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, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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)
(580) 233-8955
(Registrant's telephone number, including area code)
NONE
(Former name, former address and former fiscal year, if
change since last report)
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 X No
The Registrant is not subject to the filing requirements of Sections 13 and
15(d) of the Securities Exchange Act of 1934 (the "Act"), but files reports
required by Sections 13 and 15(d) of the Act pursuant to contractual
obligations.
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 12, 2002
Common Stock, $.01 par value 14,368,919
TABLE OF CONTENTS
PART I. Financial Information
ITEM 1. FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . 3
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . 12
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . .18
ITEM 4. CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . . . . . . . . .19
PART II. Other Information
ITEM 1. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . . . .19
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . .20
PART I. Financial Information
ITEM 1. FINANCIAL STATEMENTS
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
ASSETS
(Unaudited)
December 31, September 30,
2001 2002
--------- ---------
CURRENT ASSETS:
Cash .................................................... $ 7,225 $ 3,004
Accounts receivable-
Oil and gas sales .................................. 7,731 12,125
Joint interest and other, net ...................... 10,526 7,228
Inventories ............................................. 6,321 6,162
Prepaid expenses ........................................ 487 317
Fair value of derivative contract ....................... -- 850
--------- ---------
Total current assets .......................... 32,290 29,686
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost, based on successful
efforts accounting
Producing properties ............................... 395,559 455,813
Nonproducing leaseholds ............................ 50,889 55,924
Gas gathering and processing facilities ................. 28,176 31,795
Service properties, equipment and other ................. 17,427 18,106
--------- ---------
Total property and equipment ................ 492,051 561,638
Less--Accumulated depreciation, depletion and
amortization ................................ (174,720) (194,996)
--------- ---------
Net property and equipment .................. 317,331 366,642
--------- ---------
OTHER ASSETS:
Debt issuance costs ..................................... 4,851 6,150
Other assets ............................................ 13 11
--------- ---------
Total other assets .......................... 4,864 6,161
--------- ---------
Total assets ................................ $ 354,485 $ 402,489
========= =========
The accompanying notes are an integral part of these consolidated balances
sheets.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands, except share data)
LIABILITIES AND STOCKHOLDERS' EQUITY
(Unaudited)
December 31, September 30,
2001 2002
-------- --------
CURRENT LIABILITIES:
Accounts payable ................................................ $ 22,576 $ 17,450
Current debt .................................................... 5,400 --
Revenues and royalties payable .................................. 3,404 4,355
Accrued liabilities and other ................................... 9,906 7,162
Fair value of derivative contract ............................... -- 2,489
-------- --------
Total current liabilities ........................... 41,286 31,456
-------- --------
LONG-TERM DEBT, net of current portion .............................. 177,995 230,150
Account payable to stockholder .................................. -- 500
-------- --------
Total long-term debt ................................ 177,995 230,650
OTHER NONCURRENT LIABILITIES ........................................ 91 119
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value, 1,000,000 shares authorized,
0 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 ............................................... 109,882 115,033
-------- --------
Total stockholders' equity .......................... 135,113 140,264
-------- --------
Total liabilities and stockholders' equity .......... $354,485 $402,489
======== ========
The accompanying notes are an integral part of these consolidated balance
sheets.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED INCOME STATEMENTS
(dollars in thousands, except share data)
Three Months Ended September 30,
2001 2002
-------- --------
REVENUES:
Oil and gas sales ............................. $ 27,968 $ 29,644
Energy trading activities, net ................ 304 --
Change in derivative fair value ............... -- (757)
Gathering, marketing and processing ........... 7,616 8,319
Oil and gas service operations ................ 2,618 1,790
-------- --------
Total revenues ........................... 38,506 38,996
-------- --------
OPERATING COSTS AND EXPENSES:
Production expenses ............................ 7,269 7,424
Production taxes ............................... 1,976 2,157
Exploration expenses ........................... 4,730 2,963
Gathering, marketing and processing ............ 4,932 7,454
Oil and gas service operations ................. 1,713 1,794
Depreciation, depletion and amortization ....... 7,563 5,915
General and administrative ..................... 3,961 3,606
-------- --------
Total operating costs and expenses ........ 32,144 31,313
-------- --------
OPERATING INCOME ................................... 6,362 7,683
-------- --------
OTHER INCOME AND EXPENSES
Interest income ................................ 145 83
Interest expense ............................... (3,909) (4,344)
Other income, net .............................. 185 162
-------- --------
Total other income and (expenses) ......... (3,579) (4,099)
-------- --------
NET INCOME ......................................... $ 2,783 $ 3,584
======== ========
EARNINGS PER COMMON SHARE:
Basic ......................................... $ 0.19 $ 0.25
======== ========
Diluted ....................................... $ 0.19 $ 0.25
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED INCOME STATEMENTS
(dollars in thousands, except share data)
Nine Months Ended September 30,
2001 2002
--------- ---------
REVENUES:
Oil and gas sales ..................... $ 91,059 $ 80,566
Energy trading activities, net ........ 359 194
Change in derivative fair value ....... -- (2,020)
Gathering, marketing and processing ... 32,040 24,476
Oil and gas service operations ........ 6,683 5,846
--------- ---------
Total revenues ................... 130,141 109,062
--------- ---------
OPERATING COSTS AND EXPENSES:
Production expenses .................... 21,666 21,324
Production taxes ....................... 6,891 5,644
Exploration expenses ................... 8,901 6,252
Gathering, marketing and processing .... 25,231 20,432
Oil and gas service operations ......... 4,762 4,838
Depreciation, depletion and amortization 19,829 22,516
General and administrative ............. 9,342 10,780
--------- ---------
Total operating costs and expenses 96,622 91,786
--------- ---------
OPERATING INCOME ........................... 33,519 17,276
