United States
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________to _________
Commission File Number: 333-61547
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Oklahoma 73-0767549
------------------------------ -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
302 N. Independence, Suite 300, Enid, Oklahoma 73701
------------------------------------------------ ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (580) 233-8955
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ ] No [X]
The Registrant is not subject to the filing requirements of Section 13 and 15(d)
of the Securities Exchange Act of 1934, but files reports required by those
sections pursuant to contractual obligation requirements.
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act.) Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding as of May 14, 2004
---------------------------- ------------------------------
Common Stock, $.01 par value 14,368,919 shares
TABLE OF CONTENTS
PART I. Financial Information
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets................................ 4
Condensed Consolidated Income Statements............................. 5
Condensed Consolidated Statements of Cash Flows...................... 6
Notes to Condensed Consolidated Financial Statements................. 7
ITEM 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations.....................12
ITEM 3 Quantitative and Qualitative Disclosures About Market Risk.........19
ITEM 4. Controls and Procedures...........................................20
PART II. Other Information
ITEM 1. Legal Proceedings.................................................21
ITEM 2. Changes in Securities, Use of Proceeds and
Issuer Purchases of Equity Securities.............................21
ITEM 3. Defaults Upon Senior Securities...................................21
ITEM 4. Submission of Matters to a Vote of Security Holders...............21
ITEM 5. Other Information.................................................21
ITEM 6. Exhibits and Reports on Form 8-K..................................21
Signatures................................................................23
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)
December 31, March 31,
------------------ ------------------
Assets 2003 2004
------------------ ------------------
Current assets: (Unaudited)
Cash and cash equivalents $ 2,277 $ 1,968
Accounts receivable:
Oil and gas sales 19,035 18,964
Joint interest and other, net 13,577 11,196
Inventories 5,465 5,168
Prepaid expenses 336 144
Fair value of derivative contracts 151 40
------------------ ------------------
Total current assets 40,841 37,480
Property and equipment, at cost:
Oil and gas properties, based on
successful efforts accounting 601,325 616,546
Gas gathering and processing facilities 49,600 50,882
Service properties, equipment and other 19,515 19,629
------------------ ------------------
Total property and equipment 670,440 687,057
Less accumulated depreciation,
depletion and amortization 231,008 242,076
------------------ ------------------
Net property and equipment 439,432 444,981
Other assets:
Debt issuance costs, net 4,707 4,344
Other assets 8 8
------------------ ------------------
Total other assets 4,715 4,352
------------------ ------------------
Total assets $ 484,988 $ 486,813
================== ==================
Liabilities and stockholders' equity
Current liabilities:
Accounts payable $ 27,950 $ 26,614
Current portion of long-term debt 5,776 5,776
Revenues and royalties payable 8,250 7,935
Accrued liabilities:
Interest 6,312 3,054
Other 7,212 6,330
Fair value of derivative contracts 640 1,433
------------------ ------------------
Total current liabilities 56,140 51,142
Long-term debt, net of current portion 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 92,190 93,181
Accumulated other comprehensive income (489) (997)
------------------ ------------------
Total stockholders' equity 116,932 117,415
------------------ ------------------
Total liabilities and stockholders' equity $ 484,988 $ 486,813
================== ==================
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS
(Unaudited)
(Dollars in thousands, except share data)
Three Months Ended March 31,
-------------------------------------------
2003 2004
--------------------- --------------------
Revenues: (restated)
Oil and gas sales $ 35,722 $ 36,123
Crude oil marketing and trading 40,595 55,705
Change in derivative fair value 303 (396)
Gas gathering, marketing and processing 9,725 15,865
Oil and gas service operations 1,882 2,114
--------------------- --------------------
Total revenues 88,227 109,411
Operating costs and expenses:
Production 8,631 10,548
Production taxes 2,674 2,582
Exploration 1,502 2,092
Crude oil marketing and trading 40,484 55,863
Gas gathering, marketing and processing 8,828 13,808
Oil and gas service operations 1,960 1,946
Depreciation, depletion and amortization of oil and gas properties 8,302 10,467
Depreciation and amortization of other property and equipment 1,148 1,165
Property impairments 1,276 1,897
Asset retirement obligation accretion 352 277
General and administrative 2,838 2,500
--------------------- --------------------
Total operating costs and expenses 77,995 103,145
Operating income 10,232 6,266
Other income (expenses):
Interest income 32 27
Interest expense (4,951) (5,289)
Other income, net 37 23
Loss on sale of assets (8) (35)
--------------------- --------------------
Total other income (expense) (4,890) (5,274)
--------------------- --------------------
Income before change in accounting principle 5,342 992
--------------------- --------------------
Cumulative effect of change in accounting principle 2,162 -
--------------------- --------------------
Net income $ 7,504 $ 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 $ 0.52 $ 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 $ 0.52 $ 0.07
===================== ====================
The accompanying notes are an integral part of these condensed consolidated
financial statements.
