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, 2003
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 300, 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 13, 2003
- ---------------------------- -----------------------------------
Common Stock, $.01 par value 14,368,919 shares
TABLE OF CONTENTS
PART I. Financial Information
ITEM 1. Financial Statements .................................................4
ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.........................................14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk ..........20
ITEM 4. Controls and Procedures..............................................21
PART II. Other Information
ITEM 1. Legal Proceedings .................................................. 22
ITEM 2. Changes in Securities and Use of Proceeds ...........................22
ITEM 3. Defaults Upon Senior Securities .....................................22
ITEM 4. Submission of Matters to a Vote of Security Holders .................22
ITEM 5. Other Information ...................................................22
ITEM 6. Exhibits and Reports on Form 8-K.....................................22
Signatures....................................................................25
ITEM 1. FINANCIAL STATEMENTS
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share data)
December 31, September 30,
---------------- -----------------
2002 2003
---------------- -----------------
CURRENT ASSETS: (unaudited)
Cash $ 2,520 $ 2,999
Accounts receivable:
Oil and gas sales 14,756 15,878
Joint interest and other, net 7,884 13,552
Inventories 6,700 6,934
Prepaid expenses 482 170
Fair value of derivative contracts 628 623
----------------- ------------------
Total current assets 32,970 40,156
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties, based on
successful efforts accounting
Producing properties 488,432 573,617
Nonproducing leaseholds 33,781 33,911
Gas gathering and processing facilities 33,113 48,465
Service properties, equipment and other 18,430 19,369
----------------- ------------------
Total property and equipment 573,756 675,362
Less - Accumulated depreciation,
depletion and amortization (205,853) (211,232)
----------------- ------------------
Net property and equipment 367,903 464,130
OTHER ASSETS:
Debt issuance costs, net 5,796 4,763
Other assets 8 8
----------------- ------------------
Total other assets 5,804 4,771
----------------- ------------------
Total assets $ 406,677 $ 509,057
================= ==================
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share data)
December 31, September 30,
------------- --------------
2002 2003
------------- -------------
CURRENT LIABILITIES: (Unaudited)
Accounts payable $ 26,665 $ 34,025
Current portion of long term debt 2,400 3,336
Revenues and royalties payable 5,299 6,893
Accrued liabilities and other 10,320 7,961
Fair value of derivative contracts 2,082 1,153
------------- -------------
Total current liabilities 46,766 53,368
LONG-TERM DEBT, net of current portion 244,705 286,875
ASSET RETIREMENT OBLIGATION - 37,257
OTHER NON-CURRENT LIABILITIES 125 163
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 89,850 106,163
------------- -------------
Total stockholders' equity 115,081 131,394
------------- -------------
Total liabilities and stockholders' equity $ 406,677 $ 509,057
============= =============
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except share data)
Three Months Ended September 30,
--------------------------------
2002 2003
------------- -----------------
REVENUES: (As restated)
Oil and gas sales $ 29,577 $ 34,350
Crude oil marketing income 33,453 39,698
Change in derivative fair value (757) 519
Gathering, marketing and processing 8,319 23,284
Oil and gas service operations 1,447 2,291
------------- --------------
Total revenues 72,039 100,142
OPERATING COSTS AND EXPENSES:
Production expenses 7,424 9,266
Production taxes 2,157 2,551
Exploration expenses 2,498 3,495
Crude oil marketing expenses 33,386 39,002
Gathering, marketing and processing 7,707 22,075
Oil and gas service operations 1,794 2,094
Depreciation, depletion and amortization of oil and gas properties 4,525 8,134
Depreciation and amortization of other property and equipment 1,065 1,224
Property impairments 609 1,309
Asset retirement obligation accretion expense - 346
General and administrative 2,865 2,667
------------- --------------
Total operating costs and expenses 64,030 92,163
OPERATING INCOME 8,009 7,979
OTHER INCOME (EXPENSES):
Interest income 83 26
Interest expense (4,669) (5,076)
Other income, net 149 13
Gain on sale of assets 13 90
------------- --------------
Total other income (expense) (4,424) (4,947)
------------- --------------
NET INCOME $ 3,585 $ 3,032
============= ==============
EARNINGS PER COMMON SHARE:
Basic $ 0.25 $ 0.21
============= ==============
Diluted $ 0.25 $ 0.21
============= ==============
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except share data)
Nine Months Ended September 30,
--------------------------------
2002 2003
------------- -----------------
REVENUES: (As restated)
Oil and gas sales $ 80,023 $ 103,419
Crude oil marketing income 120,472 120,046
Change in derivative fair value (2,020) 926
Gathering, marketing and processing 24,476 50,134
Oil and gas service operations 4,287 6,596
------------- --------------
Total revenues 227,238 281,121
OPERATING COSTS AND EXPENSES:
Production expenses 21,324 27,494
Production taxes 5,644 7,586
Exploration expenses 5,153 7,548
Crude oil marketing expenses 119,735 118,878
Gathering, marketing and processing 21,192 46,697
Oil and gas service operations 4,837 5,987
Depreciation, depletion and amortization of oil and gas properties 18,548 23,350
Depreciation and amortization of other property and equipment 3,120 3,603
Property impairments 1,643 3,861
Asset retirement obligation accretion expense - 1,055
General and administrative 7,918 8,356
------------- --------------
Total operating costs and expenses 209,114 254,415
OPERATING INCOME 18,124 26,706
OTHER INCOME (EXPENSES):
Interest income 250 86
Interest expense (13,420) (14,991)
Other income, net 120 63
Gain on sale of assets 77 359
------------- --------------
Total other income (expense) (12,973) (14,483)
------------- --------------
NET INCOME BEFORE
CHANGE IN ACCOUNTING PRINCIPLE 5,151 12,223
------------- --------------
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE - 4,090
------------- --------------
NET INCOME $ 5,151 $ 16,313
============= ==============
BASIC EARNINGS PER COMMON SHARE:
Earnings before cumulative effect of accounting change $ 0.36 $ 0.85
Cumulative effect of accounting change - 0.28
------------- --------------
Basic $ 0.36 $ 1.13
============= ==============
DILUTED EARNINGS PER COMMON SHARE:
Earnings before cumulative effect of accounting change $ 0.36 $ 0.85
Cumulative effect of accounting change - 0.28
------------- --------------
Diluted $ 0.36 $ 1.13
============= ==============
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited)
Nine Months Ended September 30,
--------------------------------
(Dollars in thousands) 2002 2003
------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES: (As restated)
Net income $ 5,151 $ 16,313
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization 21,668 26,953
Accretion of asset retirement obligation - 1,055
Impairment of properties 1,643 3,861
Change in derivative fair value 844 (926)
Amortization of debt issuance costs - 1,190
Gain on sale of assets (77) (359)
Change in accounting principle - (4,090)
Dry hole costs 4,019 4,834
Cash provided by (used in) changes in assets and liabilities
Accounts receivable (1,097) (6,790)
Inventories 160 (202)
Prepaid expenses 170 312
Accounts payable (5,125) 7,360
Revenues and royalties payable 950 1,594
Accrued liabilities and other (2,744) (2,359)
Other non-current liabilities 28 38
Other 1 1
------------ -------------
Net cash provided by operating activities 25,591 48,785
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (64,774) (73,462)
Undeveloped leasehold (5,035) (5,963)
Gas gathering and processing facilities, service
properties, equipment and other (4,579) (16,529)
Purchase of oil and gas properties (655) (101)
Proceeds from sale of assets 123 4,768
------------ -------------
Net cash used in investing activities (74,920) (91,287)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 116,830 46,062
Repayment of line of credit and other (69,575) (2,956)
Debt issuance costs (2,147) (125)
------------ -------------
Net cash provided by financing activities 45,108 42,981
NET INCREASE (DECREASE) IN CASH (4,221) 479
CASH, beginning of period 7,225 2,520
------------ -------------
CASH, end of period $ 3,004 $ 2,999
============ =============
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 15,082 $ 18,086
Asset retirement obligation at January 1, 2003 - 35,173
Capitalized asset retirement obligation, net at January 1, 2003 - 39,263
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:
In the opinion of Continental Resources, Inc. ("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, 2003, the results of operations and cash flows for the three and
nine months ended September 30, 2002 and 2003. All 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 condensed
consolidated financial statements and notes thereto included in the Company's
annual report on form 10-K for the year ended December 31, 2002.