--------- ---------
OTHER INCOME AND EXPENSES
Interest income ........................ 559 250
Interest expense ....................... (11,115) (12,573)
Other income, net ...................... 2,170 198
--------- ---------
Total other income and (expenses) . (8,386) (12,125)
--------- ---------
NET INCOME ................................. $ 25,133 $ 5,151
========= =========
EARNINGS PER COMMON SHARE:
Basic ............................... $ 1.75 $ 0.36
========= =========
Diluted ............................. $ 1.75 $ 0.36
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
Nine Months Ended September 30,
2001 2002
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income .............................................. $ 25,132 $ 5,151
Adjustments to reconcile net income to
cash provided by operating activities--
Depreciation, depletion and amortization ............ 19,829 22,516
Change in derivative fair value ..................... -- (850)
Gain on sale of assets .............................. (2,142) (77)
Dry hole cost and impairment of undeveloped leases .. 5,416 4,019
Cash provided (used) by changes in assets and liabilities
Accounts receivable ................................. 7,346 (1,097)
Inventories ......................................... (786) 160
Prepaid expenses ................................... (204) 170
Accounts payable .................................... (4,971) (5,125)
Revenues and royalties payable ...................... (3,105) 950
Accrued liabilities and other ....................... (2,955) (2,744)
Fair value of derivative contracts .................. -- 2,489
Other noncurrent assets ............................. 342 1
Other noncurrent liabilities ...................... (14) 28
--------- ---------
Net cash provided by operating activities 43,888 25,591
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development ......................... (43,756) (69,809)
Gas gathering and processing facilities and
service properties, equipment and other ........ (2,977) (4,579)
Purchase of oil & gas properties .................. (3,303) (655)
Acquisition of Farrar Oil Company ................. (33,670) --
Proceeds from sale of assets ........................ 2,648 123
--------- ---------
Net cash used in investing activities ... (81,058) (74,920)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other .............. 42,745 116,830
Repayment of line of credit and other .......... (7,850) (69,575)
Debt issuance costs ................................. -- (2,147)
--------- ---------
Net cash provided by financing activities 34,895 45,108
--------- ---------
NET DECREASE IN CASH and CASH EQUIVALENTS ............... (2,275) (4,221)
CASH AND CASH EQUIVALENTS, beginning of period .......... 7,151 7,225
--------- ---------
CASH AND CASH EQUIVALENTS, end of period ................ $ 4,876 $ 3,004
========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid ....................................... $ 14,501 $ 15,082
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, consisting only of normal recurring adjustments, necessary to
present fairly the Company's financial position as of September 30, 2002, the
results of operations and cash flows for the three and nine month periods ended
September 30, 2001 and 2002. 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, 2001.
On June 19, 2001, the Company formed a new subsidiary, Continental
Resources of Illinois, Inc. (CRII), an Oklahoma corporation. On July 9, 2001,
the Company through CRII purchased the assets of Farrar Oil Company, Inc.
2. ACQUISITIONS:
On July 9, 2001, the Company's subsidiary, CRII, purchased the assets of
Farrar Oil Company, Inc. for $33.7 million using funds borrowed under the
Company's credit facility. This purchase was accounted for as a purchase and the
cost of the acquisition was allocated to the acquired assets and liabilities.
The allocation of the $33.7 million of purchase price on July 9, 2001, was as
follows:
Current assets $ 950
Producing properties 30,603
Non-producing properties 1,117
Service properties 1,000
---------
$ 33,670
The unaudited pro forma information set forth below includes the operations
of Farrar Oil Company, Inc. assuming the acquisition of Farrar Oil Company, Inc.
by CRII occurred on January 1, 2001. The unaudited pro forma information is
presented for information purposes only and is not necessarily indicative of the
results of operations that actually would have achieved had the acquisition been
consummated at that time:
Pro Forma Pro Forma
Three Months Ended Nine Months Ended
September 30, 2001 September 30, 2001
- ----------------------------------------------------------------------------------------------------------------------------
(dollars in thousands, except share data) Farrar CRI Consolidated Farrar CRI Consolidated
- ----------------------------------------------------------------------------------------------------------------------------
Revenue ................. $ 3,974 $ 34,532 $ 38,506 $ 16,243 $ 126,167 $ 142,410
Net Income .............. $ 737 $ 2,046 $ 2,783 $ 7,416 $ 24,396 $ 31,812
Earnings Per Common Share
Basic ................... $ 0.05 $ 0.14 $ 0.19 $ 0.52 $ 1.70 $ 2.21
Diluted ................. $ 0.05 $ 0.14 $ 0.19 $ 0.52 $ 1.70 $ 2.21
3. LONG-TERM DEBT:
Long-term debt as of December 31, 2001 and September 30, 2002, consisted of
the following:
December 31, 2001 September 30, 2002
----------------- ------------------
($ in thousands)
10.25% Senior Subordinated Notes due Aug 2008 $127,150 $127,150
Credit Facility due March 28, 2005 .......... 56,245 103,000
Note payable to principal stockholder ....... -- 500
-------- --------
Outstanding debt ....................... 183,395 230,650
Less current portion ........................ 5,400 --
-------- --------
Total long-term debt ................... $177,995 $230,650
======== ========
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 current
borrowing base of $140.0 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 September 30, 2002, the
Company had $103.0 million outstanding debt on its line of credit.
Subsequent to September 30, 2002, the Company has drawn $10.0 million on
its line of credit and currently has $113.0 million outstanding debt on its line
of credit.
4. Derivatives
We periodically utilize fixed-price physical delivery contracts and other
derivative contracts in order to reduce our exposure to unfavorable changes in
crude oil prices which are subject to significant and often volatile
fluctuation. These contracts allow us to predict with greater certainty the
effective crude oil prices to be received for our production.
In connection with our overall price risk management program, we enter into
a series of physical contracts which allow us to move our crude oil production
from the Rocky Mountain area to a central pricing hub at Cushing, Oklahoma where
the volumes are then sold to purchasers under both fixed price and variable
price physical delivery contracts. In prior periods, the purchase and sale
activity that allowed us to move this production was presented on a gross basis
as part of our energy trading activities. Beginning September 30, 2002, this
activity has been presented on a net basis as part of oil and gas sales in the
accompanying consolidated income statement (see Note 5).
