United States
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d)15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003March 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________to _________
Commission File Number: 333-61547
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Oklahoma 73-0767549
- ------------------------------------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
302 N. Independence, Suite 300, Enid, Oklahoma 73701
- ---------------------------------------------------------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (580) 233-8955
Securities registered pursuant to Section 12 (b)12(b) of the Act: None
Securities registered pursuant to Section 12 (g)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)15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ ] No [X]
The Registrant is not subject to the filing requirements of Section 13 and 15(d)
of the Securities Exchange Act of 1934, but files reports required by those
sections pursuant to contractual obligation requirements.
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act.) Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding as of November 13, 2003May 14, 2004
- ---------------------------- -----------------------------------------------------------------
Common Stock, $.01 par value 14,368,919 shares
TABLE OF CONTENTS
PART I. Financial Information
ITEM 1. Financial Statements
.................................................4Condensed Consolidated Balance Sheets................................ 4
Condensed Consolidated Income Statements............................. 5
Condensed Consolidated Statements of Cash Flows...................... 6
Notes to Condensed Consolidated Financial Statements................. 7
ITEM 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations.........................................14Operations.....................12
ITEM 3.3 Quantitative and Qualitative Disclosures About Market Risk ..........20Risk.........19
ITEM 4. Controls and Procedures..............................................21Procedures...........................................20
PART II. Other Information
ITEM 1. Legal Proceedings .................................................. 22Proceedings.................................................21
ITEM 2. Changes in Securities, and Use of Proceeds ...........................22and
Issuer Purchases of Equity Securities.............................21
ITEM 3. Defaults Upon Senior Securities .....................................22Securities...................................21
ITEM 4. Submission of Matters to a Vote of Security Holders .................22Holders...............21
ITEM 5. Other Information ...................................................22Information.................................................21
ITEM 6. Exhibits and Reports on Form 8-K.....................................22
Signatures....................................................................258-K..................................21
Signatures................................................................23
Certifications Pursuant to Item 302 of the Sarbanes-Oxley Act of 2002.....24
PART I. Financial Information
ITEM 1. FINANCIAL STATEMENTS
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share data)thousands)
December 31, September 30,
---------------- -----------------
2002March 31,
------------------ ------------------
Assets 2003 ---------------- -----------------2004
------------------ ------------------
CURRENT ASSETS: (unaudited)Current assets: (Unaudited)
Cash and cash equivalents $ 2,5202,277 $ 2,9991,968
Accounts receivable:
Oil and gas sales 14,756 15,87819,035 18,964
Joint interest and other, net 7,884 13,55213,577 11,196
Inventories 6,700 6,9345,465 5,168
Prepaid expenses 482 170336 144
Fair value of derivative contracts 628 623
-----------------151 40
------------------ ------------------
Total current assets 32,970 40,156
PROPERTY AND EQUIPMENT, AT COST:40,841 37,480
Property and equipment, at cost:
Oil and gas properties, based on
successful efforts accounting Producing properties 488,432 573,617
Nonproducing leaseholds 33,781 33,911601,325 616,546
Gas gathering and processing facilities 33,113 48,46549,600 50,882
Service properties, equipment and other 18,430 19,369
-----------------19,515 19,629
------------------ ------------------
Total property and equipment 573,756 675,362670,440 687,057
Less - Accumulatedaccumulated depreciation,
depletion and amortization (205,853) (211,232)
-----------------231,008 242,076
------------------ ------------------
Net property and equipment 367,903 464,130
OTHER ASSETS:439,432 444,981
Other assets:
Debt issuance costs, net 5,796 4,7634,707 4,344
Other assets 8 8
----------------------------------- ------------------
Total other assets 5,804 4,771
-----------------4,715 4,352
------------------ ------------------
Total assets $ 406,677484,988 $ 509,057
================= ==================
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share data)
December 31, September 30,
------------- --------------
2002 2003
------------- -------------
CURRENT LIABILITIES: (Unaudited)486,813
================== ==================
Liabilities and stockholders' equity
Current liabilities:
Accounts payable $ 26,66527,950 $ 34,02526,614
Current portion of long termlong-term debt 2,400 3,3365,776 5,776
Revenues and royalties payable 5,299 6,8938,250 7,935
Accrued liabilities and other 10,320 7,961liabilities:
Interest 6,312 3,054
Other 7,212 6,330
Fair value of derivative contracts 2,082 1,153
------------- -------------640 1,433
------------------ ------------------
Total current liabilities 46,766 53,368
LONG-TERM DEBT,56,140 51,142
Long-term debt, net of current portion 244,705 286,875
ASSET RETIREMENT OBLIGATION - 37,257
OTHER NON-CURRENT LIABILITIES 125 163
STOCKHOLDERS' EQUITY:285,144 291,199
Asset retirement obligation 26,608 26,891
Other noncurrent liabilities 164 166
Stockholders' equity:
Preferred stock, $0.01 par value, 1,000,000 shares
authorized, no shares issued and outstanding - -
Common stock, $0.01 par value, 20,000,000 shares
authorized, 14,368,919 shares issued and outstanding 144 144
Additional paid-in-capital 25,087 25,087
Retained earnings 89,850 106,163
------------- -------------92,190 93,181
Accumulated other comprehensive income (489) (997)
------------------ ------------------
Total stockholders' equity 115,081 131,394
------------- -------------116,932 117,415
------------------ ------------------
Total liabilities and stockholders' equity $ 406,677484,988 $ 509,057
============= =============486,813
================== ==================
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS OF INCOME
(Unaudited)
(Dollars in thousands, except share data)
Three Months Ended September 30,
--------------------------------
2002March 31,
-------------------------------------------
2003 ------------- -----------------2004
--------------------- --------------------
REVENUES: (As restated)Revenues: (restated)
Oil and gas sales $ 29,57735,722 $ 34,35036,123
Crude oil marketing income 33,453 39,698and trading 40,595 55,705
Change in derivative fair value (757) 519
Gathering,303 (396)
Gas gathering, marketing and processing 8,319 23,2849,725 15,865
Oil and gas service operations 1,447 2,291
------------- --------------1,882 2,114
--------------------- --------------------
Total revenues 72,039 100,142
OPERATING COSTS AND EXPENSES:88,227 109,411
Operating costs and expenses:
Production expenses 7,424 9,2668,631 10,548
Production taxes 2,157 2,5512,674 2,582
Exploration expenses 2,498 3,4951,502 2,092
Crude oil marketing expenses 33,386 39,002
Gathering,and trading 40,484 55,863
Gas gathering, marketing and processing 7,707 22,0758,828 13,808
Oil and gas service operations 1,794 2,0941,960 1,946
Depreciation, depletion and amortization of oil and gas properties 4,525 8,1348,302 10,467
Depreciation and amortization of other property and equipment 1,065 1,2241,148 1,165
Property impairments 609 1,3091,276 1,897
Asset retirement obligation accretion expense - 346352 277
General and administrative 2,865 2,667
------------- --------------2,838 2,500
--------------------- --------------------
Total operating costs and expenses 64,030 92,163
OPERATING INCOME 8,009 7,979
OTHER INCOME (EXPENSES)77,995 103,145
Operating income 10,232 6,266
Other income (expenses):
Interest income 83 2632 27
Interest expense (4,669) (5,076)(4,951) (5,289)
Other income, net 149 13
Gain37 23
Loss on sale of assets 13 90
------------- --------------(8) (35)
--------------------- --------------------
Total other income (expense) (4,424) (4,947)
------------- --------------
NET INCOME(4,890) (5,274)
--------------------- --------------------
Income before change in accounting principle 5,342 992
--------------------- --------------------
Cumulative effect of change in accounting principle 2,162 -
--------------------- --------------------
Net income $ 3,5857,504 $ 3,032
============= ==============
EARNINGS PER COMMON SHARE:992
===================== ====================
Basic earnings per common share:
Earnings before cumulative effect of accounting change $ 0.37 $ 0.07
Cumulative effect of accounting change 0.15 -
--------------------- --------------------
Basic $ 0.250.52 $ 0.21
============= ==============0.07
===================== ====================
Diluted earnings per common share:
Earnings before cumulative effect of accounting change $ 0.37 $ 0.07
Cumulative effect of accounting change 0.15 -
--------------------- --------------------
Diluted $ 0.250.52 $ 0.21
============= ==============0.07
===================== ====================
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOMECASH FLOWS
(Unaudited)
(Dollars in thousands, except share data)thousands)
NineThree Months Ended September 30,
--------------------------------
2002March 31,
-------------------------------------
2003 -------------2004
----------------- -----------------
REVENUES: (As restated)
OilCash flows from operating activities: (restated)
Net income $ 7,504 $ 992
Adjustments to reconcile net income to net cash
provided by operating activities-
Depreciation, depletion and gas sales $ 80,023 $ 103,419
Crude oil marketing income 120,472 120,046amortization 9,450 11,744
Accretion of asset retirement obligation 352 277
Impairment of properties 1,276 1,897
Change in derivative fair value (2,020) 926
Gathering, marketing(303) 396
Amortization of debt issuance costs 402 445
Loss on sale of assets 8 35
Change in accounting principle (2,162) -
Dry hole costs 830 1,403
Cash provided by (used in) changes in assets and liabilities-
Accounts receivable (3,637) 2,452
Inventories (836) 185
Prepaid expenses 132 192
Accounts payable 1,027 (1,336)
Revenues and royalties payable 2,067 (315)
Accrued liabilities and other (2,784) (4,140)
Other noncurrent assets 89 -
Other noncurrent liabilities 12 2
----------------- -----------------
Net cash provided by operating activities 13,427 14,229
Cash flows from investing activities:
Exploration and development (26,092) (19,188)
Gas gathering and processing 24,476 50,134
Oilfacilities and gas service
operations 4,287 6,596
------------- --------------
Total revenues 227,238 281,121
OPERATING COSTS AND EXPENSES:
Production expenses 21,324 27,494
Production taxes 5,644 7,586
Exploration expenses 5,153 7,548
Crude oil marketing expenses 119,735 118,878
Gathering, marketingproperties, equipment and processing 21,192 46,697
Oil and gas service operations 4,837 5,987
Depreciation, depletion and amortizationother (1,564) (1,488)
Purchase of oil and gas properties 18,548 23,350
Depreciation and amortization of other property and equipment 3,120 3,603
Property impairments 1,643 3,861
Asset retirement obligation accretion expense - 1,055
General and administrative 7,918 8,356
------------- --------------
Total operating costs and expenses 209,114 254,415
OPERATING INCOME 18,124 26,706
OTHER INCOME (EXPENSES):
Interest income 250 86
Interest expense (13,420) (14,991)
Other income, net 120 63
Gain on(82) (14)
Proceeds from sale of assets 77 359
------------- --------------
Total56 178
----------------- -----------------
Net cash used in investing activities (27,682) (20,512)
Cash flows from financing activities:
Proceeds from line of credit and other income (expense) (12,973) (14,483)
------------- --------------
NET INCOME BEFORE
CHANGE IN ACCOUNTING PRINCIPLE 5,151 12,223
------------- --------------
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE18,500 7,500
Repayment of debt (600) (1,444)
Debt issuance costs - 4,090
------------- --------------
NET INCOME(82)
----------------- -----------------
Net cash provided by financing activities 17,900 5,974
Net increase (decrease) in cash 3,645 (309)
Cash and cash equivalents, beginning of year 2,520 2,277
----------------- -----------------
Cash and cash equivalents, end of quarter $ 5,1516,165 $ 16,313
============= ==============
BASIC EARNINGS PER COMMON SHARE:
Earnings before cumulative effect of accounting change $ 0.36 $ 0.85
Cumulative effect of accounting change - 0.28
------------- --------------
Basic $ 0.36 $ 1.13
============= ==============
DILUTED EARNINGS PER COMMON SHARE:
Earnings before cumulative effect of accounting change $ 0.36 $ 0.85
Cumulative effect of accounting change - 0.28
------------- --------------
Diluted $ 0.36 $ 1.13
============= ==============1,968
================= =================
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited)
Nine Months Ended September 30,
--------------------------------
(Dollars in thousands) 2002 2003
------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES: (As restated)
Net income $ 5,151 $ 16,313
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization 21,668 26,953
Accretion of asset retirement obligation - 1,055
Impairment of properties 1,643 3,861
Change in derivative fair value 844 (926)
Amortization of debt issuance costs - 1,190
Gain on sale of assets (77) (359)
Change in accounting principle - (4,090)
Dry hole costs 4,019 4,834
Cash provided by (used in) changes in assets and liabilities
Accounts receivable (1,097) (6,790)
Inventories 160 (202)
Prepaid expenses 170 312
Accounts payable (5,125) 7,360
Revenues and royalties payable 950 1,594
Accrued liabilities and other (2,744) (2,359)
Other non-current liabilities 28 38
Other 1 1
------------ -------------
Net cash provided by operating activities 25,591 48,785
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development (64,774) (73,462)
Undeveloped leasehold (5,035) (5,963)
Gas gathering and processing facilities, service
properties, equipment and other (4,579) (16,529)
Purchase of oil and gas properties (655) (101)
Proceeds from sale of assets 123 4,768
------------ -------------
Net cash used in investing activities (74,920) (91,287)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from line of credit and other 116,830 46,062
Repayment of line of credit and other (69,575) (2,956)
Debt issuance costs (2,147) (125)
------------ -------------
Net cash provided by financing activities 45,108 42,981
NET INCREASE (DECREASE) IN CASH (4,221) 479
CASH, beginning of period 7,225 2,520
------------ -------------
CASH, end of period $ 3,004 $ 2,999
============ =============
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 15,082 $ 18,086
Asset retirement obligation at January 1, 2003 - 35,173
Capitalized asset retirement obligation, net at January 1, 2003 - 39,263
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. CONTINENTAL RESOURCES, INC.'S FINANCIAL STATEMENTS:
In the opinion of Continental Resources, Inc. ("CRI", or CRI or the "Company")Company, the
accompanying unaudited condensed consolidated financial statements contain all
adjustments necessary to present fairly the Company's financial position as of
September 30, 2003,March 31, 2004, the results of operations and cash flows for the three and
nine months
ended September 30, 2002March 31, 2003 and 2003. All such2004. Such adjustments are of a normal recurring
nature. The unaudited condensed consolidated financial statements for the
interim periods presented do not contain all information required by accounting
principles generally accepted in the United States. The results of operations
for any interim period are not necessarily indicative of the results of
operations for the entire year. These condensed consolidated financial
statements should be read in conjunction with the condensed
consolidated financial
statements and notes thereto included in the Company's annual report on form
10-K for the year ended December 31, 2002.