Certain reclassifications have been made to prior period amounts to conform
to the current period presentation. In June 2002, the Emerging Issues Task Force
(EITF) reached a consensus in Issue 02-03 that all gains and losses (realized
and unrealized) on energy trading contracts should be shown net in the income
statement whether or not such contracts are settled physically. In response to
the issuance of this consensus, we netted revenues and expenses of $85.8 million
and $85.1 million, respectively in the income statement included in our Form
10-Q for the nine months ended September 30, 2002. Subsequently, in October
2002, the EITF revised the June 2002 consensus requiring that gains and losses
on energy trading contracts should be reported net in the income statement until
the derivative contract culminates in physical delivery. Once a derivative
contract culminates in physical delivery, the guidance in EITF 99-19, Reporting
Revenue Gross as a Principal versus Net as an Agent, should be followed to
determine the appropriate income statement presentation. We adopted the October
2002 consensus on October 25, 2002. As a result of such adoption, the revenues
and expenses previously netted under the June 2002 consensus have been restated
and presented gross under the October 2002 consensus as such contracts meet the
criteria for gross presentation under EITF 99-19.
2. ACQUISITIONS:
On August 1, 2003, Continental Gas, Inc. ("CGI"), a wholly owned subsidiary
of CRI, acquired the Carmen Gathering System located in western Oklahoma for
$15.0 million. After various adjustments and other reductions in the purchase
and sale agreement, the net cost to CGI was $12.0 million. Funding for the
acquisition was obtained from borrowings under our revolving credit facility as
discussed in Note 3. Revenues and expenses attributable to the Carmen Gathering
System were $3.7 million and $3.1 million, respectively, for the period from
acquisition to September 30, 2003.
3. LONG-TERM DEBT:
Long-term debt as of December 31, 2002, and September 30, 2003, consisted
of the following:
December 31, September 30,
(Dollars in thousands) 2002 2003
------------ ------------
10.25% Senior Subordinated Notes due Aug. 2008 $ 127,150 $ 127,150
Credit Agreement 108,000 148,400
Capital Lease Agreement 11,955 14,661
------------ ------------
Outstanding Debt 247,105 290,211
Less Current Portion 2,400 3,336
------------ ------------
Total Long-Term Debt $ 244,705 $ 286,875
============ ============
During the quarter ended March 31, 2002, the Company executed a Fourth
Amended and Restated Credit Agreement in which a group of lenders agreed to
provide a $175.0 million senior secured revolving credit facility with a
borrowing base of $140.0 million. On June 12, 2003, the Company executed the
First Amendment to the Credit Agreement and increased the borrowing base to
$150.0 million. Borrowings under the credit facility are secured by liens on all
oil and gas properties and associated assets of the Company. Borrowings under
the credit facility bear interest, payable quarterly, at (a) a rate per annum
equal to the rate at which eurodollar deposits for one, two, three or nine
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. The credit facility matures on March 28,
2005. As of September 30, 2003, the Company had $148.4 million outstanding debt
on its line of credit and the effective rate of interest was 3.4%. The
outstanding balance at September 30, 2003, includes $12.0 million used for the
Carmen Gathering System acquisition.
Subsequent to September 30, 2003, Continental Gas, Inc. ("CGI"), a wholly
owned subsidiary of the Company, closed on 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 secured revolving credit facility of up to $10.0 million.
The initial advance under the term loan facility was $17.0 million, which was
paid to CRI to reduce CRI's outstanding balance at its credit facility. No funds
were initially advanced under the revolving loan facility. Advances under either
facility can be made, at the borrower's election, as reference rate loans or
LIBOR loans and, with respect to LIBOR loans, for interest periods of one, two,
three or six months. Interest is payable on reference rate loans monthly and on
LIBOR loans at the end of the applicable interest period. The principal amount
of the term loan facility is to be amortized on a quarterly basis through June
30, 2006, the final payment being due September 30, 2006. The amount available
under the revolving loan facility may be borrowed, repaid and reborrowed until
maturity on September 30, 2006. Interest on reference rate loans is calculated
with reference to a rate equal to the higher of the reference rate of Union Bank
of California, N.A. or the federal funds rate plus 0.5%. Interest on LIBOR loans
is calculated with reference to the London interbank offered interest rate.
Interest accrues at the reference rate or the LIBOR rate, as applicable, plus
the applicable margin. The applicable margin is based on the then current senior
debt to EBITDA ratio. The credit agreement contains certain covenants and
requires certain quarterly mandatory prepayments of 75% of excess cash flow. The
credit facility is secured by a pledge of all the assets of CGI.
On October 22, 2003, the Company executed the Second Amendment to the
Credit Agreement and deleted CGI 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 the outstanding balance was
reduced by the $17.0 million funded to CGI.
The Company's line of credit agreement contains certain negative financial
reporting covenants. The Company was not in compliance with the covenant that
requires the Company to maintain a minimum current ratio of 1.0:1. However, on a
pro-forma basis giving the effects of the Second Amended Credit Agreement, the
Company was in compliance. The Company received a waiver for non-compliance from
the bank group.
4. CRUDE OIL MARKETING:
Prior to May 2002, the Company conducted crude oil trading activities,
exclusive of its own production. Such activity was discontinued in May 2002.
Since May 2002, the Company has entered into third party contracts to purchase
and resell only its own physical production. The Company will continue to
repurchase its physical production from the Rocky Mountain area and resell
equivalent barrels in Oklahoma to take advantage of better pricing and to reduce
its credit exposure from sales to its first purchaser. The Company presents
sales and purchases of its production from the Rocky Mountain area as crude oil
marketing income and crude oil marketing expense, respectively. During the nine
months ended September 30, 2002, the Company recognized revenues from the sale
of crude oil of $120.5 million and expenses for the purchase of crude oil of
$119.7 million (including revenues of $85.8 million and expenses of $85.1
million related to crude oil trading activities discontinued as of May 2002)
resulting in a gain from crude oil marketing activities for the nine month
period of $0.7 million.
5. EARNINGS PER SHARE:
Basic earnings per common share is computed by dividing income available to
common stockholders by the weighted-average number of shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if dilutive 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
2002 and 2003. The weighted-average number of shares used to compute diluted
earnings per share was 14,416,469 for the three and nine months ended September
30, 2003 and 14,393,132 for the three and nine months ended September 30, 2002.
6. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries, Continental Gas, Inc. (CGI),
Continental Resources of Illinois, Inc. (CRII), and Continental Crude Co. (CCC),
have guaranteed the Company's outstanding Senior Subordinated Notes and its bank
credit facility. The following is a summary of the condensed consolidating
financial information of CGI and CRII as of December 31, 2002, and September 30,
2003, and for the three-month and nine-month periods ended September 30, 2002,
and 2003.
