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 June 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 August 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...............................................13
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk ..........19
ITEM 4. Controls and Procedures..............................................20
PART II. Other Information
ITEM 1. Legal Proceedings ...................................................21
ITEM 2. Changes in Securities and Use of Proceeds ...........................21
ITEM 3. Defaults Upon Senior Securities .....................................21
ITEM 4. Submission of Matters to a Vote of Security Holders .................21
ITEM 5. Other Information ...................................................21
ITEM 6. Exhibits and Reports on Form 8-K.....................................21
Signatures....................................................................23
PART I. Financial Information
ITEM 1. FINANCIAL STATEMENTS
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share data)
December 31, June 30,
------------ --------
2002 2003
---- ----
CURRENT ASSETS: (Unaudited)
Cash $ 2,520 $ 3,659
Accounts receivable:
Oil and gas sales 14,756 15,478
Joint interest and other, net 7,884 9,563
Inventories 6,700 7,893
Prepaid expenses 482 328
Fair value of derivative contracts 628 1,375
--------- ---------
Total current assets 32,970 38,296
PROPERTY AND EQUIPMENT, AT COST:
Oil and gas properties, based on
successful efforts accounting
Producing properties 488,432 546,960
Nonproducing leaseholds 33,781 34,222
Gas gathering and processing facilities 33,113 35,323
Service properties, equipment and other 18,430 18,859
--------- ---------
Total property and equipment 573,756 635,364
Less - Accumulated depreciation,
depletion and amortization (205,853) (201,897)
--------- ---------
Net property and equipment 367,903 433,467
OTHER ASSETS:
Debt issuance costs 5,796 5,112
Other assets 8 8
--------- ---------
Total other assets 5,804 5,120
--------- ---------
Total assets $ 406,677 $ 476,883
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share data)
December 31, June 30,
------------ --------
2002 2003
---- ----
CURRENT LIABILITIES: (Unaudited)
Accounts payable $ 26,665 $ 24,042
Current portion of long term debt 2,400 2,400
Revenues and royalties payable 5,299 5,448
Accrued liabilities and other 10,320 11,148
Fair value of derivative contracts 2,082 2,424
-------- --------
Total current liabilities 46,766 45,462
LONG-TERM DEBT, net of current portion 244,705 266,505
ASSET RETIREMENT OBLIGATION - 36,407
OTHER NON-CURRENT LIABILITIES 125 148
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 89,850 103,130
-------- --------
Total stockholders' equity 115,081 128,361
-------- --------
Total liabilities and stockholders' equity $406,677 $476,883
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended June 30,
---------------------------
(Dollars in thousands, except share data) 2002 2003
---- ----
REVENUES: (As restated)
Oil and gas sales $ 27,717 $ 33,347
Crude oil marketing income 38,442 39,753
Change in derivative fair value (38) 104
Gathering, marketing and processing 8,994 17,125
Oil and gas service operations 1,849 2,423
-------- --------
Total revenues 76,964 92,752
OPERATING COSTS AND EXPENSES:
Production expenses 7,412 9,598
Production taxes 1,952 2,361
Exploration expenses 871 2,551
Crude oil marketing expenses 38,185 39,392
Gathering, marketing and processing 7,842 15,793
Oil and gas service operations 1,364 1,933
Depreciation, depletion and amortization of oil and gas properties 6,670 6,914
Depreciation and amortization of other assets 1,034 1,231
Property impairments 397 1,276
Asset retirement obligation accretion expense - 358
General and administrative 2,518 2,850
-------- --------
Total operating costs and expenses 68,245 84,257
OPERATING INCOME 8,719 8,495
OTHER INCOME (EXPENSES):
Interest income 63 28
Interest expense (4,687) (4,964)
Other income, net (43) 13
Gain on sale of assets 40 277
-------- --------
Total other income (expense) (4,627) (4,646)
-------- --------
NET INCOME $ 4,092 $ 3,849
======== ========
EARNINGS PER COMMON SHARE:
Basic $ 0.28 $ 0.27
======= =======
Diluted $ 0.28 $ 0.27
======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Six Months Ended June 30,
-------------------------