Certain reclassifications have been2003.
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 face 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 surface equipment, and estimated life of the Company's wells. In the
fourth quarter of 2003, the Company made certain adjustments to prior periodits 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 to conformoriginally reported for the quarter ended March 31, 2003, compared
to the current period presentation. In June 2002,restated amount:
Three Months Ended
March 31, 2003
---------------------------------------------
(Dollars in thousands, except share data) Originally Reported Restated
- ----------------------------------------------------------------------------- ---------------------
Net income before change in accounting principle $ 5,342 $ 5,342
Cumulative effect of change in accounting principle 4,090 2,162
--------------------- ---------------------
Net income $ 9,432 $ 7,504
Diluted earnings per share $ 0.66 $ 0.52
The Company is an S-Corporation under Subchapter S of the Emerging Issues Task Force
(EITF) reached a consensus in Issue 02-03 that all gains and losses (realized
and unrealized) on energy trading contracts should be shown net in the income
statement whether or not such contracts are settled physically. In response to
the issuance of this consensus, we netted revenues and expenses of $85.8 million
and $85.1 million, respectively in the income statement included in our Form
10-Q for the nine months ended September 30, 2002. Subsequently, in October
2002, the EITF revised the June 2002 consensus requiring that gains and losses
on energy trading contracts should be reported net in the income statement until
the derivative contract culminates in physical delivery. Once a derivative
contract culminates in physical delivery, the guidance in EITF 99-19, ReportingInternal Revenue
Gross as a Principal versus Net as an Agent, should be followed to
determine the appropriate income statement presentation. We adopted the October
2002 consensus on October 25, 2002.Code. As a result, income taxes, if any, will be payable by the stockholders of
such adoption, the revenuesCompany. The Company operates principally in the following two segments:
1. Exploration and expenses previously netted underProduction - The principal business of CRI and its
wholly-owned subsidiary, Continental Resources of Illinois, Inc., or CRII, is
oil and natural gas exploration, development and production. CRI and CRII have
interests in approximately 2,207 wells and serve as the June 2002 consensus have been restatedoperator in the majority
of these wells. CRI and presented gross underCRII's operations are primarily in Illinois, Oklahoma,
Wyoming, North Dakota, Texas, South Dakota, Montana, Kansas, Mississippi,
Louisiana, Kentucky and Indiana.
At March 31, 2004, the October 2002 consensusCompany had capitalized drilling and development
costs of approximately $177.8 million related to the high-pressure air injection
project currently in process in the Cedar Hills Field. Proved reserves
associated with this field are approximately 42.2 MMBoe of which approximately
28.5 MMBoe, or 67%, are proved undeveloped. As of March 31, 2004, the Company
had excluded $119.1 million, or 67%, of the development costs from the
amortization base for purposes of computing depreciation, depletion and
amortization, or DD&A. In future periods, the proved undeveloped reserves will
be transferred to proved developed as such contractsreserves meet the criteria for gross presentationdefinition of
proved reserves under EITF 99-19.SEC guidelines. Costs associated with the Cedar Hills
Field will be added to the amortization base based on the ratio of proved
developed reserves to proved undeveloped reserves. The Company's future DD&A
rate on this field could be significantly impacted by upward or downward
revisions in the oil and gas reserves associated with this field.
2. ACQUISITIONS:
On August 1, 2003, Continental Gas Inc. ("CGI"), a wholly ownedGathering, Marketing and Processing - Another wholly-owned
subsidiary of CRI acquired the Carmen Gathering System locatedis Continental Gas, Inc., or CGI, which is engaged principally
in western Oklahoma for
$15.0 million. After various adjustmentsnatural gas marketing, gathering and other reductionsprocessing activities and currently
operates seven gas gathering systems and three gas processing plants in the purchaseits
operating areas. In addition, CGI participates with CRI in exploration,
development and sale agreement, the net cost to CGI was $12.0 million. Funding for the
acquisition was obtained from borrowings under our revolving credit facility as
discussed in Note 3. Revenuesproduction of certain oil and expenses attributable to the Carmen Gathering
System were $3.7 million and $3.1 million, respectively, for the period from
acquisition to September 30, 2003.
3.natural gas properties.
2. LONG-TERM DEBT:
Long-term debt as of December 31, 2002,2003, and September 30, 2003,March 31, 2004, consisted of
the following:
December 31, September 30,March 31,
(Dollars in thousands) 2002 2003 ------------ ------------
2004
-------------- --------------
10.25% Senior Subordinated Notes due Aug.August 1, 2008 $ 127,150 $ 127,150
Credit Agreement 108,000 148,400Facility due March 31, 2007 132,900 140,400
Credit Facility due September 30, 2006 17,000 16,392
Capital Lease Agreement 11,955 14,661
------------ ------------13,827 12,993
Ford Credit 43 40
-------------- ---------------
Outstanding Debt 247,105 290,211290,920 296,975
Less Current Portion 2,400 3,336
------------ ------------5,776 5,776
-------------- ---------------
Total Long-Term Debt $ 244,705285,144 $ 286,875
============ ============291,199
============== ===============
During the quarter endedOn March 31, 2002, the Company executedentered into a Fourth Amended and Restated
Credit Agreement in which a group of lenders agreed to
provideproviding for a $175.0 million senior secured revolving credit
facility with a borrowing base of $140.0 million. On June 12, 2003, the Company executed the
First Amendment to the Credit Agreement and increased the borrowing base to $150.0 million. Borrowings under the credit
facility are secured by liens on all oil and gas properties and associated
assets of the Company. Borrowings under the credit facility bear interest,
payable quarterly, at (a) a rate per annum equal to the rate at which eurodollar
deposits for one, two, three or ninesix 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 March 31,
2004, the lead bank's reference rate plus margins was 3.8%. 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 facility. The credit facility maturity date
was extended on April 14, 2004, to March 31, 2007.
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 credit facility in an amount
up to $25 million that matures on March 28,
2005. As31, 2006. The amendment also extended
the maturity date of September 30, 2003, the Company had $148.4original facility to March 31, 2007, and increased the
borrowing base to $150.0 million. Borrowings under the term credit facility have
margins of 5.5% on LIBOR loans and 3% on prime loans. On April 14, 2004, the
company drew $25 million on the new term credit facility and paid down the
balance of the original revolving credit facility. At May 14, 2004, the
outstanding debtbalances were $124.5 million and $25.0 million on its line ofthe original
revolving credit facility and the effective rate of interest was 3.4%. The
outstanding balance at September 30,term loan, respectively.
On October 22, 2003, includes $12.0 million used for the
Carmen Gathering System acquisition.
Subsequent to September 30, 2003, Continental Gas, Inc. ("CGI"), a wholly
owned subsidiary of the Company, closed onCGI 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 secured revolving credit facility of up to $10.0 million. The
initial advance under the term loan facility was $17.0 million, which wasCGI paid
to CRI who used the payment to reduce CRI'sthe outstanding balance at itson CRI's credit
facility. No funds were initially advanced under the revolving loan facility.
Advances under either facility can be made, at the borrower's election, as
reference rate loans or LIBOR loans and, with the respect to LIBOR loans, for
interest periods of one, two, three, or six months. Interest is payable on
reference rate loans monthly and on LIBOR loans at the end of the applicable
interest period. The principal amount of the term loan facility is to be
amortized on a quarterly basis through June 30, 2006, with the final payment due
on September 30, 2006. The amount available under the revolving loan facility
may be borrowed, repaid and reborrowed until maturity on September 30, 2006.
Interest on reference rate loans is calculated with reference to a rate equal to
the higher of the reference rate of Union Bank of California, N.A. or the
federal funds rate plus 0.5%. Interest on LIBOR loans is calculated with
reference to the London interbank offered interest rate. Interest accrues at the
reference rate or the LIBOR rate, as applicable, plus the applicable margins.
The margin is based on the then current senior debt to EBITDA ratio. The credit
agreement contains certain covenants and requires certain quarterly mandatory
prepayments on the term loan of 75% of excess cash flow. The credit facility is
secured by a pledge of all the assets of CGI. At March 31, 2004, the outstanding
balance on CGI's credit facility was $16.4 million.
CRI's credit agreement contains certain financial and other covenants. At
March 31, 2004, CRI was not in compliance with two covenants, one that requires
the Company to maintain a minimum current ratio of 1:1 and another that
prohibits trading activity other than normal production contracts without prior
approval of the required banks. On a pro-forma basis after giving effect to the
Third Amendment to the Credit Agreement, the Company was in compliance with the
current ratio covenant in its credit agreement. In May 2004 the Company
requested and received from the bank group waivers for non-compliance with both
covenants.
3. DERIVATIVE CONTRACTS:
The Company utilizes derivative contracts, consisting primarily of fixed
price physical delivery contracts, including 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 we
receive is determined based on a published index price plus 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
and are being accounted for as cash flow hedges under SFAS No. 133. The
following table summarizes the Company's fixed price physical delivery
contracts, collars and floors in place at March 31, 2004:
2004 2005 2006 2007
--------------------------------------------------
Natural Gas Physical Delivery Contracts:
Contract Volumes (MMBtu) 450,000 600,000 600,000 600,000
Weighted Average Fixed Price per MMBtu $ 4.83 $ 4.53 $ 4.47 $ 4.49
Crude Oil Basis Contracts:
- --------------------- ---------------- ---------------
Contract Month Contract Volumes Price
- --------------------- ---------------- ---------------
May 2004 184,000 $ 35.73
June 2004 90,000 $ 35.27
July 2004 62,000 $ 35.03
Crude Oil Collars and Floors for 2004: Contract Weighted-average
Volumes (Bbls) Fixed Price per Bbl
----------------- --------------------
Floor 926,000 $ 22.00
Floor 200,000 $ 24.00
Floor 230,000 $ 24.50
------------
1,356,000
Ceiling 220,000 $ 35.00
Ceiling 515,000 $ 36.00
Ceiling 230,000 $ 45.00
------------
965,000
============
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. For the three months
ended March 31, 2004, crude oil marketing and trading revenues included $10.3
million and crude oil marketing and trading expenses also included $10.3
million, related to such trading activities. The Company had no crude oil
trading activities in the first quarter of 2003. 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
March 31, 2004, the Company had the following open crude oil trading derivative
contracts:
Weighted
Contract Contract Average Barrels Unrealized
Type Month Fixed Price Buy (Sell) Gain (Loss)
- ----------- -------------- ----------- ---------- -------------
Crude Oil April 2004 $ 34.84 (42,800) $ (478,152)
Crude Oil May 2004 35.56 (18,300) (186,277)
Crude Oil December 2004 31.41 30,000 268,200
---------- -------------
(31,100) $ (396,229)
========== =============
4. 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 months ended March 31,
2003 and 2004. The weighted-average number of shares used to compute diluted
earnings per share was 14,463,210 for the three months ended March 31, 2003 and
2004.
5. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries, CGI, CRII, and Continental Crude
Co. (CCC), have guaranteed the Company's obligations under its outstanding 10
1/4% Senior Subordinated Notes due 2008. CCC has not engaged in any business
activities since its inception. The following is a summary of the condensed
consolidating balance sheets of CGI and CRII as of December 31, 2003, and March
31, 2004, and the results of operations and cash flows for the three-month
periods ended March 31, 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 0 439,432
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 0 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 March 31, 2004 Condensed Consolidating Balance Sheet
- ---------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
--------------- ---------- -------------- ---------------
Current Assets $ 9,882 $ 41,262 $ (13,664) $ 37,480
Property and Equipment 59,038 385,943 0 444,981
Other Assets 263 4,103 (14) 4,352
--------------- ---------- -------------- ---------------
Total Assets $ 69,183 $ 431,308 $ (13,678) $ 486,813
Current Liabilities $ 13,688 $ 40,732 $ (3,278) $ 51,142
Long-Term Debt 24,378 277,207 (10,386) 291,199
Other Liabilities 4,981 22,076 0 27,057
Stockholders' Equity 26,136 91,293 (14) 117,415
--------------- ---------- -------------- ---------------
Total Liabilities and
Stockholders' Equity $ 69,183 $ 431,308 $ (13,678) $ 486,813
=============== ========== ============== ===============
For the Three Months Ended March 31, 2003 Condensed Consolidating Statements of Operations
- ---------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
--------------- ---------- -------------- ---------------
Total Revenue $ 15,845 $ 74,661 $ (2,279) $ 88,227
Operating Expense (14,072) (66,202) 2,279 (77,995)
Other Expense (382) (4,508) 0 (4,890)
Cumulative Effect of Change in Accounting Principle (50) 2,212 0 2,162
--------------- ---------- -------------- ---------------
Net Income $ 1,341 $ 6,163 $ 0 $ 7,504
=============== ========== ============== ===============
For the Three Months Ended March 31, 2004 Condensed Consolidating Statements of Operations
- ---------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
--------------- ---------- -------------- ---------------
Total Revenue $ 24,350 $ 90,246 $ (5,185) $ 109,411
Operating Expense (22,421) (85,909) 5,185 (103,145)
Other Expense (321) (4,953) 0 (5,274)
--------------- ---------- -------------- ---------------
Net Income $ 1,608 $ (616) $ 0 $ 992
=============== ========== ============== ===============
For the Three Months Ended March 31, 2003 Condensed Consolidated Cash Flows Statements
- ---------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
--------------- ---------- -------------- ---------------
Cash Flows From Operating Activities $ 2,787 $ 33,502 $ (22,862) $ 13,427
Cash Flows From Investing Activities (1,556) (26,126) - (27,682)
Cash Flows From Financing Activities (819) 18,719 - 17,900
--------------- ---------- -------------- ---------------
Net Increase (Decrease) in Cash 412 26,095 (22,862) 3,645
Cash at Beginning of Period 456 2,064 - 2,520
--------------- ---------- -------------- ---------------
Cash at End of Period $ 868 $ 28,159 $ (22,862) $ 6,165
=============== ========== ============== ===============
For the Three Months Ended March 31, 2004 Condensed Consolidated Cash Flow Statements
- ---------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
--------------- ---------- -------------- ---------------
Cash Flow From Operating Activities $ 4,598 $ 23,295 $ (13,664) $ 14,229
Cash Flow From Investing Activities (1,819) (18,693) - (20,512)
Cash Flow From Financing Activities (617) 6,591 - 5,974
--------------- ---------- -------------- ---------------
Net Increase (Decrease) in Cash 2,162 11,193 (13,664) (309)
Cash at Beginning of Period 701 1,576 - 2,277
--------------- ---------- -------------- ---------------
Cash at End of Period $ 2,863 $ 12,769 $ (13,664) $ 1,968
=============== ========== ============== ===============
6. BUSINESS SEGMENTS:
The Company has two reportable segments pursuant to Statement of Financial
Accounting Standards (SFAS) No. 131, Disclosure About Segments of an Enterprise
and Related Information, consisting of exploration and production, and gas
gathering, marketing and processing. The Company's reportable business segments
have been 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 come 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 Gas Gathering,
For the Three Months Ended and Marketing and
March 31, 2003 Production Processing Intersegment Total
- ------------------------------------------ --------------- --------------- --------------- --------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 35,530 $ 192 $ - $ 35,722
Crude oil marketing and trading 40,595 - - 40,595
Change in derivative fair value 303 - - 303
Gas gathering, marketing and processing - 12,004 (2,279) 9,725
Oil and gas service operations 1,882 - - 1,882
--------------- --------------- --------------- --------------
Total revenues $ 78,310 $ 12,196 $ (2,279) $ 88,227
OPERATING COSTS AND EXPENSES:
Production expenses 8,581 50 - 8,631
Production taxes 2,659 15 - 2,674
Exploration 1,480 22 - 1,502
Crude oil marketing and trading 40,484 - - 40,484
Gas gathering, marketing and processing - 11,107 (2,279) 8,828
Oil and gas service operations 1,960 - - 1,960
Depreciation, depletion and amortization:
Oil and gas properties 8,549 (247) - 8,302
Other property and equipment 525 623 - 1,148
Property impairments 1,273 3 - 1,276
Asset retirement accretion 350 2 - 352
General and administrative 2,683 155 - 2,838
--------------- --------------- --------------- --------------
Total operating costs and expenses $ 68,544 $ 11,730 $ (2,279) $ 77,995
Total operating income $ 9,766 $ 466 $ - $ 10,232
OTHER INCOME (EXPENSE):
Interest income 90 2 (60) 32
Interest expense (4,951) (60) 60 (4,951)
Other income, net 37 - 37
Loss on sale of assets - (8) - (8)
--------------- --------------- --------------- --------------
Total other income (expense) $ (4,824) $ (66) $ - $ (4,890)
Total income from operations $ 4,942 $ 400 $ - $ 5,342
--------------- --------------- --------------- --------------
Cumulative effect of
change in accounting principle 273 1,889 - 2,162
--------------- --------------- --------------- --------------
Net income $ 5,215 $ 2,289 $ - $ 7,504
=============== =============== =============== ==============
Total assets $ 457,954 $ 33,258 $ (21,797) $ 469,415
=============== =============== =============== ==============
Capital expenditures $ 26,292 $ 1,446 $ - $ 27,738
=============== =============== =============== ==============
Exploration Gas Gathering,
For the Three Months Ended and Marketing and
March 31, 2004 Production Processing Intersegment Total
- ------------------------------------------ --------------- --------------- --------------- --------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 35,986 $ 137 $ - $ 36,123
Crude oil marketing and trading 55,705 - - 55,705
Change in derivative fair value (396) - - (396)
Gas gathering, marketing and processing - 21,050 (5,185) 15,865
Oil and gas service operations 2,114 - - 2,114
--------------- --------------- --------------- --------------
Total revenues $ 93,409 $ 21,187 $ (5,185) $ 109,411
OPERATING COSTS AND EXPENSES:
Production expenses 10,479 69 - 10,548
Production taxes 2,570 12 - 2,582
Exploration 2,092 - - 2,092
Crude oil marketing and trading 55,863 - - 55,863
Gas gathering, marketing and processing - 18,993 (5,185) 13,808
Oil and gas service operations 1,946 - - 1,946
Depreciation, depletion and amortization:
Oil and gas properties 10,445 22 - 10,467
Other property and equipment 348 817 - 1,165
Property impairments 1,897 - - 1,897
Asset retirement accretion 273 4 - 277
General and administrative 2,222 278 - 2,500
--------------- --------------- --------------- --------------
Total operating costs and expenses $ 88,135 $ 20,195 $ (5,185) $ 103,145
Total operating income $ 5,274 $ 992 $ - $ 6,266
OTHER INCOME (EXPENSE):
Interest income 25 2 - 27
Interest expense (5,095) (194) - (5,289)
Other income, net 12 11 23
Loss on sale of assets (35) - - (35)
--------------- --------------- --------------- --------------
Total other income (expense) $ (5,093) $ (181) $ - $ (5,274)
Total income from operations $ 181 $ 811 $ - $ 992
--------------- --------------- --------------- --------------
Net income $ 181 $ 811 $ - $ 992
=============== =============== =============== ==============
Total assets $ 452,168 $ 48,322 $ (13,677) $ 486,813
=============== =============== =============== ==============
Capital expenditures $ 19,331 $ 1,359 $ - $ 20,690
=============== =============== =============== ==============
7. COMPREHENSIVE INCOME (LOSS):
The components of total comprehensive income (loss) for the three months
ended March 31, 2003 and 2004 are as follows:
Three Months Ended March 31,
-------------------------------------
2003 2004
----------------- -----------------
(Dollars in thousands) (restated)
Net Income $ 7,504 $ 992
Other Comprehensive Income (Loss):
Deferred Hedging Loss - (997)
----------------- -----------------
Total Comprehensive Income (Loss) $ 7,504 $ (5)
================= =================
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 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 in 2004. Firm pricing coupled with anticipated
increases in production this year look quite favorable for us. Our Cedar Hills
North Unit and West Cedar Hills Unit are responding to high-pressure air
injection, or HPAI, and to the water injections made throughout the previous 15
months. Response is occurring as initially simulated by our Resource Development
group. Oil production in our Cedar Hills North Unit at March 31, 2004, was
approximately 2,781 Bbls per day, an increase of 454 Bbls per day since November
2003, due to HPAI. Based on the current response and the anticipated continued
response, we expect that approximately 4.0 million barrels of our reserves in
our Cedar Hills North Unit will be moved from proved undeveloped (PUD) reserves
to proved developed producing (PDP) reserves in mid-2004. We anticipate that an
aggregate of up to 20.0 million barrels will be re-classified from PUD to PDP by
the end of 2004. We expect our oil production in our Cedar Hills North Unit, on
a daily basis, to double by the end of 2004 or in early 2005.
The following table reflects our production from our Cedar Hills Units
beginning in November 2003, the time that we began to see HPAI response, through
March 2004:
Monthly Production (Bbls) Increase
------------------------
Property Nov 2003 Mar 2004 Bbls per Day
- ------------------------- ----------- ----------- -------------
Cedar Hills North Unit 69,800 86,200 454
West Cedar Hills Unit 7,700 8,500 18
-------------------------------------
Total 77,500 94,700 472
Currently, our 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. We expect
our lifting costs per barrel to decline as response and increased production
occurs. We expect a return to a normalized lifting cost per barrel in late 2004
or early 2005.
Our Middle Bakken well program currently is a 63 well drilling program in
Richland County, Montana, that has been 100% successful. To date, we have
drilled or participated in eight gross wells as part of this program, all of
which are producing. We are currently drilling two wells. We anticipate drilling
a total of 55 additional wells (including the two currently drilling), which we
will operate in this area. We expect to commence 15 additional wells as part of
this program in 2004. To date, 105 wells have been drilled by various operators
in this area with no dry holes encountered. We expect our Middle Bakken wells to
increase our proved reserve base by an average of 460,000 Bbls per well when
completed.
We expect our offshore and Texas onshore wells, both operated and
non-operated, will provide a balance of gas production for us. Our offshore
group plans to set a platform this year based on a discovery well offshore
Louisiana. We anticipate initial production from this area in late 2004 or early
2005.
During the first quarter of 2004, the plant throughput in our Matli
gas-processing system was 1.4 Bcf, an increase of .6 Bcf, or 77% over the Matli
plant throughput in the first quarter of 2003. In addition, during the first
quarter of 2004 we drilled or participated in 16 wells of which 3 were
unsuccessful. In the first quarter of 2003, we drilled or participated in 16
wells, all of which were successful.
Our capital expenditure budget for 2004 is $82.0 million. Through the end
of the first quarter of 2004, our aggregate capital expenditures were $20.7
million.
THREE MONTHS ENDED MARCH 31, 2003, COMPARED TO THREE MONTHS ENDED MARCH 31, 2004
The following table shows our statement of operations for the first quarter
of 2003 compared to the first quarter of 2004 with dollar and percentage
increases or decreases:
1st Quarter 1st Quarter Increase % Increase
REVENUES: 2003 2004 (Decrease) (Decrease)
----------------- ----------------- ---------------- --------------
Oil and gas $ 35,722 $ 36,123 $ 401 1.12%
Crude oil marketing and trading 40,595 55,705 15,110 37.22%
Change in derivative fair value 303 (396) (699) -230.69%
Gas gathering, marketing and processing 9,725 15,865 6,140 63.14%
Oil and gas service operations 1,882 2,114 232 12.33%
----------------- ----------------- ---------------- --------------
Total revenues $ 88,227 $ 109,411 $ 21,184 24.01%
OPERATING COSTS AND EXPENSES:
Production $ 8,631 $ 10,548 $ 1,917 22.21%
Production taxes 2,674 2,582 (92) -3.44%
Exploration 1,502 2,092 590 39.28%
Crude oil marketing and trading 40,484 55,863 15,379 37.99%
Gas gathering, marketing and processing 8,828 13,808 4,980 56.41%
Oil and gas service operations 1,960 1,946 (14) -0.71%
DD&A of oil and gas properties 8,302 10,467 2,165 26.08%
DD&A of other assets 1,148 1,165 17 1.48%
Property impairments 1,276 1,897 621 48.67%
Asset retirement obligation accretion 352 277 (75) -21.31%
General and administrative 2,838 2,500 (338) -11.91%
----------------- ----------------- ---------------- --------------
Total operating costs and expenses $ 77,995 $ 103,145 $ 25,150 32.25%
OPERATING INCOME $ 10,232 $ 6,266 $ (3,966) -38.76%
OTHER INCOME AND EXPENSE:
Interest income $ 32 $ 27 $ (5) -15.63%
Interest expense (4,951) (5,289) (338) 6.83%
Other income, net 37 23 (14) -37.84%
Loss on sale of assets (8) (35) (27) 337.50%
----------------- ----------------- ---------------- --------------
Total other income and (expenses) $ (4,890) $ (5,274) $ (384) 7.85%
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE $ 5,342 $ 992 $ (4,350) -81.43%
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE $ 2,162 $ - $ (2,162) -100.00%
NET INCOME $ 7,504 $ 992 $ (6,512) -86.78%
================= ================= ================ ==============
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 March 31,
---------------------------------
2003 2004
--------------- ---------------
NET PRODUCTION DATA:
Oil and Condensate (MBbl) 907 787
Natural Gas (MMcf) 2,368 2,321
Total Oil equivalent (MBoe) 1,302 1,174
OIL AND GAS SALES (dollars in thousands)
Oil sales, excluding hedges $ 28,115 $ 25,450
Hedges (4,726) (454)
--------------- ---------------
Total oil sales, including hedges 23,389 24,996
Gas sales 12,333 11,127
--------------- ---------------
Total oil and gas sales $ 35,722 $ 36,123
=============== ===============
AVERAGE SALES PRICE:
Oil, excluding hedges (dollar per barrel) $ 31.01 $ 32.33
Oil, including hedges (dollar per barrel) $ 25.78 $ 31.75
Gas (dollar per Mcf) $ 5.21 $ 4.79
Oil equivalent, excluding hedges (dollar per Boe) $ 31.07 $ 31.15
Oil equivalent, including hedges (dollar per Boe) $ 27.44 $ 30.77
EXPENSES (dollar per Boe):
Production expenses (including taxes) $ 8.68 $ 11.18
General and administrative $ 2.18 $ 2.13
DD&A (on oil and gas properties) $ 6.38 $ 8.91
REVENUES
GENERAL
The increase in revenues is attributable to higher oil prices realized on
our oil production and an increase in volumes from our oil marketing and trading
programs. Gas gathering, marketing and processing revenues were higher for the
three months ended March 31, 2004, compared to the same period in 2003 primarily
due to our acquisition of the Carmen Gathering System, which increased our total
throughput.