Condensed Consolidating Balance Sheet
As of December 31, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Current Assets $ 6,524 $ 49,308 $ (22,862) $ 32,970
Property and Equipment 42,664 325,239 - 367,903
Other Assets 7 5,811 (14) 5,804
---------------------------- ------------- -------------
Total Assets $ 49,195 $ 380,358 $ (22,876) $ 406,677
Current Liabilities $ 11,442 $ 42,258 $ (6,934) 46,766
Long-Term Debt 15,928 244,705 (15,928) 244,705
Other Liabilities - 125 - 125
Stockholders' Equity 21,825 93,270 (14) 115,081
---------------------------- ------------- ------------
Total Liabilities and
Stockholders' Equity $ 49,195 $ 380,358 $ (22,876) $ 406,677
============= ============= ============= =============
As of September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Current Assets $ 10,450 $ 62,369 $ 32,663) $ 40,156
Property and Equipment 59,417 404,713 - 464,130
Other Assets 7 4,778 (14) 4,771
---------------------------- ------------- -------------
Total Assets $ 69,874 $ 471,860 $ (32,677) $ 509,057
Current Liabilities $ 15,126 $ 45,053 $ (6,811) $ 53,368
Long-Term Debt 25,852 286,875 (25,852) 286,875
Other Liabilities 4,147 33,273 - 37,420
Stockholders' Equity 24,749 106,659 (14) 131,394
------------------------------------------- -------------
Total Liabilities and
Stockholders' Equity $ 69,874 $ 471,860 $ (32,677) $ 509,057
============= ============= ============= =============
Condensed Consolidating Income Statements
For the Three Months Ended September 30, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Total Revenue $ 11,828 $ 60,191 $ 20 $ 72,039
Operating Expenses (10,793) (53,217) (20) (64,030)
Other Income (Expenses) (399) (4,025) - (4,424)
------------- ------------- ------------- -------------
Net Income $ 636 $ 2,949 $ - $ 3,585
============= ============= ============= =============
For the Three Months Ended September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ----------------------------------------------------------
Total Revenue $ 26,565 $ 73,700 $ (123) $ 100,142
Operating Expenses (26,020) (66,266) 123 (92,163)
Other Income (Expenses) (468) (4,479) - (4,947)
------------- ------------- ------------- -------------
Net Income $ 77 $ 2,955 $ - $ 3,032
============= ============= ============= =============
Condensed Consolidating Income Statements
For the Nine Months Ended September 30, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Total Revenue $ 35,458 $ 192,640 $ (860) $ 227,238
Operating Expenses (31,776) (178,198) 860 (209,114)
Other Income (Expenses) (1,259) (11,714) - (12,973)
------------- ------------- ------------- -------------
Net Income $ 2,423 $ 2,728 $ - $ 5,151
============= ============= ============= =============
For the Nine Months Ended September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Total Revenue $ 61,991 $ 220,763 $ (1,633) $ 281,121
Operating Expenses (58,474) (197,574) 1,633 (254,415)
Other Income (Expenses) (1,153) (13,330) - (14,483)
Cumulative Effect of Change in Accounting Principle 560 3,530 - 4,090
------------- ------------ ------------- -------------
Net Income $ 2,924 $ 13,389 $ - $ 16,313
============= ============= ============= =============
Condensed Consolidated Cash Flow Statements
For the Nine Months Ended September 30, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Cash Flow From Operating Activities $ 7,759 $ 40,456 $ (22,624) $ 25,591
Cash Flow From Investing Activities (5,066) (69,854) - (74,920)
Cash Flow From Financing Activities (2,924) 48,032 - 45,108
------------- ------------- ------------- -------------
Net Increase (Decrease) in Cash (231) 18,634 (22,624) (4,221)
Cash at Beginning of Period 707 6,518 - 7,225
------------- ------------- ------------- -------------
Cash at End of Period $ 476 $ 25,152 $ (22,624) $ 3,004
For the Nine Months Ended September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Cash Flow From Operating Activities $ 7,357 $ 74,104 $ (32,676) $ 48,785
Cash Flow From Investing Activities (16,878) (74,409) - (91,287)
Cash Flow 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
At September 30, 2003, current and long-term liabilities payable to the
Company by the guarantor subsidiaries totaled approximately $32.7 million. For
the nine months ended September 30, 2002 and 2003, depreciation, depletion and
amortization included in the guarantor subsidiaries operating costs were
approximately $4.2 million and $4.3 million, respectively.
7. ASSET RETIREMENT OBLIGATIONS:
In August 2001, the FASB issued SFAS 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 a 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 face amount. The Company adopted SFAS No. 143 on
January 1, 2003. The primary impact of this standard relates to oil and gas
wells that the Company has a legal obligation to plug and abandon. Prior to SFAS
No. 143, the Company had not recorded an obligation for these plugging and
abandonment costs due to its assumption that the salvage value of the surface
equipment would substantially offset the cost of dismantling the facilities and
carrying out the necessary clean up and reclamation activities. The adoption of
SFAS No. 143 on January 1, 2003, resulted in a net increase to Property and
Equipment and Asset Retirement Obligations of approximately $39.3 million and
$35.2 million, respectively, as a result of the Company separately accounting
for salvage values and recording the estimated fair value of its plugging and
abandonment obligations on the balance sheet. The impact of adopting SFAS No.
143 has been accounted for through a cumulative effect of change in accounting
principle adjustment that amounted to a $4.1 million increase to net income
recorded on January 1, 2003. The increase in expense resulting from the
accretion of the asset retirement obligations and the depreciation of the
additional capitalized well costs is expected to be substantially offset by the
decrease in depreciation from the Company's consideration of the estimated
salvage values of the assets.
The following table describes on a pro forma basis the Company's asset
retirement liability as if SFAS No. 143 had been adopted on January 1, 2002.
2002 2003
------------- -------------
Asset Retirement Obligation liability at January 1, $ 33,495 $ 35,173
Asset Retirement Obligation accretion expense 1,005 1,055
Plus: Additions for new assets 1,478 1,807
Less: Plugging costs and sold assets (349) (777)
------------- -------------
Asset Retirement Obligation liability at September 30, $ 35,629 $ 37,258
============= =============
The following table describes the pro forma effect on net income and
earnings per share for the three and nine months ended September 30, 2002, as if
SFAS No. 143 had been adopted in January 1, 2002.
Three Months Nine Months
Ended September 30, Ended September 30,
2002 2002
-------------------- -------------------
Net income - as reported $ 3,585 $ 5,151
Less: Asset retirement obligation accretion expense (335) (1,005)
Plus: Reduction in depreciation expense on salvage value 1,220 2,440
------------- --------------
Net income - pro forma $ 4,470 $ 6,586
============= ==============
Earnings per share:
As reported
Basic $ 0.25 $ 0.36
Diluted $ 0.25 $ 0.36
Pro Forma
Basic $ 0.31 $ 0.46
Diluted $ 0.31 $ 0.46
8. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS:
In December 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." Interpretation No. 45 requires that at
the time a company issues a guarantee, the company must recognize an initial
liability for the fair value, or market value, of the obligations it assumes
under that guarantee. Interpretation No. 45 is applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. The Company adopted
this new interpretation effective January 1, 2003 and the adoption of this new
interpretation did not have a material impact on its consolidated financial
position or results of operations.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of Accounting Research Bulletin
No. 51." Interpretation No. 46 requires the consolidation of entities in which
an enterprise absorbs a majority of the entity's expected losses, receives a
majority of the entity's expected residual returns, or both, as a result of
ownership, contractual or other financial interests in the entity. Currently,
entities are generally consolidated by an enterprise when it has a controlling
financial interest through ownership of a majority voting interest in the
entity.
Interpretation No. 46 applies immediately to variable interest entities
created after January 31, 2003, and to variable interest entities in which an
enterprise obtains an interest after that date. In October 2003, the FASB issued
Interpretation No, 46-6, "Effective Date of FASB Interpretation No. 46,
Consolidation of Variable Interest Entities," in which the FASB agreed to defer,
for public companies, the required effective dates to implement Interpretation
No. 46 for interests held in a variable interest entity ("VIE") or potential VIE
that was created before February 1, 2003. For calendar year-end public
companies, the deferral effectively moves the required effective date from July
1, 2003 to December 31, 2003. As a result of Interpretation No. 46-6, public
entity need not apply the provisions of Interpretation No. 46 to an interest
held in a VIE or potential VIE until the end of the first interim or annual
period ending after December 15, 2003, if the VIE was created before February 1,
2003, and the public entity has not issued financial statements reporting that
VIE in accordance with Interpretation No. 46, other than in the disclosures
required by Interpretation No. 46. Interpretation No. 46 may be applied
prospectively with a cumulative-effect adjustment as of the date on which it is
first applied or by restating previously issued financial statements for one or
more years with a cumulative-effect adjustment as of the beginning of the first
year restated. The Company is currently evaluating the effect of the issuance of
Interpretation No. 46; however, the Company does not believe that the impact of
adoption of Interpretation No. 46 will be material to its consolidated financial
position or results of operations.