At September 30, 2002, we had fixed price physical delivery contracts in
place to deliver approximately 2,010,000 barrels of our forecasted crude oil
production through January 2004 at an average price of $24.07 per barrel. These
contracts are considered to be in the normal course of business and have been
designated as such, and 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 August 2002, we elected to convert the fixed price on
200,000 barrels of crude oil covered under these firm commitments to a variable
price by entering into fixed price purchase contracts at an average price of
$25.44 per barrel. These derivative purchase contracts have been designated as
fair value hedges of a portion of the volumes covered under the firm
commitments. As required by SFAS No.133, changes in the fair value of the firm
commitment occurring subsequent to the time the hedges were designated have been
recorded in the accompanying balance sheet. As the critical terms of the
derivative contracts and firm commitment coincide, changes in the value of the
firm commitment are perfectly offset by changes in the value of the derivative
contracts.
In addition to the above contracts, we also have a crude oil derivative
contract in place at September 30, 2002, which is being marked to market under
SFAS No. 133 with changes in fair value being recorded in earnings as such
contracts 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 450,000 barrels of
crude oil through December 2003 when market prices exceed $19.00 per barrel. At
September 30, 2002, we have recorded a net unrealized loss of $2,0 million on
this contract
5. Energy Trading Activities
Historically, we have entered into third party contracts to purchase and
sell physical volumes of crude oil, exclusive of our own production, at prices
based on current month NYMEX prices, current posting prices or at fixed prices.
These contracts have been accounted for in accordance with EITF 98-10,
Accounting for Energy Trading and Risk Management Activities. This statement
requires that contracts for the purchase and sale of energy commodities which
are entered into for the purpose of speculating on market movements or otherwise
generating gains from market be recorded at their market value, as of the
balance sheet date, with any corresponding gains or losses recorded as income
from operations. Effective May 1, 2002, we have discontinued our crude oil
trading activities.
Pursuant to EITF Issue No. 99-19, Reporting Revenue Gross as a Principal
versus Net as an Agent, we had been recording our energy trading revenues and
costs on a gross basis for physical sales and purchases. In June 2002 the
Financial Accounting Standards Board issued EITF 02-3, Accounting for Contracts
Involved in Energy Trading and Risk Management Activities. This consensus
requires that all mark to market gains or losses arising from energy trading
contracts (whether realized or unrealized) to be shown net in the income
statement beginning with the first interim period ending after July 15, 2002,
with reclassification required for all comparable periods presented. In
addition, the EITF will require additional disclosures related to our physical
trading contracts beginning in annual periods ending after July 15, 2002.
The following table shows the restated amounts for the quarter ended
September 30, 2001 and 2002, and for the nine months ended September 30, 2001
and 2002. The change in reporting reduces total revenue and total operating
costs and expense and has no effect on net income.
For the three months ended For the three months ended
September 30, 2001 September 30, 2002
-------------------------------- ---------------------------------
(dollars in thousands) Original Restated Original Restated
-------- --------- -------- -------- --------- --------
Oil and Gas Income ....... $ 27,630 $ 338 $ 27,968 $ 29,577 $ 67 $ 29,644
Energy Trading Income .... $ 48,807 ($48,503) $ 304 $ 33,453 ($33,453) --
All other Income ......... $ 10,234 $ 0 $ 10,234 $ 9,352 $ 0 $ 9,352
- --------------------------
Total Revenue ............ $ 86,671 ($48,165) $ 38,506 $ 72,382 ($33,386) $ 38,996
- ----------------------------------------------------------------------------------------------
Energy Trading Expense ... $ 48,165 ($48,165) $ 0 $ 33,386 ($33,386) $ 0
All other Expense ........ $ 35,723 $ 0 $ 35,723 $ 35,412 $ 0 $ 35,412
- --------------------------
Total Expense ............ $ 83,888 ($48,165) $ 35,723 $ 68,798 ($33,386) $ 35,412
- ----------------------------------------------------------------------------------------------
Net Income $ 2,783 $ 0 $ 2,783 $ 3,584 $ 0 $ 3,584
=================================================================
For the nine months ended For the nine months ended
September 30, 2001 September 30, 2002
----------------------------------- -----------------------------------
(dollars in thousands) Original Restated Original Restated
--------- ---------- ---------- ---------- ---------- ----------
Oil and Gas Income ....... $ 90,455 $ 604 $ 91,059 $ 80,023 $ 543 $ 80,566
Energy Trading Income .... $ 181,223 ($180,864) $ 359 $ 119,246 ($119,052) $ 194
All other Income ......... $ 38,723 $ 0 $ 38,723 $ 28,302 $ 0 $ 28,302
- --------------------------
Total Revenue ............ $ 310,401 ($180,260) $ 130,141 $ 227,571 ($118,509) $ 109,062
- ----------------------------------------------------------------------------------------------------
Energy Trading Expense ... $ 180,260 ($180,260) $ 0 $ 118,509 ($118,509) $ 0
All other Expense ........ $ 105,008 $ 0 $ 105,008 $ 103,911 $ 0 $ 103,911
- --------------------------
Total Expense ............ $ 285,268 ($180,260) $ 105,008 $ 222,420 ($118,509) $ 103,911
- ----------------------------------------------------------------------------------------------------
Net Income $ 25,133 $ 0 $ 25,133 $ 5,151 $ 0 $ 5,151
========= ========= ========= ========= ========= =========
6. EARNINGS PER SHARE
Earnings per common share was computed without any provisions for federal
income taxes since the Company converted to an S-Corporation effective June 1,
1997. Earnings per common share was computed by dividing income available to
common stockholders by the weighted-average number of shares outstanding for the
period. The weighted-average number of shares used to compute earnings per
common share was 14,368,919 in 2001 and 2002. The weighted-average number of
shares used to compute diluted earnings per share was 14,393,132 for 2001 and
2002.