(Dollars in thousands, except share data) 2002 2003
---- ----
REVENUES: (As restated)
Oil and gas sales $ 50,446 $ 69,069
Crude oil marketing income 87,019 80,348
Change in derivative fair value (1,263) 407
Gathering, marketing and processing 16,157 26,850
Oil and gas service operations 2,840 4,305
--------- ---------
Total revenues 155,199 180,979
OPERATING COSTS AND EXPENSES:
Production expenses 13,901 18,228
Production taxes 3,487 5,035
Exploration expenses 2,655 4,053
Crude oil marketing expenses 86,349 79,876
Gathering, marketing and processing 13,232 24,621
Oil and gas service operations 3,043 3,893
Depreciation, depletion and amortization of oil and gas properties 14,023 15,217
Depreciation and amortization of other assets 2,055 2,379
Property impairments 1,034 2,552
Asset retirement obligation accretion expense - 709
General and administrative 5,305 5,689
--------- ---------
Total operating costs and expenses 145,084 162,252
OPERATING INCOME 10,115 18,727
OTHER INCOME (EXPENSES):
Interest income 166 59
Interest expense (8,751) (9,916)
Other income, net (29) 50
Gain on sale of assets 65 270
--------- ---------
Total other income (expense) (8,549) (9,537)
--------- ---------
NET INCOME BEFORE
CHANGE IN ACCOUNTING PRINCIPLE 1,566 9,190
--------- ---------
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE - 4,090
--------- ---------
NET INCOME $ 1,566 $ 13,280
========= =========
BASIC EARNINGS PER COMMON SHARE:
Earnings before cumulative effect of accounting change $ 0.11 $ 0.64
Cumulative effect of accounting change - 0.28
--------- ---------
Basic $ 0.11 $ 0.92
========= =========
DILUTED EARNINGS PER COMMON SHARE:
Earnings before cumulative effect of accounting change $ 0.11 $ 0.64
Cumulative effect of accounting change - 0.28
--------- ---------
Diluted $ 0.11 $ 0.92
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited)
(Dollars in thousands)
Six Months Ended June 30,
-------------------------
2002 2003
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES: (As restated)
Net income $ 1,566 $ 13,280
Adjustments to reconcile net income to net cash
provided by operating activities-
Depreciation, depletion and amortization 16,078 17,596
Accretion of asset retirement obligation - 709
Impairment of properties - 2,552
Change in derivative fair value - (407)
Amortization of debt issuance costs 523 791
Gain on sale of assets (65) (450)
Gain on change in accounting principle - (4,090)
Dry hole costs 1,697 2,775
Cash provided by (used in) changes in assets and liabilities-
Accounts receivable (1,984) (2,401)
Inventories (542) (1,143)
Prepaid expenses 178 154
Accounts payable (4,088) (2,623)
Revenues and royalties payable 688 149
Accrued liabilities and other 1,240 828
Other noncurrent liabilities 21 23
Other noncurrent assets - -
-------- --------
Net cash provided by operating activities 15,312 27,743
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (41,643) (45,912)
Undeveloped leasehold - (4,010)
Gas gathering and processing facilities, service
properties, equipment and other (3,624) (2,806)
Purchase of oil and gas properties (55) (83)
Proceeds from sale of assets 86 4,482
-------- --------
Net cash used in investing activities (45,236) (48,329)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 98,830 23,000
Repayment of line of credit and other (69,575) (1,200)
Debt issuance costs (2,188) (75)
-------- --------
Net cash provided by financing activities 27,067 21,725
NET INCREASE (DECREASE) IN CASH (2,857) 1,139
CASH, beginning of period 7,225 2,520
-------- --------
CASH, end of period $ 4,368 $ 3,659
======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 7,478 $ 9,777
Asset retirement obligation at January 1, 2003 - 35,173
Capitalized asset retirement-obligation, net - 39,263
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO 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 consolidated financial statements contain all adjustments
necessary to present fairly the Company's financial position as of June 30,
2003, the results of operations and cash flows for the three and six months
ended June 30, 2002 and 2003. The unaudited 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 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, 2002. Certain reclassifications have been made to prior
period amounts to conform to the current period presentation.