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Dollars in thousands)
Three Months Ended March 31,
-------------------------------------
2003 2004
----------------- -----------------
Cash 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 amortization 9,450 11,744
Accretion of asset retirement obligation 352 277
Impairment of properties 1,276 1,897
Change in derivative fair value (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 facilities and service
properties, equipment and other (1,564) (1,488)
Purchase of oil and gas properties (82) (14)
Proceeds from sale of assets 56 178
----------------- -----------------
Net cash used in investing activities (27,682) (20,512)
Cash flows from financing activities:
Proceeds from line of credit and other 18,500 7,500
Repayment of debt (600) (1,444)
Debt issuance costs - (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 $ 6,165 $ 1,968
================= =================
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., or CRI or the Company, the
accompanying unaudited condensed consolidated financial statements contain all
adjustments necessary to present fairly the Company's financial position as of
March 31, 2004, the results of operations and cash flows for the three months
ended March 31, 2003 and 2004. Such adjustments are of a normal recurring
nature. The unaudited condensed consolidated financial statements for the
interim periods presented do not contain all information required by accounting
principles generally accepted in the United States. The results of operations
for any interim period are not necessarily indicative of the results of
operations for the entire year. These condensed consolidated financial
statements should be read in conjunction with the consolidated financial
statements and notes thereto included in the Company's annual report on form
10-K for the year ended December 31, 2003.
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 its assumptions
used in its initial SFAS No. 143 estimates to better reflect its future plugging
costs and future salvage values. These changes resulted in a decrease in the
cumulative effect adjustment from the $4.1 million originally reported during
the quarter ended March 31, 2003, to $2.2 million. The following table details
the amounts originally reported for the quarter ended March 31, 2003, compared
to the current 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 Internal Revenue
Code. As a result, income taxes, if any, will be payable by the stockholders of
the Company. The Company operates principally in the following two segments:
1. Exploration and Production - 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 operator in the majority
of these wells. CRI and CRII'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 Company 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 reserves meet the definition of
proved reserves under 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. Gas Gathering, Marketing and Processing - Another wholly-owned
subsidiary of CRI is Continental Gas, Inc., or CGI, which is engaged principally
in natural gas marketing, gathering and processing activities and currently
operates seven gas gathering systems and three gas processing plants in its
operating areas. In addition, CGI participates with CRI in exploration,
development and production of certain oil and natural gas properties.
2. LONG-TERM DEBT:
Long-term debt as of December 31, 2003, and March 31, 2004, consisted of
the following:
December 31, March 31,
(Dollars in thousands) 2003 2004
-------------- --------------
10.25% Senior Subordinated Notes due August 1, 2008 $ 127,150 $ 127,150
Credit Facility due March 31, 2007 132,900 140,400
Credit Facility due September 30, 2006 17,000 16,392
Capital Lease Agreement 13,827 12,993
Ford Credit 43 40
-------------- ---------------
Outstanding Debt 290,920 296,975
Less Current Portion 5,776 5,776
-------------- ---------------
Total Long-Term Debt $ 285,144 $ 291,199
============== ===============
On March 31, 2002, the Company entered into a Fourth Amended and Restated
Credit Agreement providing for a $175.0 million senior secured revolving credit
facility with a borrowing base of $150.0 million. Borrowings under the credit
facility are secured by liens on all oil and gas properties and associated
assets of the Company. Borrowings under the credit facility bear interest,
payable quarterly, at (a) a rate per annum equal to the rate at which eurodollar
deposits for one, two, three or six months are offered by the lead bank plus a
margin ranging from 150 to 250 basis points, or (b) at the lead bank's reference
rate plus an applicable margin ranging from 25 to 50 basis points. 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 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 14, 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, CGI entered into a new $35.0 million secured credit
facility consisting of a senior secured term loan facility of up to $25.0
million, and a senior revolving credit facility of up to $10.0 million. The
initial advance under the term loan facility was $17.0 million, which CGI paid
to CRI who used the payment to reduce the outstanding balance on CRI's credit
facility. No funds were initially advanced under the revolving loan facility.
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 at 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 rate. Interest accrues at the
reference rate or the LIBOR rate, as applicable, plus the applicable margin. The
margin is based on the ratio of senior debt to 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. At March 31, 2004 the outstanding balance on CGI's credit
facility was $16.4 million.