7. 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 such subsidiaries as of December 31, 2001, and
September 30, 2002, and for the three and nine month periods ended September 30,
2001 and 2002.
Condensed Consolidating Balance Sheet
as of December 31, 2001
Guarantor
(dollars in thousands) Subsidiaries Parent Eliminations Consolidated
--------- --------- ---------- ---------
Current Assets...................................... $ 6,310 $ 51,915 $ (25,935) $ 32,290
Noncurrent Assets .................................. 42,063 280,143 (11) 322,195
--------- --------- --------- ---------
Total Assets........................................ $ 48,373 $ 332,058 $ (25,946) $ 354,485
========= ========= ========= =========
Current Liabilities................................. $ 11,039 $ 38,629 $ (8,382) $ 41,286
Noncurrent Liabilities ............................. 17,553 178,086 (17,553) 178,086
Stockholder's Equity ............................... 19,781 115,343 (11) 135,113
--------- --------- --------- ---------
Total Liabilities and Stockholder's
Equity.............................................. $ 48,373 $ 332,058 $ (25,946) $ 354,485
========= ========= ========= =========
Condensed Consolidating Balance Sheet
as of September 30, 2002
Guarantor
(dollars in thousands) Subsidiaries Parent Eliminations Consolidated
--------- --------- ---------- ---------
Current Assets..................................... $ 5,566 $ 46,730 $ (22,610) $ 29,686
Noncurrent Assets ................................. 42,747 330,070 (14) 372,803
--------- --------- --------- ---------
Total Assets....................................... $ 48,313 $ 376,800 $ (22,624) $ 402,489
========= ========= ========= =========
Current Liabilities................................ $ 9,732 $ 28,461 $ (6,737) $ 31,456
Noncurrent Liabilities ............................ 16,373 230,269 (15,873) 230,769
Stockholder's Equity .............................. 22,208 118,070 (14) 140,264
--------- --------- --------- ---------
Total Liabilities and Stockholder's
Equity............................................. $ 48,313 $ 376,800 $ (22,624) $ 402,489
========= ========= ========= =========
Condensed Consolidating Statements of Operations
For the Three Months Ended September 30, 2001
Guarantor
(dollars in thousands) Subsidiaries Parent Eliminations Consolidated
--------- --------- ---------- ---------
Total Revenues..................................... $ 12,492 $ 26,791 $ (777) $ 38,506
Operating Costs & Expenses ........................ (9,530) (23,391) 777 (32,144)
Other Income(Expense) ............................. (439) (3,140) 0 (3,579)
-------- -------- -------- --------
Net Income......................................... $ 2,523 $ 260 $ 0 $ 2,783
======== ======== ======== ========
Condensed Consolidating Statements of Operations
For the Three Months Ended September 30, 2002
Guarantor
(dollars in thousands) Subsidiaries Parent Eliminations Consolidated
--------- --------- ---------- ---------
Total Revenues.................................... $ 11,801 $ 27,175 $ 20 $ 38,956
Operating Costs & Expenses ....................... (10,793) (20,500) (20) (31,313)
Other Income(Expenses) ........................... (371) (3,728) 0 (4,099)
--------- --------- --------- ---------
Net Income....................................... $ 637 $ 2,947 $ 0 $ 3,584
========= ========= ========= =========
Condensed Consolidating Statements of Operations
For the Nine Months Ended September 30, 2001
Guarantor
(dollars in thousands) Subsidiaries Parent Eliminations Consolidated
--------- --------- ---------- ---------
Total Revenues................................... $ 39,375 $ 93,680 $ (2,914) $ 130,141
Operating Costs & Expenses ...................... (33,794) (65,742) 2,914 (96,622)
Other Income(Expense) ........................... (630) (7,756) 0 (8,386)
--------- --------- -------- ---------
Net Income....................................... $ 4,951 $ 20,182 $ 0 $ 25,133
======== ========= ======== =========
Condensed Consolidating Statements of Operations
For the Nine Months Ended September 30, 2002
Guarantor
(dollars in thousands) Subsidiaries Parent Eliminations Consolidated
--------- --------- ---------- ---------
Total Revenues.................................. $ 35,458 $ 74,464 $ (860) $ 109,062
Operating Costs & Expenses ..................... (31,775) (60,871) 860 (91,786)
Other Income(Expenses) ......................... (1,259) (10,866) 0 (12,125)
--------- --------- --------- ---------
Net Income..................................... $ 2,424 $ 2,727 $ 0 $ 5,151
========= ========= ========= =========
At September 30, 2002, current liabilities payable to the Company by the
guarantor subsidiaries totaled approximately $22.3 million. For the nine months
ended September 30, 2001 and 2002, depreciation, depletion and amortization
included in the guarantor subsidiaries operating costs were approximately $2.6
million and $4.2 million, respectively.