2. LONG-TERM DEBT:
Long-term debt as of December 31, 2002, and June 30, 2003, consisted of the
following:
(Dollars in thousands) December 31, June 30,
2002 2003
---- ----
Senior Subordinated Notes $127,150 $127,150
Credit Facility 108,000 131,000
Capital Lease Agreement 11,955 10,755
-------- --------
Outstanding Debt 247,105 268,905
Less Current Portion 2,400 2,400
-------- --------
Total Long-Term Debt $244,705 $266,505
======== ========
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 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. The Company paid approximately $2.2 million in debt
issuance fees for the new credit facility. The credit facility matures on March
28, 2005. As of June 30, 2003, the Company had $131.0 million outstanding debt
on its line of credit. Subsequent to June 30, 2003 we borrowed an additional
$17.4 million on our credit line to purchase the Carmen Gathering System (Note
8) and for other general corporate purposes.
3. CRUDE OIL MARKETING:
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
quarter ended June 30, 2003, the Company recognized revenues from the sale of
crude oil of $39.8 million and expenses for the purchase of crude oil of $39.4
million, resulting in a gain from crude oil marketing activities during the
quarter of $0.4 million.
4. 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 in 2002 and 2003. The weighted-average
number of shares used to compute diluted earnings per share was 14,416,469 for
2003.
5. 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 June 30,
2003, and for the three-month and six-month periods ended June 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 June 30, 2003
- --------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Current Assets $ 8,144 $ 51,565 $ (21,413) $ 38,296
Property and Equipment 47,265 386,202 - 433,467
Other Assets 7 5,127 (14) 5,120
Total Assets $ 55,416 $442,894 $ (21,427) $476,883
Current Liabilities $ 12,493 $ 40,178 $ (7,209) $ 45,462
Long-Term Debt 14,204 266,505 (14,204) 266,505
Other Liabilities 4,048 32,507 - 36,555
Stockholders' Equity 24,671 103,704 (14) 128,361
Total Liabilities and
Stockholders' Equity $ 55,416 $442,894 $ (21,427) $476,883
Condensed Consolidating Statements of Operations
For the Three Months Ended June 30, 2002
- --------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Total Revenue $ 12,701 $ 64,336 $ (73) $ 76,964
Operating Expenses (11,606) (56,712) 73 (68,245)
Other (Expense) Income (417) (4,333) 123 (4,627)
--------- --------- -------- --------
Net Income $ 678 $ 3,291 $ 123 $ 4,092
========= ========= ======== ========
For the Three Months Ended June 30, 2003
- --------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Total Revenue $ 19,581 $ 72,401 $ 770 $ 92,752
Operating Expenses (18,382) (65,105) (770) (84,257)
Other (Expense) Income (302) (4,344) - (4,646)
--------- --------- --------- --------
Net Income $ 897 $ 2,952 $ - $ 3,849
========= ========= ======== ========
For the Six Months Ended June 30, 2002
- --------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Total Revenue $ 23,630 $ 132,449 $ (880) $ 155,199
Operating Expenses (20,983) (124,981) 880 (145,084)
Other (Expense) Income (860) (7,689) - (8,549)
--------- --------- --------- --------
Net Income $ 1,787 $ (221) $ - $ 1,566
========= ========= ======== =========
For the Six Months Ended June 30, 2003
- --------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
------------ ------ ------------ ------------
Total Revenue $ 35,426 $ 147,062 $ (1,509) $ 180,979
Operating Expenses (32,454) (131,307) 1,509 (162,252)
Other (Expense) Income (685) (8,852) - (9,537)
Change in Accounting
Principle 560 3,530 - 4,090
--------- --------- ---------- ---------
Net Income $ 2,847 $ 10,433 $ - $ 13,280
========= ========= ========== =========
At June 30, 2003, current liabilities payable to the Company by the
guarantor subsidiaries totaled approximately $20.8 million. For the three months
ended June 30, 2002 and 2003, depreciation, depletion and amortization included
in the guarantor subsidiaries operating costs were approximately $2.9 million
and $1.6 million, respectively.