In April 2003, the FASB issued SFAS No. 149, "Amendments of Statement 133
on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain instruments embedded in other contracts and for hedging
activities under SFAS No. 133. This statement requires that contracts with
comparable characteristics be accounted for similarly. In particular, this
statement clarifies under what circumstances a contract with an initial net
investment meets the characteristic of a derivative, clarifies when a derivative
contains a financing component, amends the definition of an underlying hedged
risk to conform to language used in FASB Interpretation No. 45 and amends
certain other existing pronouncements. This statement, the provisions of which
are to be applied prospectively, is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003. The Company adopted this new standard effective July 1, 2003 and the
adoption of this new standard did not have a material impact on its consolidated
financial position or results of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. The
requirements of this statement apply to an issuer's classification and
measurement of freestanding financial instruments, including those that comprise
more than one option or forward contract. This statement does not apply to
features that are embedded in a financial instrument that are not a derivative
in its entirety. This statement also addresses questions about the
classification of certain financial instruments that embody obligations to issue
equity shares. The provisions of this statement are effective for financial
instruments entered into or modified after May 31, 2003, and otherwise is
effective at the beginning of the first interim period beginning after June 15,
2003, with the exception of the application of such statement to limited life
subsidiaries. The FASB has deferred the application of SFAS No. 150 to limited
life subsidiaries indefinitely. The Company adopted this new standard effective
July 1, 2003, and the adoption of this new standard did not have a material
impact on its consolidated financial position or results of operations.
9. SUBSEQUENT EVENTS:
FINANCING
On October 22, 2003, CGI closed on 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 secured revolving credit facility of up to $10.0 million.
The credit facility is secured by a pledge of all the assets of CGI. The initial
advance under the term loan facility was $17.0 million, which was paid to CRI to
reduce CRI's outstanding balance at its credit facility. (See Note 2 LONG-TERM
DEBT)
On October 22, 2003, the Company executed the Second Amendment to the
Credit Agreement and deleted CGI as a guarantor of the Company's obligations
under the Credit Agreement. CGI paid CRI $17.0 million, which reduced the
outstanding balance at its credit facility. The borrowing base under the Second
Amendment to the Credit Agreement was revised to $145.0 million. (See Note 2
LONG-TERM DEBT)
HEDGES
The Second Amendment to the Credit Agreement requires that the Company have
50% of its production hedged on a rolling six- month term. The Company has
established costless collars from October 2003 thru March 2004 with a floor
price of $22.00 and an average ceiling price of $35.00. Such contracts are being
accounted for as cash flow hedges.
In order to mitigate price risk exposure on production, CGI has forward
sales contracts in place that will result in the physical delivery of production
and qualify as being in the normal course of business sales and are not
accounted for as derivatives. As of September 30, 2003, CGI has 50,000 MMBTU per
month hedged from January 2004 to December 2007 at an average price of $4.579
per MMBTU. These hedges account for 9% of the total delivery point volumes and
4% of overall company throughput.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
OVERVIEW
The following table sets forth certain information regarding our production
volumes, oil and gas sales, average sales prices received and expenses for the
periods indicated:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------------ -----------------------------
2002 2003 2002 2003
------------------------------ -----------------------------
NET PRODUCTION:
Oil (MBbl) 985 854 2,869 2,645
Gas (MMcf) 2,489 2,537 7,014 7,496
Oil equivalent (MBoe) 1,400 1,277 4,038 3,894
OIL AND GAS SALES (dollars in thousands)
Oil sales, excluding hedges $ 25,561 $ 23,920 $ 66,881 $ 76,694
Hedges (2,033) (1,293) (2,742) (8,597)
-------------- -------------- -------------- --------------
Total oil sales, including hedges 23,528 22,627 64,139 68,097
Gas sales 6,049 11,723 15,884 35,322
-------------- -------------- ------------------------------
Total oil and gas sales $ 29,577 $ 34,350 $ 80,023 $ 103,419
============== ============== ============== ==============
AVERAGE SALES PRICE:
Oil, excluding hedges (dollar per barrel) $ 25.96 $ 28.02 $ 23.31 $ 29.00
Oil, including hedges (dollar per barrel) $ 23.90 $ 26.51 $ 22.36 $ 25.75
Gas (dollar per Mcf) $ 2.43 $ 4.62 $ 2.27 $ 4.71
Oil equivalent, excluding hedges (dollar per Boe) $ 22.58 $ 27.92 $ 20.50 $ 28.77
Oil equivalent, including hedges (dollar per Boe) $ 21.13 $ 26.91 $ 19.82 $ 26.56
EXPENSES (dollars per Boe):
Production expenses (including taxes) $ 6.84 $ 9.26 $ 6.68 $ 9.01
General and administrative $ 2.23 $ 2.09 $ 1.96 $ 2.15
DD&A (on oil and gas properties) $ 3.23 $ 6.37 $ 4.59 $ 6.00
THREE MONTHS ENDED SEPTEMBER 30, 2003, COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2002.
OVERVIEW
The following discussion and analysis should be read in conjunction with
our unaudited condensed consolidated financial statements and the notes thereto
appearing elsewhere in this report. Our operating results for the periods
discussed may not be indicative of future performance. In the text below,
financial statement numbers have been rounded; however, the percentage changes
are based on amounts that have not been rounded.
RESULTS OF OPERATIONS
REVENUES
GENERAL
Our revenues increased $28.1 million, or 39%, to $100.1 million during the
three months ended September 30, 2003, from $72.0 million during the comparable
period in 2002. The increase is primarily attributable to higher oil and gas
prices and higher gathering, marketing and processing revenues in the third
quarter of 2003 compared to the third quarter of 2002.
OIL AND GAS SALES
Our oil and gas sales revenue for the three months ended September 30,
2003, increased $4.8 million, or 16%, to $34.4 million from $29.6 million during
the comparable period in 2002. Oil sales revenue decreased $0.9 million, or 4%,
to $22.6 million for the three months of 2003 from $23.5 million in 2002. Oil
production decreased by 131 MBbls to 854 MBbls, or 13%, for the three months
ended September 30, 2003, from 985 MBbls for the comparable period in 2002. The
oil production decrease of 131 MBbls includes 86 MBbls as the result of
converting producing wells into injection wells in the Cedar Hills Field. Oil
prices, including hedging, increased $2.61 Bbl to an average of $26.51 Bbl, or
11%, during the three months ended September 30, 2003, from $23.90 Bbl, for the
comparable 2002 period. Gas sales revenue increased $5.7 million, or 94%, to
$11.7 million for the three-month period in 2003 compared to $6.0 million in
2002. Gas production for the period increased 48 MMcf, or 2%, to 2,537 MMcf from
2,489 MMcf in 2002. The increase in gas sales revenues is primarily attributable
to higher gas prices that averaged $4.62 Mcf in the third quarter of 2003
compared to $2.43 Mcf in the third quarter of 2002, or an increase of $2.19 per
Mcf, or 90%.
CRUDE OIL MARKETING
Since May 2002, we have had third party contracts to purchase and resell
only our own production. We will continue to repurchase our production from the
Rocky Mountain area and resell equivalent barrels in Oklahoma to take advantage
of better pricing and to reduce our credit exposure from sales to our first
purchaser. We present sales and purchases of our production from the Rocky
Mountain area on a gross basis as crude oil marketing income and crude oil
marketing expense, respectively.
