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