Since its incorporation, CCC has had no operations, has acquired no assets
and has incurred no liabilities.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
The following table sets forth certain information regarding the production
volumes, oil and gas sales (excluding hedges), average sales prices received and
expenses for the periods indicated:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------------------------------------
NET PRODUCTION: 2002 2001 2002 2001
-------------------------------------------------------
Oil (MBbl) . . . . . . . . . . . . . . . . . . . . . . . 985 955 2,869 2,550
Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . 2,489 1,950 6,996 6,208
Oil equivalent (MBoe) . . . . . . . . . . . . . . . . . . 1,400 1,281 4,038 3,585
OIL AND GAS SALES ($ in thousand)
Oil sales, excluding hedges. . . . . . . . . . . . . . . . $25,628 $23,673 $67,424 $66,607
Hedges . . . . . . . . . . . . . . . . . . . . . . . . . $(2,033) $ -- $(2,742) $ --
Gas sales. . . . . . . . . . . . . . . . . . . . . . . . . $6,049 $4,295 $15,884 $24,452
------- ------- ------- -------
Total oil and gas sales. . . . . . . . . . $29,644 $27,968 $80,566 $91,059
======= ======= ======= =======
AVERAGE SALES PRICE:
Oil, excluding hedges ($ per Bbl). . . . . . . . . . . . . $26.03 $24.79 $23.50 $26.12
Oil, including hedges ($ per Bbl). . . . . . . . . . . . . $23.97 $24.79 $22.55 $26.12
Gas ($ per Mcf) . . . . . . . . . . . . . . . . . . . . . $2.43 $2.20 $2.27 $3.94
Oil equivalent, excluding hedges ($ per Boe) . . . . . . . $22.63 $21.84 $20.62 $25.40
Oil equivalent, including hedges ($ per Boe) . . . . . . . $21.18 $21.84 $19.95 $25.40
EXPENSES ($ per Boe):
Production expenses (including taxes). . . . . . . . . . . $6.84 $7.22 $6.68 $7.97
General and administrative, gross. . . . . . . . . . . . . $2.58 $3.08 $2.67 $2.60
General and administrative, net of
operating overhead. . . . . . . . . . . . . . . . . . . $2.36 $2.55 $2.29 $2.17
DD&A (on oil and gas properties) . . . . . . . . . . . . . $3.23 $5.31 $4.59 $4.60
THREE MONTHS ENDED SEPTEMBER 30, 2002, COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2001
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
unrounded amounts.
RESULTS OF OPERATIONS
REVENUES
GENERAL
For the current quarter, we had revenues of $39.0 million, an increase of
$0.5 million from revenues of $38.5 million during the three months ended
September 30, 2001. The increase is mainly attributable to higher gas prices and
increased production volumes.
OIL AND GAS SALES
Our oil and gas sales revenue for the three months ended September 30,
2002, increased $1.7 million, or 6%, to $29.6 million from $27.9 million during
the comparable period in 2001 due primarily to the increase in gas prices along
with the increase in volumes of natural gas produced. During the three months
ended September 30, 2002, we sold 985 MBbls of oil and 2,489 MMcf of natural
gas, or 1,400 MBoe compared to sales of 1,281 MBoe for the same period in 2001.
Our oil revenues for the three months ended September 30, 2002, exclusive
of hedging activities, increased $2.0 million, or 8%, to $25.6 million from
$23.6 million during the same period in 2001. Our oil production increased by 30
MBbls to 985 MBbls, or 3%, for the three months ended September 30, 2002, from
955 MBbls for the comparable period in 2001. Oil prices, exclusive of hedging
and adjustments, increased to an average of $26.03/Bbl, or 5%, during the three
months ended September 30, 2002, from $24.79/Bbl, for the comparable 2001
period.
Hedging activities reduced oil revenues by $2.0 million and reduced the
average crude oil price to $23.97 per barrel during the three months ended
September 30, 2002. There were no crude oil hedges during the three months ended
September 30, 2001.
Our gas revenues increased $1.8 million, or 41%, to $6.0 million from $4.2
million for the three month period ended September 30, 2002, compared to the
same period in 2001. Our gas production for the period increased 539 MMcf, or
28%, to 2,489 MMcf from 1,950 MMcf in 2001. Gas prices increased to an average
of $2.43/Mcf, or 19%, from $2.20/Mcf for the comparable 2001 period.
ENERGY TRADING
We discontinued our crude oil marketing activities effective May 2002.
Therefore, during the three month period ended September 30, 2002, we had no
crude oil marketing activity. We recognized a gain of $0.3 million for the three
month period ended September 30, 2001. We have reported all mark-to-market gains
or losses which arose from energy trading contracts net in the income statement
in accordance with EITF 02-3. The adoption of EITF 02-3 had no impact on our net
income, but did reduce our total revenue and total operating costs and expenses
in comparable historical periods presented. (See the restatement table under
Note 5. ENERGY TRADING ACTIVITIES)
DERIVATIVE
We have fixed price physical delivery contracts in place to deliver
approximately 2,010,000 barrels of our forecasted crude oil production through
January 2004 at an average price of $24.07 per barrel. These contracts are
considered to be in the normal course of business and have been designated as
such thus 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 August 2002, we elected to convert the fixed price by entering into
fixed price purchase contracts at an average price of $25.44 per barrel. These
derivative purchase contracts have been designated as fair value hedges of a
portion of the volumes covered under the firm commitments. As required by SFAS
No. 133, changes in the fair value of the firm commitment occurring subsequent
to the time the hedges were designated have been recorded in the accompanying
balance sheet. As the critical terms of the derivative contracts and firm
commitment coincide, changes in the value of the firm commitment are perfectly
offset by changes in the value of the derivative contracts.
In addition to the above contracts, we also have a crude oil derivative
contract in place at September 30, 2002, 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 450,000 barrels of
crude oil 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, 2002, we recorded a loss of $757,000 in
change in derivative fair value to reflect the mark-to-market valuation at
September 30, 2002.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue in the third quarter of
2002 was $8.3 million, an increase of $0.7 million, or 9%, from $7.6 million in
the same period in 2001. This increase in revenue during the third quarter was
attributable to slightly higher natural gas and liquid prices along with
increased volumes from the addition of Mississippi wells flowing into the Amory
gas gathering and processing facility during the third quarter of 2002.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations for the three months ended September 30,
2002, was $1.8 million, a decrease of $0.8 million or 32% from $2.6 million for
the three months ended September 30, 2001. The decrease was due primarily to
lower volumes of reclaimed oil sales from our central treating unit.
OPERATING COSTS AND EXPENSES
PRODUCTION EXPENSES
Our production expenses increased by $0.1 million, or 2%, to $7.4 million
during the three months ended September 30, 2002, from $7.3 million during the
comparable period in 2001. The increase was primarily due to an increase in the
expenses related to our Cedar Hills secondary recovery project and increased
volumes produced.
PRODUCTION TAXES
Our production taxes increased by $0.2 million, or 9%, to $2.2 million
during the three months ended September 30, 2002, from $2.0 million during the
comparable period in 2001. The increase was due to higher prices and more
production volumes in the three months ended September 30, 2002 compared to the
three months ended September 30, 2001.