During the three month period ended September 30, 2003, we recognized
revenues of $39.7 million in crude oil marketing income compared to $33.5
million for the three-month period ended September 30, 2002. This increase
resulted from an increase in oil prices.
DERIVATIVE
We have fixed price physical delivery contracts in place to deliver
approximately 93,000 barrels of our forecasted crude oil production per month
through December 2003 at an average price of $24.66 per barrel. These contracts
are considered to be in the normal course of business and have been designated
as such, thus the contracts are not accounted for as derivatives under Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. Revenues from these firm commitments are recognized as
production occurs.
In addition to the above contracts, at September 30, 2003, we also had in
place a crude oil derivative contract that is being marked to market under SFAS
No. 133 with changes in fair value being recorded in earnings as such contract
does not qualify for special hedge accounting nor does such contract meet the
criteria to be considered in the normal course of business. This contract
provides for a fixed price of $24.25 per barrel on 30,000 barrels of crude oil
per month through December 2003 when market prices exceed $19.00 per barrel.
When market prices fall below $19.00, we receive the market price. During the
three month period ended September 30, 2003, we recorded a gain of $0.5 million
in change in derivative fair value to reflect the mark-to-market valuation at
September 30, 2003.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue in the third quarter of
2003 was $23.3 million, an increase of $15.0 million, or 180%, from $8.3 million
in the same period in 2002. This increase in revenue during the third quarter
was attributable to greater volumes processed and higher natural gas and liquids
prices. The acquisition of the Carmen Gathering System, effective August 1,
2003, attributed $3.7 million to revenues in the third quarter of 2003.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenue for the three months ended
September 30, 2003, was $2.3 million, an increase of $0.9 million, or 58%, from
$1.4 million for the three months ended September 30, 2002. The increase was
primarily due to an increase in reclaimed oil income of $0.6 million due to
higher prices.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses, including taxes, were $11.8 million for the three
months ended September 30, 2003, an increase of $2.2 million, or 23%, over the
2002 expense of $9.6 million. Production taxes increased $0.4 million due to
higher oil and gas prices in 2003 and energy costs increased $1.5 million due to
higher utility costs in 2003 associated with the Cedar Hills Field. The balance
of the increase was due to higher labor costs and an increase in workover and
other expenses.
EXPLORATION EXPENSES
For the three months ended September 30, 2003, our exploration expenses
increased $1.0 million, or 40%, to $3.5 million from $2.5 million during the
comparable period of 2002. The increase was mainly due to an increase in seismic
costs of $0.8 million and geological costs of $0.1 million.
CRUDE OIL MARKETING
For the three months ended September 30, 2003, we recognized an expense of
$39.0 million, an increase of $5.6 million, or 17% compared to $33.4 million for
the three months ended September 30, 2002. Higher oil prices resulted in the
increased cost in 2003.
GATHERING, MARKETING, AND PROCESSING
During the three months ended September 30, 2003, we incurred gathering,
marketing and processing expenses of $22.1 million, representing a $14.4
million, or 187%, an increase from $7.7 million incurred in the third quarter of
2002 due to greater volumes processed and higher natural gas and liquids prices
on products we purchased for resale. The acquisition of the Carmen Gathering
System , effective August 1, 2003, attributed $3.1 million in expenses in the
third quarter of 2003.
OIL AND GAS SERVICE OPERATIONS
During the three months ended September 30, 2003, we incurred oil and gas
service operations expense of $2.1 million, a $0.3 million, or 17%, increase
over the $1.8 million for the comparable period in 2002. The increase was due to
the increased cost of purchasing and treating reclaimed oil for resale.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES ("DD&A")
For the three months ended September 30, 2003, DD&A of our oil and gas
properties increased $3.6 million, or 80%, to $8.1 million from $4.5 million for
the comparable period in 2002. In the third quarter of 2003, our DD&A expense on
oil and gas properties was calculated at $6.37 per BOE compared to $3.23 per BOE
for the third quarter of 2002. The adoption of SFAS No. 143 on January 1, 2003,
has decreased our DD&A $0.8 million offset by an increase in DD&A rates for the
third quarter of 2003.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT
("DD&A")
For the three months ended September 30, 2003, DD&A of our other property
and equipment increased $0.1 million, or 15%, to $1.2 million from $1.1 million
for the comparable period in 2002.
PROPERTY IMPAIRMENTS
For the three months ended September 30, 2003, our property impairments
expense increased $0.7 million, or 115%, to $1.3 million from $0.6 million for
the same period in 2002. The increase was due to an increase in reserves for
impairment associated with our undeveloped leasehold.
At September 30, 2003, we had approximately $13.5 million capitalized
related to certain proved undeveloped reserves and approximately $3.3 million
capitalized related to certain proved non-producing reserves (acid fracs)
acquired in 1998. A third party is currently in the process of reviewing the
proved undeveloped reserves. The results of the third party review are
anticipated in the fourth quarter. No impairments were indicated at September
30, 2003; however, it is possible these costs could be impaired at some future
date.
ASSET RETIREMENT ACCRETION
For the three months ended September 30, 2003, our asset retirement
accretion was $0.3 million due to the adoption of SFAS No. 143 on January 1,
2003.
GENERAL AND ADMINISTRATIVE ("G&A")
For the three months ended September 30, 2003, our G&A expense was $2.7
million, a decrease of $0.2 million, or 7%, from $2.9 million for the three
months ended September 30, 2002. Our G&A expense per BOE for the third quarter
of 2003 was $2.09 compared to $2.23 for the third quarter of 2002. The decrease
in G&A expense is due to more supervision per joint operating agreements being
billed out to third parties in the third quarter of 2003 than the third quarter
of 2002.
INTEREST EXPENSE
For the three months ended September 30, 2003, our interest expense was
$5.1 million, an increase of $0.4 million, or 9%, from $4.7 million for the
three months ended September 30, 2002. This increase was due to additional
interest paid on our credit facility due to higher average debt balances
outstanding.
NET INCOME
For the three months ended September 30, 2003, our net income was $3.0
million, a decrease of $0.6 million, or 17%, from $3.6 million for the
comparable period in 2002.
NINE MONTHS ENDED SEPTEMBER 30, 2003, COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 2002.
REVENUES
GENERAL
Our revenues increased $53.9 million, or 24%, to $281.1 million during the
nine months ended September 30, 2003, from $227.2 million during the comparable
period in 2002. The increase is attributable to higher oil and gas prices and
higher gathering, marketing and processing revenues at September 30, 2003,
compared to September 30, 2002.
OIL AND GAS SALES
Our oil and gas sales revenue for the nine months ended September 30, 2003,
increased $23.4 million, or 29%, to $103.4 million from $80.0 million during the
comparable period in 2002. Oil sales revenue for the nine months of 2003
increased $4.0 million, or 6%, to $68.1 million from $64.1 million in 2002. Oil
production decreased by 224 MBbls to 2,645 MBbls, or 8%, for the nine months
ended September 30, 2003, from 2,869 MBbls for the comparable period in 2002.
The oil production decrease includes 107 MBbls as a result of converting
producing wells into injection wells in the Cedar Hills Field. Oil prices,
including hedging, increased $3.39 Bbl to an average of $25.75 Bbl, or 15%,
during the nine months ended September 30, 2003, from $22.36 Bbl, for the
comparable 2002 period. Gas sales revenue increased $19.4 million, or 122%, to
$35.3 million for the nine-month period in 2003 compared to $15.9 million in
2002. Gas production for the period increased 482 MMcf, or 7%, to 7,496 MMcf
from 7014 MMcf in 2002. The increase in gas sales revenues is primarily
attributable to higher gas prices that averaged $4.71 Mcf in the first nine
months of 2003 compared to $2.27 Mcf in the first nine months of 2002, or an
increase of $2.44 per Mcf, or 107%.