OIL AND GAS SALES
The decrease in oil and gas sales revenues was primarily attributable to a
reduction in oil volumes due to the conversion of wells in our Cedar Hills North
Unit to injection wells and certain of our oil and gas wells in Montana being
shut in due to extreme weather during the first quarter of 2004.
The following table shows our production by region for the three months
ended March 31, 2003 and 2004:
Three Months Ended March 31,
--------------------------------------------------------
2003 2004
--------------------------- ---------------------------
MBoe Percent MBoe Percent
----------- -------------- ---------- ---------------
Rocky Mountain 772 59.29% 681 58.01%
Mid-Continent 391 30.03% 369 31.43%
Gulf 139 10.68% 124 10.56%
=========== ============== ========== ==============
1,302 100.00% 1,174 100.00%
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 quarter of 2004, we engaged in certain crude oil
trading activities, exclusive of our own production, utilizing fixed price and
variable priced physical delivery contracts. For the three months ended March
31, 2004, crude oil marketing revenues were $10.3 million and crude oil
marketing expenses were also $10.3 million, related to such trading activities.
We had no crude oil marketing revenue or expense in the first quarter of 2003.
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.
CHANGE IN DERIVATIVE FAIR VALUE
The change in derivative fair value for the three months ended March 31,
2003, related to a crude oil derivative contract used to reduce our exposure to
changes in crude oil prices but 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 three months ended March 31, 2004, is the result
of those derivative trading contracts described in Note 3 to our Condensed
Consolidated Financial Statements.
GAS GATHERING, MARKETING AND PROCESSING
The increase in our gas gathering, marketing and processing revenue during
the first quarter of 2004 was attributable to increased throughput volumes
resulting from growth in our existing systems and our acquisition of the Carmen
Gathering System in July 2003.
OIL AND GAS SERVICE OPERATIONS
The increase in our oil and gas service operations was primarily due to an
increase in reclaimed oil revenue of $0.3 million due to higher oil prices,
offset by decreases in our other income of $0.1 million.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses including taxes increased primarily due to
increased energy expense of $1.0 million. Energy expense increased due to higher
utility costs in general and costs associated with running the compressors for
HPAI in the Cedar Hills Units. Our labor costs increased $0.3 million in the
first quarter of 2004 compared to the first quarter of 2003.
EXPLORATION EXPENSES
The increase in exploration expense was primarily due to an increase in our
dry hole costs of $1.2 million in the Gulf Coast region, partially offset by
decreases in other expenses of $0.6 million.
CRUDE OIL MARKETING AND TRADING
The increase in our crude oil marketing expense was primarily due to
increased prices for oil that we purchased and increased volumes marketed and
traded.
GAS GATHERING, MARKETING, AND PROCESSING
The increase in our gas gathering, marketing and processing expense during
the first quarter of 2004 was attributable to increased throughput volumes
resulting from growth in our existing systems and our acquisition of the Carmen
Gathering System in July 2003.
OIL AND GAS SERVICE OPERATIONS
The change in our oil and gas service operations expense was immaterial.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES (DD&A)
Depletion increased $2.3 million in the first quarter of 2004 compared to
the first quarter of 2003, due to certain developmental dry hole costs being
added to our amortization base and depleted with the costs of the related field
and due to higher production decline rates in our Gulf Coast Region. The decline
rate on one of our more significant fields in the Gulf Coast Region increased
from 14% to 40% due principally to the rapid depletion of the reserves in this
field. In the first quarter of 2004, our DD&A expense on our oil and gas
properties was calculated at $8.91 per BOE, compared to $6.38 per BOE for the
first quarter of 2003.
DEPRECIATION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT
Our change in depreciation and amortization expense related to our other
property and equipment was immaterial.
PROPERTY IMPAIRMENTS
The increase in our property impairments was primarily due to increased
impairment on capitalized costs of our undeveloped leasehold.
ASSET RETIREMENT ACCRETION
We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on
January 1, 2003. For the three months ended March 31, 2004, our asset retirement
accretion was $0.3 million compared to $0.4 million for the comparable period in
2003.
GENERAL AND ADMINISTRATIVE (G&A)
Our G&A expense per BOE for the first quarter of 2004 was $2.13 compared to
$2.18 for the first quarter of 2003.
INTEREST EXPENSE
The increase in our interest expense was due to additional interest on
higher average debt balances outstanding under our credit facilities during the
first quarter of 2004.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Net cash provided by our operating activities for the three months ended
March 31, 2004, was $14.2 million, an increase of $0.8 million from $13.4
million provided by our operating activities during the comparable 2003 period.
Our cash balance as of March 31, 2004, was $2.0 million, a decrease of $0.3
million from our cash balance of $2.3 million held at December 31, 2003.
DEBT
Our long-term debt at December 31, 2003, was $285.1 million and at March
31, 2004, $291.2 million. At March 31, 2004, we had outstanding $127.2 million
principal amount in our senior subordinated notes, $156.8 million outstanding
under our secured credit facilities, and $7.2 million outstanding in capital
lease obligations with $5.8 million due within the next year.
CREDIT FACILITY
At March 31, 2004, we had $140.4 million of revolving credit debt
outstanding under our exploration and production secured credit facility.
Borrowings under our 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 credit facility was 3.8% at March 31, 2004. The borrowing base of our credit
facility was $145.0 million on March 31, 2004 and is re-determined
semi-annually. Borrowings under our exploration and production credit facility
are secured by liens on substantially all of our assets.
On April 14, 2004, the company executed the Third Amendment to the Credit
Agreement that provided for the addition of a term credit facility in an amount
up to $25 million that matures on March 31, 2006. The amendment also extended
the maturity date of the original facility to March 31, 2007, and increased the
borrowing base to $150.0 million. Borrowings under the term credit facility have
margins of 5.5% on LIBOR loans and 3% on prime loans. On April 14, 2004, the
company drew $25 million on the new term credit facility and paid down the
balance of the original revolving credit facility. At May 6, 2004, the
outstanding balances were $124.5 million and $25.0 million on the original
revolving credit facility and the term loan, respectively.
On October 22, 2003, our subsidiary, Continental Gas, Inc, or 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. The initial advance under the term
loan facility was $17.0 million, which was paid to CRI and used to reduce the
outstanding balance on our credit facility. No funds were initially advanced
under the revolving loan facility. Advances under either facility can be made,
at the borrower's election, as reference rate loans or LIBOR rate loans and,
with respect to LIBOR loans, for interest periods of one, two, three, or six
months. Interest is payable on reference rate loans monthly and on LIBOR loans
at the end of the applicable interest period. The principal amount of the term
loan facility is to be amortized on a quarterly basis through June 30, 2006, the
final payment being due September 30, 2006. The amount available under the
revolving loan facility may be borrowed, repaid and reborrowed until maturity on
September 30, 2006. Interest on reference rate loans is calculated with reference toat a rate
equal to the higher of the reference rate of Union Bank of California, N.A. or
the federal funds rate plus 0.5%. Interest on LIBOR loans is calculated with
reference to the London interbank offered interestInterbank Offered rate. Interest accrues at the
reference rate or the LIBOR rate, as applicable, plus the applicable margin. The
applicable margin is based on the then currentratio of senior debt to EBITDA ratio.EBITDA. The credit agreement
contains certain covenants and requires certain quarterly mandatory prepayments
of 75% of excess cash flow. The credit facility is secured by a pledge of all of
the assets of CGI. On October 22, 2003, the Company executed the Second Amendment to the
Credit Agreement and deleted CGI as a guarantor of the Company's obligations
under the Credit Agreement. The borrowing base under the Second Amendment to the
Credit Agreement was revised to $145.0 million andAt March 31, 2004 the outstanding balance on CGI's credit
facility was reduced by the $17.0 million funded to CGI.
The Company's line of$16.4 million.
Our credit agreement contains certain negative financial reportingand other covenants. The Company wasAt
March 31, 2004, we were not in compliance with the covenanttwo covenants, one that requires
the Companyus to maintain a minimum current ratio of 1.0:1. However, on1:1 and another that prohibits trading
activity other than normal production contracts without prior approval of the
required banks. On a pro-forma basis after giving the effects of the Second Amended Credit Agreement, the
Company was in compliance. The Company received a waiver for non-compliance from
the bank group.
4. CRUDE OIL MARKETING:
Prior to May 2002, the Company conducted crude oil trading activities,
exclusive of its own production. Such activity was discontinued in May 2002.
Since May 2002, the Company has entered into third party contracts to purchase
and resell only its own physical production. The Company will continue to
repurchase its physical production from the Rocky Mountain area and resell
equivalent barrels in Oklahoma to take advantage of better pricing and to reduce
its credit exposure from sales to its first purchaser. The Company presents
sales and purchases of its production from the Rocky Mountain area as crude oil
marketing income and crude oil marketing expense, respectively. During the nine
months ended September 30, 2002, the Company recognized revenues from the sale
of crude oil of $120.5 million and expenses for the purchase of crude oil of
$119.7 million (including revenues of $85.8 million and expenses of $85.1
million related to crude oil trading activities discontinued as of May 2002)
resulting in a gain from crude oil marketing activities for the nine month
period of $0.7 million.
5. EARNINGS PER SHARE:
Basic earnings per common share is computed by dividing income available to
common stockholders by the weighted-average number of shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if dilutive stock options were exercised, using the treasury stock method
of calculation. The weighted-average number of shares used to compute basic
earnings per common share was 14,368,919 for the three and nine months ended
2002 and 2003. The weighted-average number of shares used to compute diluted
earnings per share was 14,416,469 for the three and nine months ended September
30, 2003 and 14,393,132 for the three and nine months ended September 30, 2002.
6. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries, Continental Gas, Inc. (CGI),
Continental Resources of Illinois, Inc. (CRII), and Continental Crude Co. (CCC),
have guaranteed the Company's outstanding Senior Subordinated Notes and its bank
credit facility. The following is a summary of the condensed consolidating
financial information of CGI and CRII as of December 31, 2002, and September 30,
2003, and for the three-month and nine-month periods ended September 30, 2002,
and 2003.
Condensed Consolidating Balance Sheet
As of December 31, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Current Assets $ 6,524 $ 49,308 $ (22,862) $ 32,970
Property and Equipment 42,664 325,239 - 367,903
Other Assets 7 5,811 (14) 5,804
---------------------------- ------------- -------------
Total Assets $ 49,195 $ 380,358 $ (22,876) $ 406,677
Current Liabilities $ 11,442 $ 42,258 $ (6,934) 46,766
Long-Term Debt 15,928 244,705 (15,928) 244,705
Other Liabilities - 125 - 125
Stockholders' Equity 21,825 93,270 (14) 115,081
---------------------------- ------------- ------------
Total Liabilities and
Stockholders' Equity $ 49,195 $ 380,358 $ (22,876) $ 406,677
============= ============= ============= =============
As of September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Current Assets $ 10,450 $ 62,369 $ 32,663) $ 40,156
Property and Equipment 59,417 404,713 - 464,130
Other Assets 7 4,778 (14) 4,771
---------------------------- ------------- -------------
Total Assets $ 69,874 $ 471,860 $ (32,677) $ 509,057
Current Liabilities $ 15,126 $ 45,053 $ (6,811) $ 53,368
Long-Term Debt 25,852 286,875 (25,852) 286,875
Other Liabilities 4,147 33,273 - 37,420
Stockholders' Equity 24,749 106,659 (14) 131,394
------------------------------------------- -------------
Total Liabilities and
Stockholders' Equity $ 69,874 $ 471,860 $ (32,677) $ 509,057
============= ============= ============= =============
Condensed Consolidating Income Statements
For the Three Months Ended September 30, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Total Revenue $ 11,828 $ 60,191 $ 20 $ 72,039
Operating Expenses (10,793) (53,217) (20) (64,030)
Other Income (Expenses) (399) (4,025) - (4,424)
------------- ------------- ------------- -------------
Net Income $ 636 $ 2,949 $ - $ 3,585
============= ============= ============= =============
For the Three Months Ended September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ----------------------------------------------------------
Total Revenue $ 26,565 $ 73,700 $ (123) $ 100,142
Operating Expenses (26,020) (66,266) 123 (92,163)
Other Income (Expenses) (468) (4,479) - (4,947)
------------- ------------- ------------- -------------
Net Income $ 77 $ 2,955 $ - $ 3,032
============= ============= ============= =============
Condensed Consolidating Income Statements
For the Nine Months Ended September 30, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Total Revenue $ 35,458 $ 192,640 $ (860) $ 227,238
Operating Expenses (31,776) (178,198) 860 (209,114)
Other Income (Expenses) (1,259) (11,714) - (12,973)
------------- ------------- ------------- -------------
Net Income $ 2,423 $ 2,728 $ - $ 5,151
============= ============= ============= =============
For the Nine Months Ended September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Total Revenue $ 61,991 $ 220,763 $ (1,633) $ 281,121
Operating Expenses (58,474) (197,574) 1,633 (254,415)
Other Income (Expenses) (1,153) (13,330) - (14,483)
Cumulative Effect of Change in Accounting Principle 560 3,530 - 4,090
------------- ------------ ------------- -------------
Net Income $ 2,924 $ 13,389 $ - $ 16,313
============= ============= ============= =============
Condensed Consolidated Cash Flow Statements
For the Nine Months Ended September 30, 2002
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Cash Flow From Operating Activities $ 7,759 $ 40,456 $ (22,624) $ 25,591
Cash Flow From Investing Activities (5,066) (69,854) - (74,920)
Cash Flow From Financing Activities (2,924) 48,032 - 45,108
------------- ------------- ------------- -------------
Net Increase (Decrease) in Cash (231) 18,634 (22,624) (4,221)
Cash at Beginning of Period 707 6,518 - 7,225
------------- ------------- ------------- -------------
Cash at End of Period $ 476 $ 25,152 $ (22,624) $ 3,004
For the Nine Months Ended September 30, 2003
- ---------------------------------------------------------------------------------------------------------------
(Dollars in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
- --------------------------------------------------- ------------- ------------- ------------- -------------
Cash Flow From Operating Activities $ 7,357 $ 74,104 $ (32,676) $ 48,785
Cash Flow From Investing Activities (16,878) (74,409) - (91,287)
Cash Flow From Financing Activities 9,924 33,057 - 42,981
------------- ------------- ------------- -------------
Net Increase (Decrease) in Cash 403 32,752 (32,676) 479
Cash at Beginning of Period 456 2,064 - 2,520
------------- ------------- ------------- -------------
Cash at End of Period $ 859 $ 34,816 $ (32,676) $ 2,999
At September 30, 2003, current and long-term liabilities payableeffect to the Company by the guarantor subsidiaries totaled approximately $32.7 million. For
the nine months ended September 30, 2002 and 2003, depreciation, depletion and
amortization included in the guarantor subsidiaries operating costs were
approximately $4.2 million and $4.3 million, respectively.