6. 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 which 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 670 709
Plus: Additions for new assets 812 1,245
Less: Plugging costs and sold assets (290) (720)
-------- --------
Asset Retirement Obligation liability at June 30, $ 34,687 $ 36,407
======== ========
The following table describes the pro forma effect on net income and
earnings per share for the three and six months ended June 30, 2002, as if SFAS
No. 143 had been adopted in January 1, 2002.
Three Months Six Months
Ended June 30, Ended June 30,
2002 2002
---- ----
Net income - as reported $ 4,092 $ 1,566
Less: Asset retirement obligation accretion expense (335) (670)
Plus: Reduction in depreciation expense on salvage value 1,220 2,440
---------- ---------
Net income - pro forma $ 4,977 $ 3,336
========== =========
Earnings per share:
As reported
Basic $ 0.28 $ 0.11
Diluted $ 0.28 $ 0.11
Pro Forma
Basic $ 0.35 $ 0.23
Diluted $ 0.35 $ 0.23
7. 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. It applies in the first fiscal
year or interim period beginning after June 15, 2003, to variable interest
entities in which an enterprise holds a variable interest that it acquired
before February 1, 2003. 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 is not expected to 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. The Company adopted this new standard effective July 1, 2003 and the
adoption of this new standard is not expected to have a material impact on its
consolidated financial position or results of operations.
8. SUBSEQUENT EVENTS:
ACQUISITIONS AND FINANCING
CGI acquired the Carmen Gathering System located in western Oklahoma for
$15.0 million with an effective date of August 1, 2003. After various
adjustments and other reductions contained in the purchase and sale agreement,
the net cost to CGI was $12.0 million. The system consists of 290 miles of
pipeline connected to approximately 200 wells. The gas gathered by this system
is currently being processed by CGI at its Eagle Chief Plant. The purchase was
financed through our credit facility.
HEDGES
Section 5.35 "Required Hedging Transaction" in the first amendment to the
revolving credit agreement requires us to have 30% of our production hedged on a
rolling six-month term. To satisfy this requirement, we have established
costless collars from August 2003 thru January 2004 with a floor of $22.00 and
an average ceiling of $35.57.
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 Six Months
Ended June 30, Ended June 30,
-------------- --------------
2002 2003 2002 2003
---- ---- ---- ----
NET PRODUCTION:
Oil (MBbl) 949 882 1,884 1,789
Gas (MMcf) 2,213 2,589 4,507 4,957
Oil equivalent (MBoe) 1,319 1,314 2,638 2,615
OIL AND GAS SALES (dollars in thousands)
Oil sales, excluding hedges $ 22,983 $ 23,409 $ 41,320 $ 51,524
Hedges (769) (1,328) (709) (6,054)
--------- --------- --------- ---------
Total oil sales, including hedges 22,214 22,081 40,611 45,470
Gas sales 5,503 11,266 9,835 23,599
--------- --------- --------- ---------
Total oil and gas sales $ 27,717 $ 33,347 $ 50,446 $ 69,069
========= ========= ========= =========
AVERAGE SALES PRICE:
Oil, excluding hedges (dollar per barrel) $ 24.23 $ 26.54 $ 21.93 $ 28.81
Oil, including hedges (dollar per barrel) $ 23.42 $ 25.04 $ 21.55 $ 25.42
Gas (dollar per Mcf) $ 2.49 $ 4.35 $ 2.18 $ 4.76
Oil equivalent, excluding hedges (dollar per Boe) $ 21.60 $ 26.40 $ 19.39 $ 28.72
Oil equivalent, including hedges (dollar per Boe) $ 21.02 $ 25.39 $ 19.12 $ 26.41
EXPENSES (dollars per Boe):
Production expenses (including taxes) $ 7.10 $ 9.10 $ 6.59 $ 8.89
General and administrative $ 1.91 $ 2.17 $ 2.01 $ 2.18
DD&A (on oil and gas properties) $ 5.06 $ 5.26 $ 5.32 $ 5.82
THREE MONTHS ENDED JUNE 30, 2003, COMPARED TO THREE MONTHS ENDED JUNE 30, 2002.