CRUDE OIL MARKETING
Since May 2002, we have had third party contracts to purchase and resell
only our own production. We will continue to repurchase our production from the
Rocky Mountain area and resell equivalent barrels in Oklahoma to take advantage
of better pricing and to reduce our credit exposure from sales to our first
purchaser. We present sales and purchases of our production from the Rocky
Mountain area on a gross basis as crude oil marketing income and crude oil
marketing expense, respectively.
During the nine month period ended September 30, 2003, we recognized
revenues of $120.0 million in crude oil marketing revenue compared to $120.5
million for the nine-month period ended September 30, 2002. This $0.5 million
decrease in marketing revenue resulted from a reduction in volumes marketed,
offset by an increase in oil prices.
DERIVATIVE
We have fixed price physical delivery contracts in place to deliver
approximately 93,000 barrels of our forecasted crude oil production per month
through December 2003 at an average price of $24.66 per barrel. These contracts
are considered to be in the normal course of business and have been designated
as such, thus the contracts are not accounted for as derivatives under Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. Revenues from these firm commitments are recognized as
production occurs.
In addition to the above contracts, we also have a crude oil derivative
contract in place at September 30, 2003, which is being marked to market under
SFAS No. 133 with changes in fair value being recorded in earnings as such
contract does not qualify for special hedge accounting nor does such contract
meet the criteria to be considered in the normal course of business. This
contract provides for a fixed price of $24.25 per barrel on 30,000 barrels of
crude oil per month through December 2003 when market prices exceed $19.00 per
barrel. When market prices fall below $19.00, we receive the market price.
During the nine month period ended September 30, 2003, we recorded a gain of
$0.9 million in change in derivative fair value to reflect the mark-to-market
valuation at September 30, 2003.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue in the first nine months of
2003 was $50.1 million, an increase of $25.6 million, or 105%, from $24.5
million in the same period in 2002. This increase in revenue for the 2003 period
was attributable to greater volumes processed and higher natural gas and liquids
prices. The acquisition of the Carmen Gathering System, effective August 1,
2003, attributed $3.7 million to revenues from acquisition to September 30,
2003.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenue for the nine months ended
September 30, 2003, was $6.6 million, an increase of $2.3 million, or 54%, from
$4.3 million for the nine months ended September 30, 2002. The increase was
primarily due to an increase in reclaimed oil income of $1.9 million due to
higher prices.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses, including taxes, were $35.1 million for the nine
months ended September 30, 2003, an increase of $8.1 million, or 30%, over the
2002 expense of $27.0 million. Production taxes increased $2.0 million due to
higher oil and gas prices in 2003 and energy costs increased $3.8 million due to
higher utility costs in 2003 associated with the Cedar Hills Field. The balance
of the increase was due to higher labor costs of $0.8 million and an increase in
workover and other expenses of $1.6 million.
EXPLORATION EXPENSES
For the nine months ended September 30, 2003, our exploration expenses
increased $2.3 million, or 46%, to $7.5 million from $5.2 million during the
comparable period of 2002. The increase was mainly due to an increase in dry
hole costs of $0.9 million, geological costs of $0.2 million and seismic costs
of $0.9 million.
CRUDE OIL MARKETING
For the nine months ended September 30, 2003, we recognized an expense of
$118.9 million; a decrease of $0.8 million compared to $119.7 million for the
nine months ended September 30, 2002. The decrease was due to less volume
marketed in 2003.
GATHERING, MARKETING, AND PROCESSING
During the nine months ended September 30, 2003, we incurred gathering,
marketing and processing expenses of $46.7 million, representing a $25.5
million, or 120%, increase from $21.2 million incurred in the nine months ended
September 30, 2002, due to greater volumes processed and higher natural gas and
liquids prices on products we purchased for resale. The acquisition of the
Carmen Gathering System, effective August 1, 2003, attributed $3.1 million to
expenses from acquisition to September 30, 2003.
OIL AND GAS SERVICE OPERATIONS
During the nine months ended September 30, 2003, we incurred oil and gas
service operations expense of $6.0 million, a $1.2 million, or 24%, increase
over the $4.8 million for the comparable period in 2002. The increase was due to
the increased cost of purchasing and treating reclaimed oil for resale.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES ("DD&A")
For the nine months ended September 30, 2003, DD&A of our oil and gas
properties increased $4.9 million, or 26%, to $23.4 million from $18.5 million
for the comparable period in 2002. In the first nine months of 2003, our DD&A
expense on oil and gas properties was calculated at $6.00 per BOE compared to
$4.59 per BOE for the first nine months of 2002. The adoption of SFAS No. 143 on
January 1, 2003 has decreased our DD&A $2.3 million offset by an increase in
DD&A rates.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT
("DD&A")
For the nine months ended September 30, 2003, DD&A of our other property
and equipment increased $0.5 million, or 15%, to $3.6 million from $3.1 million
for the comparable period in 2002.
PROPERTY IMPAIRMENTS
For the nine months ended September 30, 2003, our property impairments
expense increased $2.3 million, or 135%, to $3.9 million from $1.6 million for
the same period in 2002. The increase was due to an increase in reserves for
impairment associated with our undeveloped leasehold.
At September 30, 2003, we had approximately $13.5 million capitalized
related to certain proved undeveloped reserves and approximately $3.3 million
capitalized related to certain proved non-producing reserves (acid fracs)
acquired in 1998. A third party is currently in the process of reviewing the
proved undeveloped reserves. The results of the third party review are
anticipated in the fourth quarter. No impairments were indicated at September
30, 2003; however, it is possible these costs could be impaired at some future
date.
ASSET RETIREMENT ACCRETION
For the nine months ended September 30, 2003, our asset retirement
accretion was $1.1 million due to the adoption of SFAS No. 143 on January 1,
2003.
GENERAL AND ADMINISTRATIVE ("G&A")
For the nine months ended September 30, 2003, our G&A expense was $8.4
million, an increase of $0.5 million, or 6%, from $7.9 million for the nine
months ended September 30, 2002. Our G&A expense per BOE for the nine months of
2003 was $2.15 compared to $1.96 for the nine months of 2002.
INTEREST EXPENSE
For the nine months ended September 30, 2003, our interest expense was
$15.0 million, an increase of $1.6 million or 12%, from $13.4 million in the
nine months ended September 30, 2002. Our interest expense increased in the 2003
period due to higher average debt balances outstanding.
NET INCOME
For the nine months ended September 30, 2003, our net income was $16.3
million, an increase of $11.1 million or 217%, from $5.2 million for the
comparable period in 2002. The adoption of SFAS No. 143 on January 1, 2003
resulted in a cumulative effect adjustment of $4.1 million that increased net
income.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Our net cash provided by operating activities for the nine months ended
September 30, 2003, was $48.8 million, an increase of $23.2 million, or 91%,
from $25.6 million during the comparable 2002 period primarily attributable to
higher oil and gas sales and the change in working capital, namely accounts
payable.. Our cash balance as of September 30, 2003, was $3.0 million, an
increase of $0.5 million, or 20%, from the balance of $2.5 million held at
December 31, 2002.
DEBT
Our long-term debt at December 31, 2002, was $244.7 million and at
September 30, 2003, $286.9 million. During the quarter ended March 31, 2002, we
entered into a Fourth Amended and Restated Credit Agreement in which our
syndicated bank group agreed to provide a $175.0 million senior secured
revolving credit facility with a current borrowing base of $140.0 million. On
June 12, 2003, our borrowing base was increased to $150.0 million. At September
30, 2003, we had outstanding $127.2 million principal amount in senior
subordinated notes, $148.4 million of outstanding debt under our credit
facility, and $14.7 million outstanding in capital lease agreements. On October
22, 2003, we executed the Second Amendment to the Credit Agreement and deleted
CGI as a guarantor under the Credit Agreement. The borrowing base under the
Second Amendment to the Credit Agreement was revised to $145.0 million and the
outstanding balance was reduced by the $17.0 million we received from CGI.