7. ASSET RETIREMENT OBLIGATIONS:
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. Subsequently, the asset retirement cost should be
allocated to expense using a systematic and rational method and the liability
should be accreted to its face amount. The Company adopted SFAS No. 143 on
January 1, 2003. The primary impact of this standard relates to oil and gas
wells that the Company has a legal obligation to plug and abandon. Prior to SFAS
No. 143, the Company had not recorded an obligation for these plugging and
abandonment costs due to its assumption that the salvage value of the surface
equipment would substantially offset the cost of dismantling the facilities and
carrying out the necessary clean up and reclamation activities. The adoption of
SFAS No. 143 on January 1, 2003, resulted in a net increase to Property and
Equipment and Asset Retirement Obligations of approximately $39.3 million and
$35.2 million, respectively, as a result of the Company separately accounting
for salvage values and recording the estimated fair value of its plugging and
abandonment obligations on the balance sheet. The impact of adopting SFAS No.
143 has been accounted for through a cumulative effect of change in accounting
principle adjustment that amounted to a $4.1 million increase to net income
recorded on January 1, 2003. The increase in expense resulting from the
accretion of the asset retirement obligations and the depreciation of the
additional capitalized well costs is expected to be substantially offset by the
decrease in depreciation from the Company's consideration of the estimated
salvage values of the assets.
The following table describes on a pro forma basis the Company's asset
retirement liability as if SFAS No. 143 had been adopted on January 1, 2002.
2002 2003
------------- -------------
Asset Retirement Obligation liability at January 1, $ 33,495 $ 35,173
Asset Retirement Obligation accretion expense 1,005 1,055
Plus: Additions for new assets 1,478 1,807
Less: Plugging costs and sold assets (349) (777)
------------- -------------
Asset Retirement Obligation liability at September 30, $ 35,629 $ 37,258
============= =============
The following table describes the pro forma effect on net income and
earnings per share for the three and nine months ended September 30, 2002, as if
SFAS No. 143 had been adopted in January 1, 2002.
Three Months Nine Months
Ended September 30, Ended September 30,
2002 2002
-------------------- -------------------
Net income - as reported $ 3,585 $ 5,151
Less: Asset retirement obligation accretion expense (335) (1,005)
Plus: Reduction in depreciation expense on salvage value 1,220 2,440
------------- --------------
Net income - pro forma $ 4,470 $ 6,586
============= ==============
Earnings per share:
As reported
Basic $ 0.25 $ 0.36
Diluted $ 0.25 $ 0.36
Pro Forma
Basic $ 0.31 $ 0.46
Diluted $ 0.31 $ 0.46
8. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS:
In December 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." Interpretation No. 45 requires that at
the time a company issues a guarantee, the company must recognize an initial
liability for the fair value, or market value, of the obligations it assumes
under that guarantee. Interpretation No. 45 is applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. The Company adopted
this new interpretation effective January 1, 2003 and the adoption of this new
interpretation did not have a material impact on its consolidated financial
position or results of operations.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of Accounting Research Bulletin
No. 51." Interpretation No. 46 requires the consolidation of entities in which
an enterprise absorbs a majority of the entity's expected losses, receives a
majority of the entity's expected residual returns, or both, as a result of
ownership, contractual or other financial interests in the entity. Currently,
entities are generally consolidated by an enterprise when it has a controlling
financial interest through ownership of a majority voting interest in the
entity.
Interpretation No. 46 applies immediately to variable interest entities
created after January 31, 2003, and to variable interest entities in which an
enterprise obtains an interest after that date. In October 2003, the FASB issued
Interpretation No, 46-6, "Effective Date of FASB Interpretation No. 46,
Consolidation of Variable Interest Entities," in which the FASB agreed to defer,
for public companies, the required effective dates to implement Interpretation
No. 46 for interests held in a variable interest entity ("VIE") or potential VIE
that was created before February 1, 2003. For calendar year-end public
companies, the deferral effectively moves the required effective date from July
1, 2003 to December 31, 2003. As a result of Interpretation No. 46-6, public
entity need not apply the provisions of Interpretation No. 46 to an interest
held in a VIE or potential VIE until the end of the first interim or annual
period ending after December 15, 2003, if the VIE was created before February 1,
2003, and the public entity has not issued financial statements reporting that
VIE in accordance with Interpretation No. 46, other than in the disclosures
required by Interpretation No. 46. Interpretation No. 46 may be applied
prospectively with a cumulative-effect adjustment as of the date on which it is
first applied or by restating previously issued financial statements for one or
more years with a cumulative-effect adjustment as of the beginning of the first
year restated. The Company is currently evaluating the effect of the issuance of
Interpretation No. 46; however, the Company does not believe that the impact of
adoption of Interpretation No. 46 will be material to its consolidated financial
position or results of operations.
In April 2003, the FASB issued SFAS No. 149, "Amendments of Statement 133
on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain instruments embedded in other contracts and for hedging
activities under SFAS No. 133. This statement requires that contracts with
comparable characteristics be accounted for similarly. In particular, this
statement clarifies under what circumstances a contract with an initial net
investment meets the characteristic of a derivative, clarifies when a derivative
contains a financing component, amends the definition of an underlying hedged
risk to conform to language used in FASB Interpretation No. 45 and amends
certain other existing pronouncements. This statement, the provisions of which
are to be applied prospectively, is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003. The Company adopted this new standard effective July 1, 2003 and the
adoption of this new standard did not have a material impact on its consolidated
financial position or results of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. The
requirements of this statement apply to an issuer's classification and
measurement of freestanding financial instruments, including those that comprise
more than one option or forward contract. This statement does not apply to
features that are embedded in a financial instrument that are not a derivative
in its entirety. This statement also addresses questions about the
classification of certain financial instruments that embody obligations to issue
equity shares. The provisions of this statement are effective for financial
instruments entered into or modified after May 31, 2003, and otherwise is
effective at the beginning of the first interim period beginning after June 15,
2003, with the exception of the application of such statement to limited life
subsidiaries. The FASB has deferred the application of SFAS No. 150 to limited
life subsidiaries indefinitely. The Company adopted this new standard effective
July 1, 2003, and the adoption of this new standard did not have a material
impact on its consolidated financial position or results of operations.
9. SUBSEQUENT EVENTS:
FINANCING
On October 22, 2003, CGI closed on a new $35.0 million secured credit
facility consisting of a senior secured term loan facility of up to $25.0
million, and a senior secured revolving credit facility of up to $10.0 million.
The credit facility is secured by a pledge of all the assets of CGI. The initial
advance under the term loan facility was $17.0 million, which was paid to CRI to
reduce CRI's outstanding balance at its credit facility. (See Note 2 LONG-TERM
DEBT)
On October 22, 2003, the Company executed the SecondThird Amendment
to the Credit Agreement, and deleted CGI as a guarantor of the Company's obligations
under the Credit Agreement. CGI paid CRI $17.0 million, which reduced the
outstanding balance at its credit facility. The borrowing base under the Second
Amendment to the Credit Agreement was revised to $145.0 million. (See Note 2
LONG-TERM DEBT)
HEDGES
The Second Amendment to the Credit Agreement requires that the Company have
50% of its production hedged on a rolling six- month term. The Company has
established costless collars from October 2003 thru March 2004 with a floor
price of $22.00 and an average ceiling price of $35.00. Such contracts are being
accounted for as cash flow hedges.
In order to mitigate price risk exposure on production, CGI has forward
sales contracts in place that will result in the physical delivery of production
and qualify as being in the normal course of business sales and are not
accounted for as derivatives. As of September 30, 2003, CGI has 50,000 MMBTU per
month hedged from January 2004 to December 2007 at an average price of $4.579
per MMBTU. These hedges account for 9% of the total delivery point volumes and
4% of overall company throughput.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Certain amounts applicable to the prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do not
affect earnings.
OVERVIEW
The following table sets forth certain information regarding our production
volumes, oil and gas sales, average sales prices received and expenses for the
periods indicated:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------------ -----------------------------
2002 2003 2002 2003
------------------------------ -----------------------------
NET PRODUCTION:
Oil (MBbl) 985 854 2,869 2,645
Gas (MMcf) 2,489 2,537 7,014 7,496
Oil equivalent (MBoe) 1,400 1,277 4,038 3,894
OIL AND GAS SALES (dollars in thousands)
Oil sales, excluding hedges $ 25,561 $ 23,920 $ 66,881 $ 76,694
Hedges (2,033) (1,293) (2,742) (8,597)
-------------- -------------- -------------- --------------
Total oil sales, including hedges 23,528 22,627 64,139 68,097
Gas sales 6,049 11,723 15,884 35,322
-------------- -------------- ------------------------------
Total oil and gas sales $ 29,577 $ 34,350 $ 80,023 $ 103,419
============== ============== ============== ==============
AVERAGE SALES PRICE:
Oil, excluding hedges (dollar per barrel) $ 25.96 $ 28.02 $ 23.31 $ 29.00
Oil, including hedges (dollar per barrel) $ 23.90 $ 26.51 $ 22.36 $ 25.75
Gas (dollar per Mcf) $ 2.43 $ 4.62 $ 2.27 $ 4.71
Oil equivalent, excluding hedges (dollar per Boe) $ 22.58 $ 27.92 $ 20.50 $ 28.77
Oil equivalent, including hedges (dollar per Boe) $ 21.13 $ 26.91 $ 19.82 $ 26.56
EXPENSES (dollars per Boe):
Production expenses (including taxes) $ 6.84 $ 9.26 $ 6.68 $ 9.01
General and administrative $ 2.23 $ 2.09 $ 1.96 $ 2.15
DD&A (on oil and gas properties) $ 3.23 $ 6.37 $ 4.59 $ 6.00
THREE MONTHS ENDED SEPTEMBER 30, 2003, COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2002.
OVERVIEW
The following discussion and analysis should be read in conjunction with
our unaudited condensed consolidated financial statements and the notes thereto
appearing elsewhere in this report. Our operating results for the periods
discussed may not be indicative of future performance. In the text below,
financial statement numbers have been rounded; however, the percentage changes
are based on amounts that have not been rounded.
RESULTS OF OPERATIONS
REVENUES
GENERAL
Our revenues increased $28.1 million, or 39%, to $100.1 million during the
three months ended September 30, 2003, from $72.0 million during the comparable
period in 2002. The increase is primarily attributable to higher oil and gas
prices and higher gathering, marketing and processing revenues in the third
quarter of 2003 compared to the third quarter of 2002.
OIL AND GAS SALES
Our oil and gas sales revenue for the three months ended September 30,
2003, increased $4.8 million, or 16%, to $34.4 million from $29.6 million during
the comparable period in 2002. Oil sales revenue decreased $0.9 million, or 4%,
to $22.6 million for the three months of 2003 from $23.5 million in 2002. Oil
production decreased by 131 MBbls to 854 MBbls, or 13%, for the three months
ended September 30, 2003, from 985 MBbls for the comparable period in 2002. The
oil production decrease of 131 MBbls includes 86 MBbls as the result of
converting producing wells into injection wells in the Cedar Hills Field. Oil
prices, including hedging, increased $2.61 Bbl to an average of $26.51 Bbl, or
11%, during the three months ended September 30, 2003, from $23.90 Bbl, for the
comparable 2002 period. Gas sales revenue increased $5.7 million, or 94%, to
$11.7 million for the three-month period in 2003 compared to $6.0 million in
2002. Gas production for the period increased 48 MMcf, or 2%, to 2,537 MMcf from
2,489 MMcf in 2002. The increase in gas sales revenues is primarily attributable
to higher gas prices that averaged $4.62 Mcf in the third quarter of 2003
compared to $2.43 Mcf in the third quarter of 2002, or an increase of $2.19 per
Mcf, or 90%.
CRUDE OIL MARKETING
Since May 2002, we have had third party contracts to purchase and resell
only our own production. We will continue to repurchase our production from the
Rocky Mountain area and resell equivalent barrels in Oklahoma to take advantage
of better pricing and to reduce our credit exposure from sales to our first
purchaser. We present sales and purchases of our production from the Rocky
Mountain area on a gross basis as crude oil marketing income and crude oil
marketing expense, respectively.
During the three month period ended September 30, 2003, we recognized
revenues of $39.7 million in crude oil marketing income compared to $33.5
million for the three-month period ended September 30, 2002. This increase
resulted from an increase in oil prices.
DERIVATIVE
We have fixed price physical delivery contracts in place to deliver
approximately 93,000 barrels of our forecasted crude oil production per month
through December 2003 at an average price of $24.66 per barrel. These contracts
are considered to be in the normal course of business and have been designated
as such, thus the contracts are not accounted for as derivatives under Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. Revenues from these firm commitments are recognized as
production occurs.
In addition to the above contracts, at September 30, 2003, we also had in
place a crude oil derivative contract that is being marked to market under SFAS
No. 133 with changes in fair value being recorded in earnings as such contract
does not qualify for special hedge accounting nor does such contract meet the
criteria to be considered in the normal course of business. This contract
provides for a fixed price of $24.25 per barrel on 30,000 barrels of crude oil
per month through December 2003 when market prices exceed $19.00 per barrel.