EXPLORATION EXPENSES
For the three months ended September 30, 2002, our exploration expenses
decreased $1.7 million, or 37%, to $3.0 million from $4.7 million during the
comparable period of 2001. The decrease was due to a $0.6 million decrease in
dry hole costs and $1.1 million decrease in expired lease and plugging costs.
GATHERING, MARKETING, AND PROCESSING
During the three months ended September 30, 2002, we incurred gathering,
marketing and processing expenses of $7.4 million, representing a $2.5 million,
or 51% increase from the $4.9 million incurred in the third quarter of 2001 due
to increased system volumes and higher natural gas and liquid prices.
OIL AND GAS SERVICE OPERATIONS
During the three months ended September 30, 2002, we incurred oil and gas
services operations expenses of $1.8 million, an increase of $0.1 million, or 5%
from $1.7 million in the third quarter of 2001.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
For the three months ended September 30, 2002, our DD&A expense decreased
$1.7 million, or 22%, to $5.9 million from $7.6 million for the comparable
period in 2001. In the third quarter of 2002, DD&A expense on oil and gas
properties was calculated at $3.23 per Boe compared to $5.31 per Boe for the
third quarter of 2001. The decrease was primarily due to higher product prices,
which lengthens the life of the properties and decreases depletion rates.
GENERAL AND ADMINISTRATIVE ("G&A")
For the three months ended September 30, 2002, our G&A expense was $3.6
million, net of overhead reimbursement of $0.3 million, for a period net of $3.3
million which was no change from our G&A expense of $4.0 million, net of
overhead reimbursement of $0.7 million, for a net of $3.3 million during the
comparable period in 2001. Overhead reimbursement is included in our oil and gas
service operations on the income statement. Our G&A expenses per Boe for the
third quarter of 2002 was $2.36 compared to $2.55 for the third quarter of 2001.
INTEREST EXPENSE
For the three months ended September 30, 2002, our interest expense
increased $0.4 million, or 11% to $4.3 million from $3.9 million for the three
months ended September 30, 2001. The increase was additional interest paid on
our credit facility due to higher average debt balances outstanding.
OTHER INCOME
Our other income for the three months ended September 30, 2002 and 2001,
remained constant at $0.2 million.
NET INCOME
For the three months ended September 30, 2002, our net income was $3.6
million, an increase in net income of $0.8 million, or 29%, from $2.8 million
for the comparable period in 2001. The increase in net income was due primarily
to higher gas prices and increases in oil and gas volumes.
NINE MONTHS ENDED SEPTEMBER 30, 2002, COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 2001
REVENUES
GENERAL
Our revenues decreased $21.0 million, or 16%, to $109.1 million during the
nine months ended September 30, 2002, from $130.1 million during the comparable
period in 2001. The decrease is mainly attributable to lower oil and gas prices,
declines in gathering, marketing and processing revenues due to lower gas prices
and losses in hedging activities and derivative transactions.
OIL AND GAS SALES
Our oil and gas sales revenue for the nine months ended September 30, 2002,
decreased $10.5 million, or 12%, to $80.6 million from $91.1 million during the
same period in 2001 due to decreased oil and gas prices and hedging losses.
During the nine months ended September 30, 2002, we sold 2,869 MBbls of oil and
6,996 MMcf of natural gas, or 4,038 MBoe compared to sales of 3,585 MBoe for the
same period in 2001.
Our oil revenues, exclusive of hedging, for the nine months ended September
30, 2002, increased $0.8 million, or 1%, to $67.4 million from $66.6 million in
the same period in 2001. Our oil production increased by 319 MBbls to 2,868
MBbls, or 13%, for the nine months ended September 30, 2002, from 2,549 MBbls
for the same period in 2001. Oil prices, exclusive of hedging, decreased to an
average of $23.50/Bbl, or 10%, during the nine months ended September 30, 2002,
from $26.12/Bbl, for the comparable 2001 period.
Hedging activities reduced oil revenues by $2.7 million and reduced the
average crude oil price to $22.55 per barrel during the nine months ended
September 30, 2002. There were no crude oil hedges during the nine months ended
September 30, 2001.
Our gas revenues for the nine months ended September 30, 2002, decreased
$8.5 million, or 35%, to $15.9 million from $24.4 million in the same period in
2001. Our gas production for the period increased 788 MMcf, or 13%, to 6,996
MMcf from 6,208 MMcf in 2001. Gas prices decreased to an average of $2.27/Mcf,
or 42%, from $3.94/Mcf, for the comparable 2001 period.
ENERGY TRADING
We discontinued our crude oil marketing activities effective May 2002. We
have reported all mark-to-market gains or losses which arose from energy trading
contracts as net in the income statement and restated all comparable historical
periods presented according to EITF 02-3. The adoption of EITF 02-3 had no
impact on our net income, but it did reduce total revenues and total operating
costs and expense in comparable historical periods presented. (See the
restatement table under Note 5. Crude Oil Marketing) For the year to date period
ended September 30, 2002, we recognized a gain of $0.2 million on crude oil
marketing activities from January 2002 thru May 2002, compared to a gain of $0.4
million for the nine months ended September 30, 2001.
DERIVATIVE
We have fixed price physical delivery contracts in place to deliver
approximately 2,010,000 barrels of our forecasted crude oil production through
January 2004 at an average price of $24.07 per barrel. These contracts are
considered to be in the normal course of business and have been designated as
such thus 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 August 2002, we elected to convert the fixed price by entering into
fixed price purchase contracts at an average price of $25.44 per barrel. These
derivative purchase contracts have been designated as fair value hedges of a
portion of the volumes covered under the firm commitments. As required by SFAS
No. 133, changes in the fair value of the firm commitment occurring subsequent
to the time the hedges were designated have been recorded in the accompanying
balance sheet. As the critical terms of the derivative contracts and firm
commitment coincide, changes in the value of the firm commitment are perfectly
offset by changes in the value of the derivative contracts.