CREDIT FACILITY
Long-term debt outstanding at September 30, 2003, included $148.4 million
of revolving credit debt under our credit facility. The effective rate of
interest under the credit facility was 3.4% at September 30, 2003. The credit
facility, which matures March 28, 2005, charges interest based on a rate per
annum equal to the rate at which eurodollar deposits for one, two, three or nine
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 borrowing base of our credit facility
was revised on October 22, 2003, and currently is $145.0 million. The borrowing
base, which is based on our reserves, is re-determined semi-annually.
Subsequent to September 30, 2003, Continental Gas, Inc. ("CGI"), a wholly
owned subsidiary, closed on 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 secured revolving credit facility of up to $10.0 million (individually,
the "Term Loan Facility" and the "Revolving Loan Facility" and, collectively,
the "CGI Credit Facility"). The initial advance under the Term Loan Facility was
$17.0 million, which was used to repay borrowings under our credit facility that
funded the Carmen Gathering System acquisition. No funds were initially advanced
under the Revolving Loan Facility. Advances under either facility can be made,
at the borrower's election, as reference rate loans or LIBOR loans and, with
respect to LIBOR loans, for interest periods of one, two, three or six months.
Interest is payable on reference rate loans monthly and on LIBOR loans at the
end of the applicable interest period. The principal amount of the Term Loan
Facility is to be amortized on a quarterly basis through June 30, 2006, the
final payment being due September 30, 2006. The amount available under the
Revolving Loan Facility may be borrowed, repaid and reborrowed until maturity on
September 30, 2006. Interest on reference rate loans is calculated with
reference to a rate equal to the higher of the reference rate of Union Bank of
California, N.A. or the federal funds rate plus 0.5% (the "Reference Rate").
Interest on LIBOR loans is calculated with reference to the London interbank
offered interest rate (the "LIBOR Rate"). Interest accrues at the Reference Rate
or the LIBOR Rate, as applicable, plus, in either case, the applicable margin.
The applicable margin is based on the then current senior debt to EBITDA ratio.
The CGI Credit Facility contains certain covenants including covenants requiring
that:
o CGI maintain a certain interest charge coverage ratio;
o CGI maintain a certain fixed charge coverage ratio;
o CGI not exceed specified debt senior levels.
In addition, the CGI Credit Agreement limits the ability of CGI to, among other
things:
o Incur indebtedness;
o Engage in certain mergers and consolidations, liquidations and
dissolutions;
o Engage in certain asset sales;
o Make loans to others; and
o Make investments and acquisition, with certain exceptions.
The CGI Credit Agreement requires certain mandatory prepayments of 75% of excess
cash flow.
Our line of credit agreement contains certain negative financial reporting
covenants. We were not in compliance with the covenant that requires that we
maintain a minimum current ratio of 1.0:1. However, on a pro-forma basis giving
the effects of the Second Amended Credit Agreement, we were in compliance. We
received a waiver for non-compliance from the bank group.
CAPITAL EXPENDITURES
Our 2003 capital expenditures budget, exclusive of acquisitions, has been
revised to $108.8 million, of which $42.6 million is dedicated to our Cedar
Hills secondary recovery project. During the nine months ended September 30,
2003, we incurred $83.9 million of capital expenditures, exclusive of
acquisitions, compared to $74.4 million, exclusive of acquisitions, in the
nine-month period of 2002. The $83.9 million of capital expenditures includes
$35.6 million that was used in the development of the Cedar Hills field. The
$9.5 million, or 13% increase was the result of our increased drilling activity
in the Rocky Mountain and Gulf Coast regions. We expect to fund the remainder of
our 2003 capital budget through cash flow from operations and borrowings under
our credit facility.
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 cost,
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
We are exposed to market risks in the normal course of our business
operations. Due to the volatility of oil and gas prices, we, from time to time,
have entered into financial contracts to hedge oil and gas prices as a means of
controlling our exposure to price changes. Most of our financial contracts
settle against either a NYMEX based price or a fixed price.
DERIVATIVES
The risk management process we established is designed to measure both
quantitative and qualitative risks in our businesses. We are exposed to market
risk, including changes in interest rates and certain commodity prices. To
manage the volatility relating to these exposures, periodically we enter into
various derivative transactions pursuant to our policies on hedging practices.
Derivative positions are monitored using techniques such as mark-to-market
valuation and value-at-risk and sensitivity analysis.
We had a derivative contract in place at September 30, 2003, which is being
marked to market under SFAS No. 133 with changes in fair value being recorded in
earnings as such contract does not qualify for special hedge accounting nor does
such contract meet the criteria to be considered in the normal course of
business. Such contract provides for a fixed price of $24.25 per barrel on
30,000 barrels of crude oil per month through December 2003 when market prices
exceed $19.00 per barrel. However, if the average NYMEX spot crude oil price is
$19.00 per barrel or less, no payment is required of the counterparty. If NYMEX
spot crude oil prices during the month average more than $24.25 per barrel, we
pay the excess to the counterparty. As of September 30, 2003, we have recorded a
net unrealized loss of $0.5 million.
COMMODITY PRICE EXPOSURE
The market risk inherent in our market risk sensitive instruments and
positions is the potential loss in value arising from adverse changes in our
commodity prices. Our management believes that we are well positioned with our
mix of oil and gas reserves to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to impact the
domestic oil and gas industry. Due to the volatility of oil and gas prices, we,
from time to time, have used derivative hedging and may do so in the future as a
means of controlling our exposure to price changes. Most of our purchases are
made at either a NYMEX based price or a fixed price. Forward sales contracts
that provide for the physical delivery of our production are deemed to be normal
course of business sales and are not accounted for as derivatives. As of
September 30, 2003, we had the following fixed sales contracts in order to
mitigate our price risk exposure on our production:
Time Period Barrels per Month Price per Barrel
----------- ----------------- ----------------
10/03 to 12/03 32,375 to 33,375 $25.08
10/03 to 12/03 30,000 $24.85
10/03 to 12/03 30,000 $24.01
In April 2003, we repurchased two fixed sales contracts from September 2003
through December 2003. The fixed sales contracts were each for 30,000 barrels a
month at $25.08/Bbl and $24.01/Bbl. The cost of this transaction will be
recorded monthly for seven months at approximately $78,000/month for a total of
approximately $546,000.
The second amendment to the revolving credit agreement requires us to have
50% of our production hedged on a rolling six-month term. In October, we have
established costless collars covering 30,000 barrels of production for October
and November 2003, 85,000 barrels of production for December 2003 and 145,000
barrels of production from January 2004 thru March 2004 with a floor price of
$22.00 and an average ceiling price of $35.00.
In order to mitigate price risk exposure on production, CGI has forward
sales contracts in place that will result in the physical delivery of production
and qualify as being in the normal course of business sales and are not
accounted for as derivatives. As of September 30, 2003, CGI has 50,000 MMBTU per
month hedged from January 2004 to December 2007 at an average price of $4.579
per MMBTU. These hedges account for 9% of the total delivery point volumes and
4% of overall company throughput.
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 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.
2003
(Dollars in thousands) 2003 2004 2005 2006 Thereafter Total Fair Value
- ---------------------------------------------------------------------------------------------------
Fixed rate debt:
Senior subordinated notes
Principal amount $ - $ - $ - $ - $127,150 $127,150 $127,607
Weighted-average
interest rate 10.25% 10.25% 10.25% 10.25% 10.25%
- ---------------------------------------------------------------------------------------------------
Variable rate debt:
Credit facility
Principal amount $ - $ 2,429 $133,829 $ 12,142 $ - $148,400 $148,400
Weighted-average
interest rate 3.48% 3.45% 3.45% 3.45% 3.45%
- ---------------------------------------------------------------------------------------------------
Variable rate debt:
Capital lease agreement
Principal amount $ 834 $ 3,336 $ 3,336 $ 3,336 $ 3,819 $ 14,661 $ 14,661
Weighted-average
interest rate 3.70% 3.70% 3.70% 3.70% 3.70%
- ---------------------------------------------------------------------------------------------------
ITEM 4. CONTROLS AND PROCEDURES
The Securities and Exchange Commission's rules require that registrants
maintain disclosure controls and procedures to provide reasonable assurance that
a registrant is able to record, process, summarize and report the information
required in the registrant's quarterly and annual reports under the Securities
Exchange Act of 1934. While we believe that our existing disclosure controls and
procedures have been effective 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.