When market prices fall below $19.00, we receive the market price. During the
three month period ended September 30, 2003, we recorded a gain of $0.5 million
in change in derivative fair value to reflect the mark-to-market valuation at
September 30, 2003.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue in the third quarter of
2003 was $23.3 million, an increase of $15.0 million, or 180%, from $8.3 million
in the same period in 2002. This increase in revenue during the third quarter
was attributable to greater volumes processed and higher natural gas and liquids
prices. The acquisition of the Carmen Gathering System, effective August 1,
2003, attributed $3.7 million to revenues in the third quarter of 2003.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenue for the three months ended
September 30, 2003, was $2.3 million, an increase of $0.9 million, or 58%, from
$1.4 million for the three months ended September 30, 2002. The increase was
primarily due to an increase in reclaimed oil income of $0.6 million due to
higher prices.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses, including taxes, were $11.8 million for the three
months ended September 30, 2003, an increase of $2.2 million, or 23%, over the
2002 expense of $9.6 million. Production taxes increased $0.4 million due to
higher oil and gas prices in 2003 and energy costs increased $1.5 million due to
higher utility costs in 2003 associated with the Cedar Hills Field. The balance
of the increase was due to higher labor costs and an increase in workover and
other expenses.
EXPLORATION EXPENSES
For the three months ended September 30, 2003, our exploration expenses
increased $1.0 million, or 40%, to $3.5 million from $2.5 million during the
comparable period of 2002. The increase was mainly due to an increase in seismic
costs of $0.8 million and geological costs of $0.1 million.
CRUDE OIL MARKETING
For the three months ended September 30, 2003, we recognized an expense of
$39.0 million, an increase of $5.6 million, or 17% compared to $33.4 million for
the three months ended September 30, 2002. Higher oil prices resulted in the
increased cost in 2003.
GATHERING, MARKETING, AND PROCESSING
During the three months ended September 30, 2003, we incurred gathering,
marketing and processing expenses of $22.1 million, representing a $14.4
million, or 187%, an increase from $7.7 million incurred in the third quarter of
2002 due to greater volumes processed and higher natural gas and liquids prices
on products we purchased for resale. The acquisition of the Carmen Gathering
System , effective August 1, 2003, attributed $3.1 million in expenses in the
third quarter of 2003.
OIL AND GAS SERVICE OPERATIONS
During the three months ended September 30, 2003, we incurred oil and gas
service operations expense of $2.1 million, a $0.3 million, or 17%, increase
over the $1.8 million for the comparable period in 2002. The increase was due to
the increased cost of purchasing and treating reclaimed oil for resale.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES ("DD&A")
For the three months ended September 30, 2003, DD&A of our oil and gas
properties increased $3.6 million, or 80%, to $8.1 million from $4.5 million for
the comparable period in 2002. In the third quarter of 2003, our DD&A expense on
oil and gas properties was calculated at $6.37 per BOE compared to $3.23 per BOE
for the third quarter of 2002. The adoption of SFAS No. 143 on January 1, 2003,
has decreased our DD&A $0.8 million offset by an increase in DD&A rates for the
third quarter of 2003.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT
("DD&A")
For the three months ended September 30, 2003, DD&A of our other property
and equipment increased $0.1 million, or 15%, to $1.2 million from $1.1 million
for the comparable period in 2002.
PROPERTY IMPAIRMENTS
For the three months ended September 30, 2003, our property impairments
expense increased $0.7 million, or 115%, to $1.3 million from $0.6 million for
the same period in 2002. The increase was due to an increase in reserves for
impairment associated with our undeveloped leasehold.
At September 30, 2003, we had approximately $13.5 million capitalized
related to certain proved undeveloped reserves and approximately $3.3 million
capitalized related to certain proved non-producing reserves (acid fracs)
acquired in 1998. A third party is currently in the process of reviewing the
proved undeveloped reserves. The results of the third party review are
anticipated in the fourth quarter. No impairments were indicated at September
30, 2003; however, it is possible these costs could be impaired at some future
date.
ASSET RETIREMENT ACCRETION
For the three months ended September 30, 2003, our asset retirement
accretion was $0.3 million due to the adoption of SFAS No. 143 on January 1,
2003.
GENERAL AND ADMINISTRATIVE ("G&A")
For the three months ended September 30, 2003, our G&A expense was $2.7
million, a decrease of $0.2 million, or 7%, from $2.9 million for the three
months ended September 30, 2002. Our G&A expense per BOE for the third quarter
of 2003 was $2.09 compared to $2.23 for the third quarter of 2002. The decrease
in G&A expense is due to more supervision per joint operating agreements being
billed out to third parties in the third quarter of 2003 than the third quarter
of 2002.
INTEREST EXPENSE
For the three months ended September 30, 2003, our interest expense was
$5.1 million, an increase of $0.4 million, or 9%, from $4.7 million for the
three months ended September 30, 2002. This increase was due to additional
interest paid on our credit facility due to higher average debt balances
outstanding.
NET INCOME
For the three months ended September 30, 2003, our net income was $3.0
million, a decrease of $0.6 million, or 17%, from $3.6 million for the
comparable period in 2002.
NINE MONTHS ENDED SEPTEMBER 30, 2003, COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 2002.
REVENUES
GENERAL
Our revenues increased $53.9 million, or 24%, to $281.1 million during the
nine months ended September 30, 2003, from $227.2 million during the comparable
period in 2002. The increase is attributable to higher oil and gas prices and
higher gathering, marketing and processing revenues at September 30, 2003,
compared to September 30, 2002.
OIL AND GAS SALES
Our oil and gas sales revenue for the nine months ended September 30, 2003,
increased $23.4 million, or 29%, to $103.4 million from $80.0 million during the
comparable period in 2002. Oil sales revenue for the nine months of 2003
increased $4.0 million, or 6%, to $68.1 million from $64.1 million in 2002. Oil
production decreased by 224 MBbls to 2,645 MBbls, or 8%, for the nine months
ended September 30, 2003, from 2,869 MBbls for the comparable period in 2002.
The oil production decrease includes 107 MBbls as a result of converting
producing wells into injection wells in the Cedar Hills Field. Oil prices,
including hedging, increased $3.39 Bbl to an average of $25.75 Bbl, or 15%,
during the nine months ended September 30, 2003, from $22.36 Bbl, for the
comparable 2002 period. Gas sales revenue increased $19.4 million, or 122%, to
$35.3 million for the nine-month period in 2003 compared to $15.9 million in
2002. Gas production for the period increased 482 MMcf, or 7%, to 7,496 MMcf
from 7014 MMcf in 2002. The increase in gas sales revenues is primarily
attributable to higher gas prices that averaged $4.71 Mcf in the first nine
months of 2003 compared to $2.27 Mcf in the first nine months of 2002, or an
increase of $2.44 per Mcf, or 107%.
CRUDE OIL MARKETING
Since May 2002, we have had third party contracts to purchase and resell
only our own production. We will continue to repurchase our production from the
Rocky Mountain area and resell equivalent barrels in Oklahoma to take advantage
of better pricing and to reduce our credit exposure from sales to our first
purchaser. We present sales and purchases of our production from the Rocky
Mountain area on a gross basis as crude oil marketing income and crude oil
marketing expense, respectively.
During the nine month period ended September 30, 2003, we recognized
revenues of $120.0 million in crude oil marketing revenue compared to $120.5
million for the nine-month period ended September 30, 2002. This $0.5 million
decrease in marketing revenue resulted from a reduction in volumes marketed,
offset by an increase in oil prices.
DERIVATIVE
We have fixed price physical delivery contracts in place to deliver
approximately 93,000 barrels of our forecasted crude oil production per month
through December 2003 at an average price of $24.66 per barrel. These contracts
are considered to be in the normal course of business and have been designated
as such, thus the contracts are not accounted for as derivatives under Statement
of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. Revenues from these firm commitments are recognized as
production occurs.
In addition to the above contracts, we also have a crude oil derivative
contract in place at September 30, 2003, which is being marked to market under
SFAS No. 133 with changes in fair value being recorded in earnings as such
contract does not qualify for special hedge accounting nor does such contract
meet the criteria to be considered in the normal course of business. This
contract provides for a fixed price of $24.25 per barrel on 30,000 barrels of
crude oil per month through December 2003 when market prices exceed $19.00 per
barrel. When market prices fall below $19.00, we receive the market price.
During the nine month period ended September 30, 2003, we recorded a gain of
$0.9 million in change in derivative fair value to reflect the mark-to-market
valuation at September 30, 2003.
GATHERING, MARKETING AND PROCESSING
Our gathering, marketing and processing revenue in the first nine months of
2003 was $50.1 million, an increase of $25.6 million, or 105%, from $24.5
million in the same period in 2002. This increase in revenue for the 2003 period
was attributable to greater volumes processed and higher natural gas and liquids
prices. The acquisition of the Carmen Gathering System, effective August 1,
2003, attributed $3.7 million to revenues from acquisition to September 30,
2003.
OIL AND GAS SERVICE OPERATIONS
Our oil and gas service operations revenue for the nine months ended
September 30, 2003, was $6.6 million, an increase of $2.3 million, or 54%, from
$4.3 million for the nine months ended September 30, 2002. The increase was
primarily due to an increase in reclaimed oil income of $1.9 million due to
higher prices.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses, including taxes, were $35.1 million for the nine
months ended September 30, 2003, an increase of $8.1 million, or 30%, over the
2002 expense of $27.0 million. Production taxes increased $2.0 million due to
higher oil and gas prices in 2003 and energy costs increased $3.8 million due to
higher utility costs in 2003 associated with the Cedar Hills Field. The balance
of the increase was due to higher labor costs of $0.8 million and an increase in
workover and other expenses of $1.6 million.
EXPLORATION EXPENSES
For the nine months ended September 30, 2003, our exploration expenses
increased $2.3 million, or 46%, to $7.5 million from $5.2 million during the
comparable period of 2002. The increase was mainly due to an increase in dry
hole costs of $0.9 million, geological costs of $0.2 million and seismic costs
of $0.9 million.
CRUDE OIL MARKETING
For the nine months ended September 30, 2003, we recognized an expense of
$118.9 million; a decrease of $0.8 million compared to $119.7 million for the
nine months ended September 30, 2002. The decrease was due to less volume
marketed in 2003.
GATHERING, MARKETING, AND PROCESSING
During the nine months ended September 30, 2003, we incurred gathering,
marketing and processing expenses of $46.7 million, representing a $25.5
million, or 120%, increase from $21.2 million incurred in the nine months ended
September 30, 2002, due to greater volumes processed and higher natural gas and
liquids prices on products we purchased for resale. The acquisition of the
Carmen Gathering System, effective August 1, 2003, attributed $3.1 million to
expenses from acquisition to September 30, 2003.
OIL AND GAS SERVICE OPERATIONS
During the nine months ended September 30, 2003, we incurred oil and gas
service operations expense of $6.0 million, a $1.2 million, or 24%, increase
over the $4.8 million for the comparable period in 2002. The increase was due to
the increased cost of purchasing and treating reclaimed oil for resale.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES ("DD&A")
For the nine months ended September 30, 2003, DD&A of our oil and gas
properties increased $4.9 million, or 26%, to $23.4 million from $18.5 million
for the comparable period in 2002. In the first nine months of 2003, our DD&A
expense on oil and gas properties was calculated at $6.00 per BOE compared to
$4.59 per BOE for the first nine months of 2002. The adoption of SFAS No. 143 on
January 1, 2003 has decreased our DD&A $2.3 million offset by an increase in
DD&A rates.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OTHER PROPERTY AND EQUIPMENT
("DD&A")
For the nine months ended September 30, 2003, DD&A of our other property
and equipment increased $0.5 million, or 15%, to $3.6 million from $3.1 million
for the comparable period in 2002.
PROPERTY IMPAIRMENTS
For the nine months ended September 30, 2003, our property impairments
expense increased $2.3 million, or 135%, to $3.9 million from $1.6 million for
the same period in 2002. The increase was due to an increase in reserves for
impairment associated with our undeveloped leasehold.
At September 30, 2003, we had approximately $13.5 million capitalized
related to certain proved undeveloped reserves and approximately $3.3 million
capitalized related to certain proved non-producing reserves (acid fracs)
acquired in 1998. A third party is currently in the process of reviewing the
proved undeveloped reserves. The results of the third party review are
anticipated in the fourth quarter. No impairments were indicated at September
30, 2003; however, it is possible these costs could be impaired at some future
date.
ASSET RETIREMENT ACCRETION
For the nine months ended September 30, 2003, our asset retirement
accretion was $1.1 million due to the adoption of SFAS No. 143 on January 1,
2003.
GENERAL AND ADMINISTRATIVE ("G&A")
For the nine months ended September 30, 2003, our G&A expense was $8.4
million, an increase of $0.5 million, or 6%, from $7.9 million for the nine
months ended September 30, 2002. Our G&A expense per BOE for the nine months of
2003 was $2.15 compared to $1.96 for the nine months of 2002.
INTEREST EXPENSE
For the nine months ended September 30, 2003, our interest expense was
$15.0 million, an increase of $1.6 million or 12%, from $13.4 million in the
nine months ended September 30, 2002. Our interest expense increased in the 2003
period due to higher average debt balances outstanding.
NET INCOME
For the nine months ended September 30, 2003, our net income was $16.3
million, an increase of $11.1 million or 217%, from $5.2 million for the
comparable period in 2002. The adoption of SFAS No. 143 on January 1, 2003
resulted in a cumulative effect adjustment of $4.1 million that increased net
income.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Our net cash provided by operating activities for the nine months ended
September 30, 2003, was $48.8 million, an increase of $23.2 million, or 91%,
from $25.6 million during the comparable 2002 period primarily attributable to
higher oil and gas sales and the change in working capital, namely accounts
payable.. Our cash balance as of September 30, 2003, was $3.0 million, an
increase of $0.5 million, or 20%, from the balance of $2.5 million held at
December 31, 2002.