In addition to the above contracts, we also had a crude oil derivative
contract in place at September 30, 2002, which has been 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 450,000 barrels of
crude oil 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, 2002, we recorded a loss of $2.0 million
in change in derivative fair value to reflect the mark-to-market valuation at
September 30, 2002.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue for the nine months ended
September 30, 2002, was $24.5 million, a $7.5 million, or 24% decrease, from
$32.0 million in the comparable 2001 period. The decrease for the nine month
period was due to lower natural gas and liquid prices in the 2002 period.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations for the nine months ended September 30,
2002, decreased $0.9 million, or 13%, to $5.8 million from $6.7 million during
the same period in 2001. The decrease was due primarily to fewer volumes of
reclaimed oil sales from our central treating unit.
OPERATING COSTS AND EXPENSES
PRODUCTION EXPENSES
Our production expenses decreased by $0.4 million, or 2%, to $21.3 million
for the nine months ended September 30, 2002, from $21.7 million during the
comparable period in 2001. The decrease was primarily due to various expenses
relating to our Cedar Hills Unit and increased oil and gas volumes produced.
PRODUCTION TAXES
Our production taxes for the nine months ended September 30, 2002,
decreased by $1.3 million, or 19%, to $5.6 million compared to $6.9 million in
the comparable period of 2001. The decrease was due to lower oil and gas prices
in 2002 compared to 2001.
EXPLORATION EXPENSES
Our exploration expense for the nine months ended September 30, 2002,
decreased $2.6 million, or 30%, to $6.3 million from $8.9 million incurred in
the comparable period in 2001. The decrease was due primarily to a $1.8 million
decrease in dry hole costs, a $0.3 million decrease in plugging costs and a
decrease of $0.5 million due to lease impairments.
GATHERING, MARKETING, AND PROCESSING
Our gathering, marketing and processing expenses for the nine months ended
September 30, 2002, were $20.4 million, a $4.8 million, or 19% decrease, from
$25.2 million in the same period in 2001 due to lower natural gas and liquids
prices on natural gas processed at the plants.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations expenses remained constant at $4.8
million for the nine months ended September 30, 2002 and 2001.
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)
For the nine months ended September 30, 2002, our DD&A expense increased
$2.7 million, or 14% to $22.5 million from $19.8 million for the same period in
2001. The increase was primarily due to lower product prices which shortens the
life of the properties and increases depletion rates.
GENERAL AND ADMINISTRATIVE ("G&A")
For the nine month period ended September 30, 2002, our G&A expense was
$10.8 million, net of overhead reimbursement of $1.5 million, for a period net
of $9.3 or an increase of $1.5 million, or 19%, from our G&A expense of $9.3
million, net of overhead reimbursement of $1.5 million, for a total of $7.8
million during the comparable period in 2001. Overhead reimbursement is included
in our oil and gas service operations on the income statement. Our net G&A
expense per Boe for the first nine months of 2002 was $2.29 compared to $2.17
for the same period in 2001. The increase was primarily due to increased
employment expense.
INTEREST EXPENSE
For the nine months ended September 30, 2002, our interest expense
increased $1.5 million, or 13% to $12.6 million from $11.1 million for the same
period in 2001. The increase was additional interest on our credit facility due
to higher average debt balances outstanding.
OTHER INCOME
Our other income for the year to date ended September 30, 2002, was $0.2
million compared to $2.1 million for the year to date ended September 30, 2001.
The decrease reflects the sale of 62 uneconomical wells April 11, 2001, which
was approximately $2.0 million and a gain on the repurchase of our senior
subordinated notes of $0.1 million.
NET INCOME
For the nine months ended September 30, 2002, our net income was $5.2
million, a decrease of $19.9 million, or 80%, from $25.1 million for the
comparable period in 2001. The decrease in net income was mainly due to lower
oil and gas prices and reduced results from gathering, marketing and processing.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Net cash provided by our operating activities for the nine months ended
September 30, 2002, was $25.6 million, a decrease of $18.3 million, or 42%, from
$43.9 million provided by operating activities during the comparable 2001
period. The decrease was primarily due to the decrease in net income. We had
cash at September 30, 2002, of $3.0 million, a decrease of $4.2 million, or 58%,
from the balance of $7.2 million held at December 31, 2001.
DEBT
Our long-term debt at December 31, 2001, was $178.0 million and at
September 30, 2002, was $230.6 million. During the first quarter of 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. We
had $103.0 million of outstanding debt under this credit facility at September
30, 2002. Subsequent to September 30, 2002, we borrowed $10.0 million against
our credit facility, increasing our outstanding borrowings to $113.0 million.
CREDIT FACILITY
The effective rate of interest under our bank credit facility was 4.06 % at
September 30, 2002. Our 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 is $140.0 million and is re-determined
semi-annually.
CAPITAL EXPENDITURES
Our 2002 capital expenditures budget is $91.3 million, exclusive of
acquisitions. Our Cedar Hills Field secondary recovery project will account for
$65.0 million, or 71%, of our budgeted capital expenditures for 2002. This
includes $40.9 million for drilling injector wells and $24.1 million for
compressors, equipment and facilities. During the nine months ended September
30, 2002, we incurred $74.4 million of capital expenditures, exclusive of
acquisitions, compared to $46.7 million, exclusive of acquisitions, in the nine
month period of 2001. The $27.7 million, or 59% 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 2002 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 the Company's financial position, business
strategy, plans and objectives of management of the Company for future
operations and industry conditions, are forward-looking statements. Although the
Company believes that the expectations reflected in such forward-looking
statements are reasonable, it can give no assurance that such expectations will
prove to have been correct. Important factors that could cause actual results to
differ materially from the Company's 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 of the Company filed with the
Securities and Exchange Commission (the "Commission"). All subsequent written
and oral forward-looking statements attributable to the Company or persons
acting on its 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 risk 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. As of September 30, 2002, we had entered into financial contracts
covering the notation volumes set forth in the following tables for the periods
indicated:
Time Period Barrels per Month Price per barrel
----------- ----------------- ----------------
10/02-03/03 60,000 $21.98
10/02-06/03 30,000 $24.01
10/02-01/04 30,000 $24.01
10/02-12/03 30,000 $25.08
10/02-12/03 30,000 $24.85
DERIVATIVES
We entered into a derivative contract, covering 30,000 barrels of crude oil
per month for the period from April 2002 to December 2003, that provides for the
counterparty to pay us the positive difference, if any, between $24.25 per
barrel or the average NYMEX spot crude oil price for the month. 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 a month
average more than $24.25 per barrel, we pay the excess to the counterparty.