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) as of the end of the period covered
by this report, 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. CHANGES IN 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 AND REPORTS ON FORM 8-K
(a.) EXHIBITS:
DESCRIPTION
2.1 Agreement and Plan of Recapitalization of Continental Resources, Inc.
dated October 1, 2000 [2.1](4)
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)
3.3 Certificate of Incorporation of Continental Gas, Inc. [3.3](1)
3.4 Bylaws of Continental Gas, Inc., as amended and restated [3.4](1)
3.5 Certificate of Incorporation of Continental Crude Co. [3.5](1)
3.6 Bylaws of Continental Crude Co. [3.6](1)
4.1 Restated Credit Agreement dated April 21, 2000, among Continental
Resources, Inc. and Continental Gas Inc., as Borrowers and MidFirst Bank
as Agent (the "Credit Agreement") [4.4](3)
4.1.1 Form of Consolidated Revolving Note under the Credit Agreement [4.4](3)
4.1.2 Second Amended and Restated Credit Agreement among Continental Resources,
Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc.,
as Borrowers, and MidFirst Bank, dated July 9, 2001 [10.1](5)
4.1.3 Third Amended and Restated Credit Agreement among Continental Resources,
Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc.,
as Borrowers, and MidFirst Bank, dated January 17, 2002 [4.13](7)
4.1.4 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](8)
4.1.5 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](10)
4.1.6 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](11)
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)
4.3 Term and Revolving Credit Agreement by and among Continental Gas, Inc.
and Union Bank of California, N.A., as administrative agent for the
lenders, dated October 22, 2003 (11)
10.1 Unlimited Guaranty Agreement dated March 28, 2002 by Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc. to Union Bank of California, N.A., Guaranty Bank, FSB and
Fortis Capital Corp. [10.2](8)
10.2 Security Agreement dated March 28, 2002, between Registrant and Guaranty
Bank, FSB, as Agent [10.3](8)
10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent [10.4](8)
10.4 Conveyance Agreement of Worland Area Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April 23,
1984, to Continental Resources, Inc. [10.4](2)
10.5 Purchase Agreement signed January 2000, effective October 1, 1999, by and
between Patrick Energy Corporation as Buyer and Continental Resources,
Inc. as Seller [10.5](2)
10.6+ Continental Resources, Inc. 2000 Stock Option Plan [10.6](4)
10.7+ Form of Incentive Stock Option Agreement [10.7](4)
10.8+ Form of Non-Qualified Stock Option Agreement [10.8](4)
10.9 Purchase and Sales Agreement between Farrar Oil Company and Har-Ken Oil
Company, as Sellers, and Continental Resources of Illinois, Inc. as
Purchaser, dated May 14, 2001 [2.1](5)
10.10 Collateral Assignment of Contracts dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as Agent [10.5](8)
12.1 Statement re computation of ratio of debt to Adjusted EBITDA [12.1](9)
12.2 Statement re computation of ratio of earning to fixed charges [12.2](9)
12.3 Statement re computation of ratio of adjusted EBITDA to interest expense
[12.3](9)
12.0 Subsidiaries of Registrant [21](6)
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
99.1 Letter to the Securities and Exchange Commission dated March 28, 2002,
regarding the audit of the Registrant's financial statements by Arthur
Andersen LLP [99.1](7)
- ----------------------------
* 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, 1999. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(3) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
the fiscal quarter ended March 31, 2000. The exhibit number is indicated
in brackets and is incorporated herein by reference.
(4) 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.
(5) Filed as an exhibit to report on Form 8-K dated July 18, 2001. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(6) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
the fiscal quarter ended June 30, 2001. The exhibit number is indicated
in brackets and is incorporated herein by reference.
(7) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(8) Filed as an exhibit to report on Form 8-K dated April 11, 2002. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(9) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2002. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(10) 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.
(11) Filed as an exhibit to report on Form 8-K dated October 31, 2003. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(b.) REPORTS ON FORM 8-K:
On October 31, 2003, the Registrant filed a current report on Form 8-K
describing the Second Amended and Restated Credit Agreement with Union Bank of
California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. and Continental
Gas Inc.'s new Term and Revolving Credit Agreement with Union Bank of
California, N.A., Fortis Capital Corp., and Wells Fargo Bank of Texas, N.A.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Continental Resources, Inc.
Date: November 13, 2003 By: /s/ Roger V. Clement
Roger V. Clement
Senior Vice President and Chief
Financial Officer
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
--- ----------- ----------------
2.1 Agreement and Plan of Recapitalization Incorporated herein by reference
of Continental Resources, Inc. dated
October 1, 2000
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.
3.3 Certificate of Incorporation of Incorporated herein by reference
Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as Incorporated herein by reference
amended and restated
3.5 Certificate of Incorporation of Incorporated herein by reference
Continental Crude Co.
3.6 Bylaws of Continental Crude Co. Incorporated herein by reference
4.1 Restated Credit Agreement dated April Incorporated herein by reference
21, 2000, among Continental Resources,
Inc. and Continental Gas Inc., as
Borrowers and MidFirst Bank as Agent
(the "Credit Agreement")
4.1.1 Form of Consolidated Revolving Note Incorporated herein by reference
under the Credit Agreement
4.1.2 Second Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois,
Inc., as Borrowers, and MidFirst Bank,
dated July 9, 2001
4.1.3 Third Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois,
Inc., as Borrowers, and MidFirst Bank,
dated January 17, 2002
4.1.4 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.
4.1.5 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.
4.1.6 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.
4.2 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
4.3 Term and Revolving Credit Agreement by Incorporated herein by reference
and among Continental Gas, Inc. and
Union Bank of California, N.A., as
administrative agent for the lenders,
dated October 22, 2003
10.1 Unlimited Guaranty Agreement dated Incorporated herein by reference
March 28, 2002 by Continental
Resources, Inc., Continental Gas, Inc.
and Continental Resources of Illinois,
Inc. to Union Bank of California, N.A.,
Guaranty Bank, FSB and Fortis Capital
Corp.
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 Conveyance Agreement of Worland Area Incorporated herein by reference
Properties from Harold G. Hamm, Trustee
of the Harold G. Hamm Revocable
Intervivos Trust dated April 23, 1984,
to Continental Resources, Inc.
10.5 Purchase Agreement signed January 2000, Incorporated herein by reference
effective October 1, 1999, by and
between Patrick Energy Corporation as
Buyer and Continental Resources, Inc.
as Seller
10.6 Continental Resources, Inc. 2000 Stock Incorporated herein by reference
Option Plan
10.7 Form of Incentive Stock Option Incorporated herein by reference
Agreement
10.8 Form of Non-Qualified Stock Option Incorporated herein by reference
Agreement
10.9 Purchase and Sales Agreement between Incorporated herein by reference
Farrar Oil Company and Har-Ken Oil
Company, as Sellers, and Continental
Resources of Illinois, Inc. as
Purchaser, dated May 14, 2001
10.10 Collateral Assignment of Contracts Incorporated herein by reference
dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as
Agent
12.1 Statement re computation of ratio of Incorporated herein by reference
debt to Adjusted EBITDA
12.2 Statement re computation of ratio of Incorporated herein by reference
earning to fixed charges
12.3 Statement re computation of ratio of Incorporated herein by reference
adjusted EBITDA to interest expense
12.0 Subsidiaries of Registrant Incorporated herein by reference
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
99.1 Letter to the Securities and Exchange Incorporated herein by reference
Commission dated March 28, 2002,
regarding the audit of the Registrant's
financial statements by Arthur Andersen
LLP