DEBT
Our long-term debt at December 31, 2002, was $244.7 million and at
September 30, 2003, $286.9 million. During the quarter ended March 31, 2002, we
entered into a Fourth Amended and Restated Credit Agreement in which our
syndicated bank group agreed to provide a $175.0 million senior secured
revolving credit facility with a current borrowing base of $140.0 million. On
June 12, 2003, our borrowing base was increased to $150.0 million. At September
30, 2003, we had outstanding $127.2 million principal amount in senior
subordinated notes, $148.4 million of outstanding debt under our credit
facility, and $14.7 million outstanding in capital lease agreements. On October
22, 2003, we executed the Second Amendment to the Credit Agreement and deleted
CGI as a guarantor under the Credit Agreement. The borrowing base under the
Second Amendment to the Credit Agreement was revised to $145.0 million and the
outstanding balance was reduced by the $17.0 million we received from CGI.
CREDIT FACILITY
Long-term debt outstanding at September 30, 2003, included $148.4 million
of revolving credit debt under our credit facility. The effective rate of
interest under the credit facility was 3.4% at September 30, 2003. The credit
facility, which matures March 28, 2005, charges interest based on a rate per
annum equal to the rate at which eurodollar deposits for one, two, three or nine
months are offered by the lead bank plus an applicable margin ranging from 150
to 250 basis points or the lead bank's reference rate plus an applicable margin
ranging from 25 to 50 basis points. The borrowing base of our credit facility
was revised on October 22, 2003, and currently is $145.0 million. The borrowing
base, which is based on our reserves, is re-determined semi-annually.
Subsequent to September 30, 2003, Continental Gas, Inc. ("CGI"), a wholly
owned subsidiary, closed on a new $35.0 million secured credit facility
consisting of a senior secured term loan facility of up to $25.0 million, and a
senior secured revolving credit facility of up to $10.0 million (individually,
the "Term Loan Facility" and the "Revolving Loan Facility" and, collectively,
the "CGI Credit Facility"). The initial advance under the Term Loan Facility was
$17.0 million, which was used to repay borrowings under our credit facility that
funded the Carmen Gathering System acquisition. No funds were initially advanced
under the Revolving Loan Facility. Advances under either facility can be made,
at the borrower's election, as reference rate loans or LIBOR loans and, with
respect to LIBOR loans, for interest periods of one, two, three or six months.
Interest is payable on reference rate loans monthly and on LIBOR loans at the
end of the applicable interest period. The principal amount of the Term Loan
Facility is to be amortized on a quarterly basis through June 30, 2006, the
final payment being due September 30, 2006. The amount available under the
Revolving Loan Facility may be borrowed, repaid and reborrowed until maturity on
September 30, 2006. Interest on reference rate loans is calculated with
reference to a rate equal to the higher of the reference rate of Union Bank of
California, N.A. or the federal funds rate plus 0.5% (the "Reference Rate").
Interest on LIBOR loans is calculated with reference to the London interbank
offered interest rate (the "LIBOR Rate"). Interest accrues at the Reference Rate
or the LIBOR Rate, as applicable, plus, in either case, the applicable margin.
The applicable margin is based on the then current senior debt to EBITDA ratio.
The CGI Credit Facility contains certain covenants including covenants requiring
that:
o CGI maintain a certain interest charge coverage ratio;
o CGI maintain a certain fixed charge coverage ratio;
o CGI not exceed specified debt senior levels.
In addition, the CGI Credit Agreement limits the ability of CGI to, among other
things:
o Incur indebtedness;
o Engage in certain mergers and consolidations, liquidations and
dissolutions;
o Engage in certain asset sales;
o Make loans to others; and
o Make investments and acquisition, with certain exceptions.
The CGI Credit Agreement requires certain mandatory prepayments of 75% of excess
cash flow.
Our line of credit agreement contains certain negative financial reporting
covenants. We were not in compliance with the covenant that requires that we
maintain a minimum current ratio of 1.0:1. However, on a pro-forma basis givingcovenant
in our credit agreement. In May 2004, we requested and received from the effects of the Second Amended Credit Agreement, we were in compliance. We
receivedbank
group a waiver for non-compliance of both covenants as of March 31, 2004. In the
future, we will seek prior approval on our trading activities from the bank group.required
banks.
CAPITAL EXPENDITURES
Our 20032004 capital expenditures budget, exclusive of acquisitions, has been
revised to $108.8is $82.0
million, of which $42.6$6.7 million is dedicated to our Cedar Hills Field secondary
recovery project. During the ninethree months ended September 30,
2003,March 31, 2004, we incurred
$83.9$20.7 million of capital expenditures, exclusive of
acquisitions, compared to $74.4$27.7 million exclusive of acquisitions, induring the
nine-monththree-month period of 2002. The $83.92003. Of the total $20.7 million of capital expenditures,
includes
$35.6we expended $15.0 in exploration and development, and $3.5 million that wason secondary
recovery operations. We used the remaining $2.2 million for leasing and
additions to our gas gathering systems. The $7.0 million decrease in our capital
expenditures during the developmentfirst quarter of 2004 compared to the Cedar Hills field. The
$9.5 million, or 13% increasefirst quarter of
2003 was the result of our increased drilling activitynear completion of the high-pressure air injection
project in the Cedar Hills Field in our Rocky Mountain and Gulf Coast regions.Region. We expect to fund
the remainder of our 20032004 capital budget through cash flowflows from operations and
borrowings under our credit facility.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report includes "forward-looking statements". All statements other
than statements of historical fact, including, without limitation, statements
contained under "Management's Discussion and Analysis of Financial Condition and
Results of Operations" regarding our financial position, business strategy,
plans and objectives of our management for future operations and industry
conditions, are forward-looking statements. Although we believe that the
expectations reflected in such forward-looking statements are reasonable, we can
give no assurance that such expectations will prove to be correct. Important
factors that could cause actual results to differ materially from our
expectations ("Cautionary Statements") include, without limitation, future
production levels, future prices and demand for oil and gas, results of future
exploration and development activities, future operating and development cost,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 ofor our business operations. DueInformation
regarding our exposures to these market risks is provided below.
COMMODITY PRICE EXPOSURE
Non-trading
We utilize fixed-price contracts, including fixed price basis contracts,
collars and floors to reduce exposure to the volatility ofunfavorable changes in oil and gas
prices that are subject to significant and often volatile fluctuation. Under the
fixed price physical delivery contracts we from timereceive 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 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 time,
have entered into financial contracts to hedgepredict with greater certainty the effective
oil and gas prices as a means of
controlling our exposure to price changes. Most of our financial contracts
settle against either a NYMEX based price or a fixed price.
DERIVATIVES
The risk management process we established is designed to measure both
quantitative and qualitative risks in our businesses. We are exposed to market
risk, including changes in interest rates and certain commodity prices. To
manage the volatility relating to these exposures, periodically we enter into
various derivative transactions pursuant to our policies on hedging practices.
Derivative positions are monitored using techniques such as mark-to-market
valuation and value-at-risk and sensitivity analysis.
We had a derivative contract in place at September 30, 2003, which is being
marked to market under SFAS No. 133 with changes in fair value being recorded in
earnings as such contract does not qualify for special hedge accounting nor does
such contract meet the criteria to be considered in the normal course of
business. Such contract providesreceived for a fixed price of $24.25 per barrel on
30,000 barrels of crude oil per month through December 2003hedged production and benefit operating
cash flows and earnings when market prices exceed $19.00 per barrel. However, ifare less than the average NYMEX spot crude oil price is
$19.00 per barrel or less, no payment is required of the counterparty. If NYMEX
spot crude oilfixed prices
during the month average more than $24.25 per barrel, we
pay the excess to the counterparty. As of September 30, 2003, we have recorded a
net unrealized loss of $0.5 million.
COMMODITY PRICE EXPOSURE
The market risk inherent in our market risk sensitive instruments and
positions is the potential loss in value arising from adverse changes in our
commodity prices. Our management believes that we are well positioned with our
mix of oil and gas reserves to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to impact the
domestic oil and gas industry. Due to the volatility of oil and gas prices, we,
from time to time, have used derivative hedging and may do soprovided in the future as a
means of controlling our exposure to price changes. Mostcontracts. However, we will not benefit from market prices that
are higher than the fixed, or ceiling prices in the contracts for hedged
production.
The terms of our purchases are
madecredit facility require that at either a NYMEX based price or a fixed price. Forward sales contracts
that provide for the physical delivery of our production are deemed to be normal
course of business sales and are not accounted for as derivatives. As of
September 30, 2003, we had the following fixed sales contracts in order to
mitigate our price risk exposure on our production:
Time Period Barrels per Month Price per Barrel
----------- ----------------- ----------------
10/03 to 12/03 32,375 to 33,375 $25.08
10/03 to 12/03 30,000 $24.85
10/03 to 12/03 30,000 $24.01
In April 2003, we repurchased two fixed sales contracts from September 2003
through December 2003. The fixed sales contracts were each for 30,000 barrels a
month at $25.08/Bbl and $24.01/Bbl. The cost of this transaction will be
recorded monthly for seven months at approximately $78,000/month for a total of
approximately $546,000.
The second amendment to the revolving credit agreement requires us to haveleast 50% of our
forecasted crude oil production from our exploration and production segment be
hedged on a rolling six-month term. In October,At March 31, 2004, we have
established costlesshad collars and/or
floors in place covering 30,000approximately 1.4 million barrels of crude oil
representing approximately 66% of our forecasted production for Octoberthrough September
30, 2004. At March 31, 2004, we had a mark-to-market unrealized loss of
approximately $996,600 on our collar and November 2003, 85,000 barrelsfloor contracts. As such contracts have
been designated and qualify as cash flow hedges, the loss has been recorded as a
component of production for December 2003 and 145,000
barrels of production from January 2004 thruAccumulated Other Comprehensive Income at March 200431, 2004. The
ineffectiveness associated with a floor price of
$22.00 and an average ceiling price of $35.00.
In order to mitigate price risk exposure on production,our cash flow hedging strategy was immaterial.
Additionally, CGI has executed fixed price forward sales contracts in place that will result in the physical delivery of productionrelated
to our gas gathering, marketing and qualifyprocessing segment on approximately 50,000
MMBtu per month through December 2007. Such contracts have been designated as
being in the normal course of business sales under SFAS No. 133 and are therefore not accounted formarked to market as
derivatives. As of September 30, 2003, CGI has 50,000 MMBTU per
month hedged from January 2004 to December 2007 at an averageThese volumes under these fixed price of $4.579
per MMBTU. These hedges account forforward sales contracts
represent approximately 9% of the total delivery point volumes and 4% of the overall
company throughput.throughput volumes of the gas gathering, marketing and processing segment.
The following table summarizes our non-trading contracts in place at March
31, 2004:
2004 2005 2006 2007
----------- ----------- ----------- -----------
Natural Gas Physical Delivery Contracts:
Contract Volumes (MMBtu) 450,000 600,000 600,000 600,000
Weighted Average Fixed Price per MMBtu $ 4.83 $ 4.53 $ 4.47 $ 4.49
Crude Oil Collars and Floors for 2004: Contract Weighted-average
Volumes (Bbls) Fixed Price per Bbl
------------- -------------------
Floor 926,000 $ 22.00
Floor 200,000 $ 24.00
Floor 230,000 $ 24.50
-------------
1,356,000
Ceiling 220,000 $ 35.00
Ceiling 515,000 $ 36.00
Ceiling 230,000 $ 45.00
-------------
965,000
The following table represents our fixed basis contracts in place at March
31, 2004. The price shown below represents the price we would have received
based on the current forward crude oil price for the applicable month combined
with the fixed basis differential contained in the contract.
Contract Month Contract Volumes Price
- ----------------- ----------------- ---------
May 2004 184,000 $ 35.73
June 2004 90,000 $ 35.27
July 2004 62,000 $ 35.03
Trading
In the first quarter 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 March 31, 2004, we had the following open
trading derivative contracts:
Weighted
Contract Contract Average Barrels Unrealized
Type Month Fixed Price Buy (Sell) Gain (Loss)
- ----------- -------------- ----------------- ----------- ---------------
Crude Oil April 2004 $ 34.84 (42,800) $ (478,152)
Crude Oil May 2004 35.56 (18,300) (186,277)
Crude Oil December 2004 31.41 30,000 268,200
----------- ---------------
(31,100) $ (396,229)
=========== ===============
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.
2003March 31,
2004
(Dollars in thousands) 2003 2004 2005 2006 2007 Thereafter Total Fair Value
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Fixed rate debt:
Senior subordinated notes
Principal amount $ - $ - $ - $ - $127,150 $127,150 $127,607$ 127,150 $ 127,150 $ 128,422
Weighted-average
interest rate 10.25% 10.25% 10.25% 10.25% 10.25%
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Credit facility
Principal amount $ 1,821 $ 2,430 $ 12,141 $ 140,400 $ - $ 2,429 $133,829156,792 $ 12,142 $ - $148,400 $148,400156,792
Weighted-average
interest rate 3.48% 3.45% 3.45% 3.45% 3.45%3.80% 3.80% 3.80% 3.80% 3.80%
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Capital lease agreement
Principal amount $ 8342,502 $ 3,336 $ 3,336 $ 3,3363,333 $ 3,819486 $ 14,66112,993 $ 14,66112,993
Weighted-average
interest rate 3.70% 3.70% 3.70% 3.70% 3.70%3.80% 3.80% 3.80% 3.80% 3.80%
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Variable rate debt:
Ford Credit agreement
Principal amount $ 8 $ 13 $ 11 $ 8 $ - $ 40 $ 40
Weighted-average
interest rate 5.50% 5.50% 5.50% 5.50% 5.50%
- ----------------------------------------------------------------------------------------------------------------
ITEM 4. CONTROLS AND PROCEDURES
The Securities and Exchange Commission'sCommission rules require that registrants to
maintain disclosure controls and procedures to provide reasonable assurance that
a registrant is able to record, process, summarize and report the information
required in the registrant's quarterly and annual reports under the Securities
Exchange Act of 1934. While we believe that our existing disclosure controls and
procedures have been effective to accomplish these objectives, we intend to
continue to examine, refine and formalize our disclosure controls and procedures
and to maintain ongoing developments in this area.