OVERVIEW
The following discussion and analysis should be read in conjunction with
our unaudited 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 $15.8 million, or 21%, to $92,8 million during the
three months ended June 30, 2003, from $77.0 million during the comparable
period in 2002. The increase is attributable to higher oil and gas prices and
gathering, marketing and processing revenues in the second quarter of 2003
compared to the second quarter of 2002.
OIL AND GAS SALES
Our oil and gas sales revenue for the three months ended June 30, 2003,
increased $5.6 million, or 20%, to $33.3 million from $27.7 million during the
comparable period in 2002. Oil sales revenue decreased $0.1 million to $22.1
million for the three months of 2003 from $22.2 million in 2002. Oil production
decreased by 67 MBbls to 882 MBbls, or 7%, for the three months ended June 30,
2003 from 949 MBbls for the comparable period in 2002. The oil production
decrease of 67 MBbls includes 30 MBbls as the result of converting producing
wells into injection wells in the Cedar Hills Field. Oil prices, including
hedging, increased $1.62 Bbl to an average of $25.04 Bbl, or 7%, during the
three months ended June 30, 2003, from $23.42 Bbl, for the comparable 2002
period. Gas sales revenue increased $5.7 million, or 104%, to $11.2 million for
the three-month period in 2003 compared to $5.5 million in 2002. Gas production
for the period increased 376 MMcf, or 17%, to 2,589 MMcf from 2,213 MMcf in
2002. The increase in gas sales revenues is primarily attributable to higher gas
prices that averaged $4.35 Mcf in the second quarter of 2003 compared to $2.49
Mcf in the second quarter of 2002, or an increase of $1.86 per Mcf, or 75%.
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 as crude oil marketing income and crude oil marketing expense,
respectively.
During the three month period ended June 30, 2003, we recognized revenues
of $39.8 million in crude oil marketing income compared to $38.4 million for the
three-month period ended June 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, we also have a crude oil derivative
contract in place at June 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
three month period ended June 30, 2003, we recorded a gain of $104,000 in change
in derivative fair value to reflect the mark-to-market valuation at June 30,
2003.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue in the second quarter of
2003 was $17.1 million, an increase of $8.1 million, or 90%, from $9.0 million
in the same period in 2002. This increase in revenue during the second quarter
was attributable to greater volumes processed and higher natural gas and liquids
prices.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations for the three months ended June 30,
2003, was $2.4 million, an increase of $0.6 million, or 31%, from $1.8 million
for the three months ended June 30, 2002. The increase was primarily due to an
increase in reclaimed oil income of $0.3 million due to higher prices and rental
income of $0.4 million offset by various small expenses.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses, including taxes, were $12.0 million for the three
months ended June 30, 2003, an increase of $2.6 million, or 28%, over the 2002
expense of $9.4 million. Production taxes increased $0.4 million due to higher
oil and gas prices in 2003 and energy costs increased $1.1 million due to higher
utility costs in 2003. 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 June 30, 2003, our exploration expenses
increased $1.7 million, or 192%, to $2.6 million from $0.9 million during the
comparable period of 2002. The increase was mainly due to an increase in dry
hole costs and other expenses.
CRUDE OIL MARKETING
For the three months ended June 30, 2003, we recognized an expense of $39.4
million, an increase of $1.2 million, or 3% compared to $38.2 million for the
three months ended June 30, 2002. Although marketed volumes decreased, higher
oil prices resulted in the increased revenue in 2003.