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.
The prices of crude oil, natural gas, and natural gas liquids are subject
to fluctuations resulting from changes in supply and demand. To partially reduce
price risk caused by these market fluctuations, we may hedge (through the
utilization of derivatives) a portion of our production and sale contracts.
Because the commodities covered by these derivatives are substantially the same
commodities that we buy and sell in the physical market, no special studies
other than monitoring the degree of correlation between the derivative and cash
markets, are deemed necessary.
A sensitivity analysis has been prepared to estimate the price exposure to
the market risk of our crude oil, natural gas and natural gas liquids commodity
positions. Our daily net commodity position consists of crude inventories,
commodity purchase and sales contracts and derivative commodity instruments. The
fair value of such position is a summation of the fair values calculated for
each commodity by valuing each net position at quoted futures prices. Market
risk is estimated as the potential loss in fair value resulting from a
hypothetical 10 percent adverse change in such prices over the next 12 months.
Based on this analysis, we estimate the potential market risk loss, assuming a
hypothetical 10 percent adverse change, to be approximately $4.2 million related
to our crude trading and hedging portfolios.
INTEREST RATE RISK
Our exposure to changes in interest rates relates primarily to long-term
debt obligations. We manage our interest rate exposure by limiting our
variable-rate debt to a certain percentage of total capitalization and by
monitoring the effects of market changes in interest rates. We may utilize
interest rate derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense related to existing debt issues. Interest rate
derivatives are used solely to modify interest rate exposure and not to modify
the overall leverage of the debt portfolio. The fair value of long-term debt is
estimated based on quoted market prices and management's estimate of current
rates available for similar issues. The following table itemizes our long-term
debt maturities and the weighted-average interest rates by maturity date.
- -------------------------------------------------------------------------------------------------------------------
2002
(dollars in thousands) 2002 2003 2004 2005 Thereafter Total Fair Value
- -------------------------------------------------------------------------------------------------------------------
Fixed rate debt:
Principal amount $ 127,150 $ 127,150 $ 127,150
Weighted-average
interest rate 10.25% 10.25% --
Variable-rate debt:
Principal amount -- -- -- $ 103,000 -- $ 103,000 $ 103,000
Weighted-average
interest rate -- -- -- 4.0% -- 4.0% --
- -------------------------------------------------------------------------------------------------------------------
ITEM 4. CONTROLS AND PROCEDURES
The Securities and Exchange Commission's rules require registrants to
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 monitor 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)
and Rule 15d-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, the Company is party to litigation or other legal
proceedings that it considers to be a part of the ordinary course of its
business. The Company is not involved in any legal proceedings nor is it party
to any pending or threatened claims that could reasonably be expected to have a
material adverse effect on its financial condition or results of operations.
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)
4.3 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. [4.3] (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](7)
12.2 Statement re computation of ratio of earning to fixed charges.
[12.2](7)
12.3 Statement re computation of ratio of Adjusted EBITDA to interest
expense. [12.3](7)
21.0 Subsidiaries of Registrant. [21](6)
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.
(b.) REPORTS ON FORM 8-K
On July 19, 2002, the Registrant filed a current report on Form 8-K
describing the dismissal of Arthur Andersen LLP and appointment of Ernst and
Young LLP as its new independent auditors.
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.
ROGER V. CLEMENT
Roger V. Clement
Senior Vice President
(Chief Financial Officer)
Date: November 12, 2002
CERTIFICATIONS FOR FORM 10-Q
I, Harold Hamm, Chairman and Chief Executive Officer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Continental
Resources, Inc. (the "registrant");
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Continental Resources, Inc.
Date: November 12, 2002 By: HAROLD HAMM
Harold Hamm
Chairman and Chief Executive Officer
CERTIFICATIONS FOR FORM 10-Q
I, Roger V. Clement, Vice President and Chief Financial Officer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Continental
Resources, Inc. (the "registrant");
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Continental Resources, Inc.
Date: November 12, 2002 By: ROGER V. CLEMENT
Roger V. Clement
Vice President and Chief Financial Officer
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
- ------- ----------- ----------------
2.1 Agreement and Plan of Incorporated herein by reference
Recapitalization 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 Incorporated herein by reference
April 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.
4.3 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 Incorporated herein by reference
28, 2002, between Registrant and
Guaranty Bank, FSB, as
Agent
10.4 Conveyance Agreement of Worland Incorporated herein by reference
Area 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 Incorporated herein by reference
2000, effective October 1, 1999, by
and between Patrick Energy
Corporation as Buyer and
Continental Resources, Inc. as
Seller
10.6 Continental Resources, Inc. 2000 Incorporated herein by reference
Stock 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 Incorporated herein by reference
between 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 Incorporated herein by reference
of debt to Adjusted EBITDA
12.2 Statement re computation of ratio Incorporated herein by reference
of earning to fixed charges
12.3 Statement re computation of ratio Incorporated herein by reference
of Adjusted EBITDA to interest
expense
21.0 Subsidiaries of Registrant Incorporated herein by reference
99.1 Letter to the Securities and Incorporated herein by reference
Exchange Commission dated March 28,
2002, regarding the audit of the
Registrant's financial statements
by Arthur Andersen LLP