIRMENTS 5,154 5,631 10,113 25,686 8,975 9,062 EXPLORATION EXPENSE 3,191 9,965 15,863 10,229 17,221 9,278 LITIGATION SETTLEMENT - - - - - - CHANGE IN ACCOUNTING PRINCIPLE - - - - (2,162) - ---------- ---------- ---------- ------------ ----------- ---------- ADJUSTED EBITDA 49,184 89,442 81,048 65,664 90,150 84,276 ANNUALIZED ADJUSTED EBITDA 112,368 TOTAL DEBT 170,637 140,350 183,395 235,205 277,093 281,583 TOTAL DEBT TO ADJUSTED EBITDA 3.5 1.6 2.3 3.6 3.1 2.5 _______________ Adjusted EBITDA represents earnings before interest expense, income taxes, depreciation, depletion, amortization, accretion, property impairments and exploration expense, excluding proceeds from litigation settlements. Adjusted EBITDA is not a measure of cash flow as determined by generally accepted accounting principles ("GAAP"). Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. The Company's computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. The Company believes that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure the Company' ability to meet future debt service requirements, if any. Total debt excludes capital leases of $11.3 million in the nine months ended September 30, 2004, $13.8 million at year-end 2003 and $12.0 million at year-end 2002.
EX-12.2 4 criex122form10q-111504.txt CONTINENTAL RESOURCES, INC. Exhibit 12.2 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Nine months ended YEAR ENDED DECEMBER 31, September 30, ----------------------------------------------------------------- ------------- 1999 2000 2001 2002 2003 2004 ----------------------------------------------------------------- ------------- EARNINGS 3,920 37,780 11,667 (20,032) 2,340 18,667 FIXED CHARGES 16,990 16,513 15,674 18,401 20,258 16,152 ----------------------------------------------------------------- ------------- TOTAL EARNINGS & FIXED CHARGES 20,910 54,293 27,341 (1,631) 22,598 34,819 RATIO 1.2 3.3 1.7 N/A 1.1 2.2 EARNINGS INSUFFICIENT TO COVER FIXED CHARGES BY N/A N/A N/A 20,032 N/A N/A _______________ Represents interest expense.
EX-31.1 5 criex311form10q-111504.txt Exhibit 31.1 CERTIFICATIONS FOR FORM 10-Q I, Harold Hamm, Chief Executive Officer, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Continental Resources, Inc. ("Registrant"); 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, 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 and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; 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 over financial reporting. Continental Resources, Inc. Date: November 11, 2004 By: /S/ HAROLD HAMM Harold Hamm Chief Executive Officer EX-31.2 6 criex312form10q-111504.txt Exhibit 31.2 CERTIFICATIONS FOR FORM 10-Q I, Roger Clement, Vice President and Chief Financial Officer, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Continental Resources, Inc. ("Registrant"); 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, 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 and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; 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 over financial reporting. Continental Resources, Inc. Date: November 11, 2004 By: /S/ ROGER V. CLEMENT Roger V. Clement Senior Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----