GATHERING, MARKETING, AND PROCESSING
During the three months ended June 30, 2003, we incurred gathering,
marketing and processing expenses of $15.8 million, representing an $8.0
million, or 101%, increase from $7.8 million incurred in the second quarter of
2002 due to greater volumes processed and higher natural gas and liquids prices
on natural gas we purchased for resale.
OIL AND GAS SERVICE OPERATIONS
During the three months ended June 30, 2003, we incurred oil and gas
service operations expense of $1.9 million, a $0.5 million, or 42%, increase
over the $1.4 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 June 30, 2003, DD&A of our oil and gas
properties increased $0.2 million, or 4%, to $6.9 million from $6.7 million for
the comparable period in 2002. In the second quarter of 2003, Our DD&A expense
on oil and gas properties was calculated at $5.26 per BOE compared to $5.06 per
BOE for the second quarter of 2002. The adoption of SFAS No. 143 on January 1,
2003, has decreased our DD&A $0.5 million offset by an increase in DD&A rates.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OTHER ASSETS ("DD&A")
For the three months ended June 30, 2003, DD&A of our other assets
increased $0.2 million, or 19%, to $1.2 million from $1.0 million for the
comparable period in 2002.
PROPERTY IMPAIRMENTS
For the three months ended June 30, 2003, our property impairments expense
increased $.9 million, or 221%, to $1.3 million from $0.4 million for the same
period in 2002. The increase was due to an increase in reserves for impairment.
ASSET RETIREMENT ACCRETION
For the three months ended June 30, 2003, our asset retirement accretion
was $0.4 million due to the adoption of SFAS No. 143 on January 1, 2003.
GENERAL AND ADMINISTRATIVE ("G&A")
For the three months ended June 30, 2003, our G&A expense was $2.9 million,
an increase of $0.4 million, or 13%, from $2.5 million for the three months
ended June 30, 2002. Our G&A expense per BOE for the second quarter of 2003 was
$2.17 compared to $1.91 for the second quarter of 2002.
INTEREST EXPENSE
For the three months ended June 30, 2003, our interest expense was $5.0
million, an increase of $0.3 million, or 6%, from $4.7 million for the three
months ended June 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 June 30, 2003, our net income was $3.8 million,
a decrease of $0.3 million from $4.1 million for the comparable period in 2002.
SIX MONTHS ENDED JUNE 30, 2003, COMPARED TO SIX MONTHS ENDED JUNE 30, 2002.
REVENUES
GENERAL
Our revenues increased $25.8 million, or 17%, to $181.0 million during the
six months ended June 30, 2003, from $155.2 million during the comparable period
in 2002. The increase is attributable to higher oil and gas prices and
gathering, marketing and processing revenues at June 30, 2003, compared to June
30, 2002.
OIL AND GAS SALES
Our oil and gas sales revenue for the six months ended June 30, 2003,
increased $18.6 million, or 37%, to $69.1 million from $50.5 million during the
comparable period in 2002. Oil sales revenue for the six months of 2003
increased $4.9 million, or 12%, to $45.5 million from $40.6 million in 2002. Oil
production decreased by 95 MBbls to 1,789 MBbls, or 5%, for the six months ended
June 30, 2003 from 1,884 MBbls for the comparable period in 2002. The oil
production decrease of 95 MBbls includes 23 MBbls as a result of converting
producing wells into injection wells in the Cedar Hills Field. Oil prices,
including hedging, increased $3.87 Bbl to an average of $25.42 Bbl, or 18%,
during the six months ended June 30, 2003, from $21.55 Bbl, for the comparable
2002 period. Gas sales revenue increased $13.8 million, or 140%, to $23.6
million for the six-month period in 2003 compared to $9.8 million in 2002. Gas
production for the period increased 450 MMcf, or 10%, to 4,957 MMcf from 4,507
MMcf in 2002. The increase in gas sales revenues is primarily attributable to
higher gas prices that averaged $4.76 Mcf in the first six months of 2003
compared to $2.18 Mcf in the first six months of 2002, or an increase of $2.58
per Mcf, or 118%.