OurAs 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) as of the end of the period covered
by this report, and concluded that our disclosure controls and procedures are
effective.
There have been no significant changes in our internal controls or in other
factors that could significantly affect these controls, since the date the
controls were evaluated.
PART II. Other Information
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are a party to litigation or other legal proceedings
that we consider to be a part of the ordinary course of our business. We are not
involved in any legal proceedings nor are we a party to any pending or
threatened claims that could reasonably be expected to have a material adverse
effect on our financial condition or results of operations.
ITEM 2. CHANGES IN SECURITIES, AND USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a.)(a) EXHIBITS:
EXHIBIT
NO. DESCRIPTION 2.1 Agreement and Plan of Recapitalization of Continental Resources, Inc.
dated October 1, 2000 [2.1](4)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)
3.3 Certificate of Incorporation of Continental Gas, Inc. [3.3](1)
3.4 Bylaws of Continental Gas, Inc., as amended and restated [3.4](1)
3.5 Certificate of Incorporation of Continental Crude Co. [3.5](1)
3.6 Bylaws of Continental Crude Co. [3.6](1)
4.1 Restated Credit Agreement dated April 21, 2000, among Continental
Resources, Inc. and Continental Gas Inc., as Borrowers and MidFirst Bank
as Agent (the "Credit Agreement") [4.4](3)
4.1.1 Form of Consolidated Revolving Note under the Credit Agreement [4.4](3)
4.1.2 Second Amended and Restated Credit Agreement among Continental Resources,
Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc.,
as Borrowers, and MidFirst Bank, dated July 9, 2001 [10.1](5)
4.1.3 Third Amended and Restated Credit Agreement among Continental Resources,
Inc., Continental Gas, Inc. and Continental Resources of Illinois, Inc.,
as Borrowers, and MidFirst Bank, dated January 17, 2002 [4.13](7)
4.1.4 Fourth Amended and Restated Credit Agreement dated March 28, 2002,
among the Registrant, Union Bank of California, N.A., Guaranty Bank,
FSB and Fortis Capital Corp. [10.1](8)
4.1.5(5)
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](10)
4.1.6(6) 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](11)(7)
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.
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 TrusteeTrustee. [4.2](1)
4.3 Term and Revolving Credit Agreement by and among Continental Gas, Inc.
and Union Bank of California, N.A., as administrative agent for the
lenders, dated October 22, 2003 (11)
10.1 Unlimited Guaranty Agreement dated March 28, 2002 by Continental
Resources, Inc., Continental Gas, Inc. and Continental Resources of
Illinois, Inc. to Union Bank of California, N.A., Guaranty Bank, FSB and
Fortis Capital Corp.2002. [10.2](8)(5)
10.2 Security Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as AgentAgent. [10.3](8)(5)
10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as AgentAgent. [10.4](8)(5)
10.4 Conveyance Agreement of Worland Area Properties from Harold G. Hamm,
Trustee of the Harold G. Hamm Revocable Intervivos Trust dated April 23,
1984, to Continental Resources, Inc. [10.4](2)
10.5 Purchase Agreement signed January 2000, effective October 1, 1999, by and
between Patrick Energy Corporation as Buyer and Continental Resources,
Inc. as Seller [10.5](2)
10.6++ Continental Resources, Inc. 2000 Stock Option PlanPlan. [10.6](4)
10.7+(2)
10.5 + Form of Incentive Stock Option AgreementAgreement. [10.7](4)
10.8+(2)
10.6 + Form of Non-Qualified Stock Option AgreementAgreement. [10.8](4)
10.9 Purchase and Sales Agreement between Farrar Oil Company and Har-Ken Oil
Company, as Sellers, and Continental Resources of Illinois, Inc. as
Purchaser, dated May 14, 2001 [2.1](5)
10.10(2)
10.7 Collateral Assignment of Contracts dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as AgentAgent. [10.5](8)(5)
12.1 * Statement re computation of ratio of debt to Adjusted EBITDA [12.1](9)EBITDA.
12.2 * Statement re computation of ratio of earning to fixed charges [12.2](9)
12.3 Statement re computation of ratio of adjusted EBITDA to interest expense
[12.3](9)
12.0 Subsidiaries of Registrant [21](6)
31.1*charges.
31.1 * Certification pursuant to section 302 of the Sarbanes-Oxley Act of
2002 - Chief Executive Officer
31.2*31.2 * Certification pursuant to section 302 of the Sarbanes-Oxley Act of
2002 - Chief Financial Officer
99.1 Letter to the Securities and Exchange Commission dated March 28, 2002,
regarding the audit of the Registrant's financial statements by Arthur
Andersen LLP [99.1](7)
- -----------------------------------------------------
* Filed herewith
+ Represents management compensatory plans or agreements
(1) Filed as an exhibit to the Company's Registration Statement on Form S-4, as
amended (No. 333-61547), which was filed with the Securities and Exchange
Commission. The exhibit number is indicated in brackets and is incorporated
herein by reference.
(2) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1999.2000. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(3) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended March 31, 2000.June 30, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(4) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2000.2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(5) Filed as an exhibit to current report on Form 8-K dated July 18, 2001.April 11, 2002. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(6) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended June 30, 2001.2003. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(7) Filed as an exhibit to the Company's Annual Reportcurrent report on Form 10-K for the
fiscal year ended December 31, 2001.8-K dated October 22, 2003.
The exhibit number is indicated in brackets and is incorporated herein by
reference.
(8) Filed as an exhibit to reportthe Company's Annual Report on Form 8-K dated April 11, 2002.10-K for the
fiscal year ended December 31, 2003. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(9) Filed as an exhibit to the Company's AnnualQuarterly Report on Form 10-K10-Q for the
fiscal yearquarter ended DecemberMarch 31, 2002.2004. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(10) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
the fiscal quarter ended June 30, 2003. The exhibit number is indicated
in brackets and is incorporated herein by reference.
(11) Filed as an exhibit to report on Form 8-K dated October 31, 2003. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(b.)(b) REPORTS ON FORM 8-K:
On October 31, 2003, the Registrant filed a current report on Form 8-K
describing the Second Amended and Restated Credit Agreement with Union Bank of
California, N.A., Guaranty Bank, FSB and Fortis Capital Corp. and Continental
Gas Inc.'s new Term and Revolving Credit Agreement with Union Bank of
California, N.A., Fortis Capital Corp., and Wells Fargo Bank of Texas, N.A.
None.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Companyregistrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Continental Resources, Inc.
Date: NovemberMay 13, 20032004 By: /s/ RogerROGER V. ClementCLEMENT
Roger V. Clement
Senior Vice President and
Chief Financial Officer
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
--- ----------- ----------------
2.1 Agreement and Plan of Recapitalization Incorporated herein by reference
of Continental Resources, Inc. dated
October 1, 2000
3.1 Amended and Restated Certificate of Incorporated herein by reference
Incorporation of Continental Resources,
Inc.
3.2 Amended and Restated Bylaws of Incorporated herein by reference
Continental Resources, Inc.
3.3 Certificate of Incorporation of Incorporated herein by reference
Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as Incorporated herein by reference
amended and restated
3.5 Certificate of Incorporation of Incorporated herein by reference
Continental Crude Co.
3.6 Bylaws of Continental Crude Co. Incorporated herein by reference
4.1 Restated Credit Agreement dated April Incorporated herein by reference
21, 2000, among Continental Resources,
Inc. and Continental Gas Inc., as
Borrowers and MidFirst Bank as Agent
(the "Credit Agreement")
4.1.1 Form of Consolidated Revolving Note Incorporated herein by reference
under the Credit Agreement
4.1.2 Second Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois,
Inc., as Borrowers, and MidFirst Bank,
dated July 9, 2001EXHIBIT INDEX
Exhibit
No. Description Method of Filing
- ------- ----------- ----------------
3.1 Amended and Restated Certificate of Incorporated by reference
Incorporation of Continental
Resources, Inc.
3.2 Amended and Restated Bylaws of Incorporated by reference
Continental Resources, Inc.
4.1 Fourth Amended and Restated Credit Incorporated 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 Incorporated by reference
Credit Agreement dated June 12,
2003, among the Registrant, Union
Bank of California, N.A., Guaranty
Bank, FSB and Fortis Capital Corp.
[10.1](6)
4.1.2 Second Amendment to the Revolving Incorporated 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 Amended and Restated Credit Incorporated herein by reference
Agreement among Continental Resources,
Inc., Continental Gas, Inc. and
Continental Resources of Illinois,
Inc., as Borrowers, and MidFirst Bank,
dated January 17, 2002
4.1.4 Fourth Amended and Restated Credit Incorporated herein by reference
Agreement dated March 28, 2002, among
the Registrant, Union Bank of
California, N.A., Guaranty Bank, FSB
and Fortis Capital Corp.
4.1.5 First Amendment to the Revolving Credit Incorporated herein by reference
Agreement dated June 12, 2003, among
the Registrant, Union Bank of
California, N.A., Guaranty Bank, FSB
and Fortis Capital Corp.
4.1.6 Second Amendment to the Revolving Incorporated herein by reference
Credit Agreement dated October 22,
2003, among the Registrant, Union Bank
of California, N.A., Guaranty Bank, FSB
and Fortis Capital Corp.
4.2 Indenture dated as of July 24, 1998, Incorporated herein by reference
between Continental Resources, Inc. as
Issuer, the Subsidiary Guarantors named
therein and the United States Trust
Company of New York, as Trustee
4.3 Term and Revolving Credit Agreement by Incorporated herein by reference
and among Continental Gas, Inc. and
Union Bank of California, N.A., as
administrative agent for the lenders,
dated October 22, 2003
10.1 Unlimited Guaranty Agreement dated Incorporated herein by reference
March 28, 2002 by Continental
Resources, Inc., Continental Gas, Inc.
and Continental Resources of Illinois,
Inc. to Union Bank of California, N.A.,
Guaranty Bank, FSB and Fortis Capital
Corp.
10.2 Security Agreement dated March 28, Incorporated herein by reference
2002, between Registrant and Guaranty
Bank, FSB, as Agent
10.3 Stock Pledge Agreement dated March 28, Incorporated herein by reference
2002, between Registrant and Guaranty
Bank, FSB, as Agent
10.4 Conveyance Agreement of Worland Area Incorporated herein by reference
Properties from Harold G. Hamm, Trustee
of the Harold G. Hamm Revocable
Intervivos Trust dated April 23, 1984,
to Continental Resources, Inc.
10.5 Purchase Agreement signed January 2000, Incorporated herein by reference
effective October 1, 1999, by and
between Patrick Energy Corporation as
Buyer and Continental Resources, Inc.
as Seller
10.6 Continental Resources, Inc. 2000 Stock Incorporated herein by reference
Option Plan
10.7 Form of Incentive Stock Option Incorporated herein by reference
Agreement
10.8 Form of Non-Qualified Stock Option Incorporated herein by reference
Agreement
10.9 Purchase and Sales Agreement between Incorporated herein by reference
Farrar Oil Company and Har-Ken Oil
Company, as Sellers, and Continental
Resources of Illinois, Inc. as
Purchaser, dated May 14, 2001
10.10 Collateral Assignment of Contracts Incorporated herein by reference
dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as
Agent
12.1 Statement re computation of ratio of Incorporated herein by reference
debt to Adjusted EBITDA
12.2 Statement re computation of ratio of Incorporated herein by reference
earning to fixed charges
12.3 Statement re computation of ratio of Incorporated herein by reference
adjusted EBITDA to interest expense
12.0 Subsidiaries of Registrant Incorporated herein by reference
31.1 Certification pursuant to section 302 Filed herewith electronically
of the Sarbanes-Oxley Act of 2002 -
Chief Executive Officer
31.2 Certification pursuant to section 302 Filed herewith electronically
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.
4.2 Indenture dated as of July 24, 1998, Incorporated 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 by reference
March 28, 2002.
10.2 Security Agreement dated March 28, Incorporated by reference
2002, between Registrant and
Guaranty Bank, FSB, as Agent.
10.3 Stock Pledge Agreement dated March Incorporated by reference
28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent.
10.4 Continental Resources, Inc. 2000 Incorporated by reference
Stock Option Plan.
10.5 Form of Incentive Stock Option Incorporated by reference
Agreement.
10.6 Form of Non-Qualified Stock Option Incorporated by reference
Agreement.
10.7 Collateral Assignment of Contracts Incorporated by reference
dated March 28, 2002, between
Registrant and Guaranty Bank, FSB,
as Agent.
12.1 Statement re computation of ratio Filed herewith electronically
of debt to Adjusted EBITDA.
12.2 Statement re computation of ratio Filed herewith electronically
of earning to fixed charges.
31.1 Certification pursuant to section Filed herewith electronically
302 of the Sarbanes-Oxley Act of
2002 - Chief Executive Officer
31.2 Certification pursuant to section Filed herewith electronically
302 of the Sarbanes-Oxley Act of
2002 - Chief Financial Officer
99.1 Letter to the Securities and Exchange Incorporated herein by reference
Commission dated March 28, 2002,
regarding the audit of the Registrant's
financial statements by Arthur Andersen
LLP