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 as crude oil marketing income and crude oil marketing expense,
respectively.
During the six month period ended June 30, 2003, we recognized revenues of
$80.3 million in crude oil marketing revenue compared to $87.0 million for the
six-month period ended June 30, 2002. This $6.7 million, or 8% 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 June 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
six month period ended June 30, 2003, we recorded a gain of $0.4 million in
change in derivative fair value to reflect the mark-to-market valuation at June
30, 2003.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue in the first six months of
2003 was $26.9 million, an increase of $10.7 million, or 66%, from $16.2 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.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations for the six months ended June 30, 2003,
was $4.3 million, an increase of $1.5 million, or 52%, from $2.8 million for the
six months ended June 30, 2002. The increase was primarily due to an increase in
reclaimed oil income of $1.3 million due to higher prices.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses, including taxes, were $23.3 million for the six
months ended June 30, 2003, an increase of $5.9 million, or 34%, over the 2002
expense of $17.4 million. Production taxes increased $1.5 million due to higher
oil and gas prices in 2003 and energy costs increased $2.3 million due to higher
utility costs in 2003. The balance of the increase was due to higher labor costs
of $0.6 million and an increase in workover and other expenses of $1.5 million.
EXPLORATION EXPENSES
For the six months ended June 30, 2003, our exploration expenses increased
$1.4 million, or 53%, to $4.1 million from $2.7 million during the comparable
period of 2002. The increase was mainly due to an increase in dry hole costs and
other expenses.
CRUDE OIL MARKETING
For the six months ended June 30, 2003, we recognized an expense of $79.9
million, a decrease of $6.4 million, or 8% compared to $86.3 million for the six
months ended June 30, 2002. The decrease was due to fewer volumes marketed in
2003.
GATHERING, MARKETING, AND PROCESSING
During the six months ended June 30, 2003, we incurred gathering, marketing
and processing expenses of $24.6 million, representing an $11.4 million, or 86%,
increase from $13.2 million incurred in the six months ended June 30, 2002 due
to greater volumes processed and higher natural gas and liquids prices on
natural gas we purchased for resale.
OIL AND GAS SERVICE OPERATIONS
During the six months ended June 30, 2003, we incurred oil and gas service
operations expense of $3.9 million, an $0.9 million, or 28%, increase over the
$3.0 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 six months ended June 30, 2003, DD&A of our oil and gas properties
increased $1.2 million, or 9%, to $15.2 million from $14.0 million for the
comparable period in 2002. In the first six months of 2003, our DD&A expense on
oil and gas properties was calculated at $5.82 per BOE compared to $5.32 per BOE
for the first six months of 2002. The adoption of SFAS No. 143 on January 1,
2003 has decreased our DD&A $1.6 million offset by an increase in DD&A rates.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OTHER ASSETS ("DD&A")
For the six months ended June 30, 2003, DD&A of our other assets increased
$0.3 million, or 16%, to $2.4 million from $2.1 million for the comparable
period in 2002.
PROPERTY IMPAIRMENTS
For the six months ended June 30, 2003, our property impairments expense
increased $1.5 million, or 147%, to $2.5 million from $1.0 million for the same
period in 2002. The increase was due to an increase in reserves for impairment.
ASSET RETIREMENT ACCRETION
For the six months ended June 30, 2003, our asset retirement accretion was
$0.7 million due to the adoption of SFAS No. 143 on January 1, 2003.
GENERAL AND ADMINISTRATIVE ("G&A")
For the six months ended June 30, 2003, our G&A expense was $5.7 million,
an increase of $0.4 million, or 7%, from $5.3 million for the six months ended
June 30, 2002. Our G&A expense per BOE for the six months of 2003 was $2.18
compared to $2.01 for the six months of 2002.
INTEREST EXPENSE
For the six months ended June 30, 2003, our interest expense was $9.9
million, an increase of $1.1 million or 13%, from $8.8 million in the six months
ended June 30, 2002. Our interest expense increased in the 2003 period due to
higher average debt balances outstanding.
NET INCOME
For the six months ended June 30, 2003, our net income was $13.3 million,
an increase of $11.7 million or 748%, from $1.6 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 which increased net income.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Our net cash provided by operating activities for the six months ended June
30, 2003, was $27.7 million, an increase of $12.4 million, or 81% from $15.3
million during the comparable 2002 period. Cash as of June 30, 2003, was $3.7
million, an increase of $1.2 million 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 June 30,
2003, $266.5 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 June 30, 2003, we had $127.2 million in
senior subordinated notes, $131.0 million of outstanding debt under this credit
facility, and $8.3 million outstanding in capital lease agreements. Subsequent
to June 30, 2003 we borrowed an additional $17.4 million on our credit line to
purchase the Carmen Gathering System and for other general corporate purposes.
CREDIT FACILITY
Long-term debt outstanding at June 30, 2003, included $131.0 million of
revolving credit debt under our credit facility. The effective rate of interest
under the credit facility was 3.7% at June 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 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 borrowing base of our credit facility was increased $10.0
million on June 12, 2003, and currently is $150.0 million. The borrowing base is
re-determined semi-annually.
CAPITAL EXPENDITURES
Our 2003 capital expenditures budget, exclusive of acquisitions, has been
revised down to $90.4 million, of which $52.6 million is dedicated to our Cedar
Hills secondary recovery project. During the six months ended June 30, 2003, we
incurred $52.7 million of capital expenditures, exclusive of acquisitions,
compared to $45.3 million, exclusive of acquisitions, in the six-month period of
2002. The $52.7 million of capital expenditures includes $21.2 million that was
used in the development of the Cedar Hills field. The $7.4 million, or 16%
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 and may do so
in the future 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 June 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 June 30, 2003, we have recorded a net
unrealized gain of $0.4 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 will result in the physical delivery of our production are deemed to be
normal course of business sales and are not accounted for as derivatives. As of
June 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
----------- ----------------- ----------------
7/03 to 12/03 32,375 to 33,375 $25.08
7/03 to 12/03 30,000 $24.85
7/03 to 12/03 30,000 $24.01
In April 2003, we repurchased two fixed sales contracts from June 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.
Section 5.35 "Required Hedging Transaction" in the first amendment to the
revolving credit agreement requires us to have 30% of our production hedged on a
rolling six-month term. To satisfy this requirement, we have established
costless collars from August 2003 thru January 2004 with a floor of $22.00 and
an average ceiling of $35.57.
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 $ 127,150
Weighted-average
Interest rate 10.25% 10.25% 10.25% 10.25% 10.25% 10.25%
- ------------------------------------------------------------------------------------------------------------------------------------
Variable-rate debt:
Credit facility
Principal amount - - $ 131,000 - - $ 131,000 $ 131,000
Weighted-average
Interest rate 3.70% 3.70% 3.70% 3.70% 3.70% 3.70%
- ------------------------------------------------------------------------------------------------------------------------------------
Variable-rate debt:
Capital lease agreement
Principal amount $ 1,200 $ 2,400 $ 2,400 $ 2,400 $ 2,355 $ 10,755 $ 10,755
Weighted-average
Interest rate 3.70% 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) within 90 days of the filing of 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 Restate 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.
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](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)
21.0 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 Quarterly Report on Form 10-K for
the fiscal quarter ended December 31, 2000. The exhibit number is
indicated in brackets and is incorporated herein by reference.
(5) Filed as an exhibit to current 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 current 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.
(b.) REPORTS ON FORM 8-K
None
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: August 13, 2003 By: 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 Restate 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 Filed herewith electronically
Agreement dated June 12, 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.
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 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.
21.0 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.