Our credit agreement contains certain financial and other covenants. At
March 31, 2004, we were not in compliance with two covenants, one that requires
us 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, we were in compliance with the current ratio covenant
in our credit agreement. In May 2004, we requested and received from the bank
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 required
banks.
CAPITAL EXPENDITURES
Our 2004 capital expenditures budget, exclusive of acquisitions, is $82.0
million, of which $6.7 million is dedicated to our Cedar Hills Field secondary
recovery project. During the three months ended March 31, 2004, we incurred
$20.7 million of capital expenditures, compared to $27.7 million during the
three-month period of 2003. Of the total $20.7 million of capital expenditures,
we expended $15.0 in exploration and development, and $3.5 million on 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 first quarter of 2004 compared to the first quarter of
2003 was the result of our near completion of the high-pressure air injection
project in the Cedar Hills Field in our Rocky Mountain Region. We expect to fund
the remainder of our 2004 capital budget through cash flows from operations and
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 costs,
the effect of existing and future laws and governmental regulations (including
those pertaining to the environment) and the political and economic climate of
the United States as discussed in this quarterly report and the other documents
we previously filed with the Securities and Exchange Commission. All subsequent
written and oral forward-looking statements attributable to us, or persons
acting on our behalf, are expressly qualified in their entirety by the
Cautionary Statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
GENERAL
We are exposed to market risks, including commodity price risk and interest
rate risk, in the normal course or our business operations. Information
regarding our exposures to these market risks is provided below.
COMMODITY PRICE EXPOSURE
Non-trading
We utilize fixed-price contracts, including fixed price basis contracts,
collars and floors to reduce exposure to the unfavorable changes in oil and gas
prices that are subject to significant and often volatile fluctuation. Under the
fixed price physical delivery contracts we receive the fixed price stated in the
contract. Under the fixed price basis contracts, the price we receive is
determined based on a published regional index price plus a fixed basis. Under
the collars and floors, if the market price of crude oil exceeds the ceiling
strike price or falls below the floor strike price, then we receive the fixed
price ceiling or floor. If the market price is between the floor strike price
and the ceiling strike price, we receive market price.
These contracts allow us to predict with greater certainty the effective
oil and gas prices to be received for hedged production and benefit operating
cash flows and earnings when market prices are less than the fixed prices
provided in the contracts. However, we will not benefit from market prices that
are higher than the fixed, or ceiling prices in the contracts for hedged
production.
The terms of our credit facility require that at least 50% of our
forecasted crude oil production from our exploration and production segment be
hedged on a rolling six-month term. At March 31, 2004, we had collars and/or
floors in place covering approximately 1.4 million barrels of crude oil
representing approximately 66% of our forecasted production through September
30, 2004. At March 31, 2004, we had a mark-to-market unrealized loss of
approximately $996,600 on our collar and floor contracts. As such contracts have
been designated and qualify as cash flow hedges, the loss has been recorded as a
component of Accumulated Other Comprehensive Income at March 31, 2004. The
ineffectiveness associated with our cash flow hedging strategy was immaterial.
Additionally, CGI has executed fixed price forward sales contracts related
to our gas gathering, marketing and processing segment on approximately 50,000
MMBtu per month through December 2007. Such contracts have been designated as
normal sales under SFAS No. 133 and are therefore not marked to market as
derivatives. These volumes under these fixed price forward sales contracts
represent approximately 9% of total delivery point volumes and 4% of the overall
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.
March 31,
2004
(Dollars in thousands) 2004 2005 2006 2007 Thereafter Total Fair Value
----------------------------------------------------------------------------------------------------------------
Fixed rate debt:
Senior subordinated notes
Principal amount $ - $ - $ - $ - $ 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 $ - $ 156,792 $ 156,792
Weighted-average
interest rate 3.80% 3.80% 3.80% 3.80% 3.80%
----------------------------------------------------------------------------------------------------------------
Variable rate debt:
Capital lease agreement
Principal amount $ 2,502 $ 3,336 $ 3,336 $ 3,333 $ 486 $ 12,993 $ 12,993
Weighted-average
interest rate 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 rules require registrants to
maintain disclosure controls and procedures to provide reasonable assurance that
a registrant is able to record, process, summarize and report the information
required in the registrant's quarterly and annual reports under the Securities
Exchange Act of 1934. While we believe that our existing disclosure controls and
procedures have been effective to accomplish these objectives, we intend to
continue to examine, refine and formalize our disclosure controls and procedures
and to maintain ongoing developments in this area.
As of the end of the period covered by this report, our principal executive
officer and principal financial officer have evaluated our disclosure controls
and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act
of 1934) and concluded that our disclosure controls and procedures are
effective.
There have been no significant changes in our internal controls or in other
factors that could significantly affect these controls, since the date the
controls were evaluated.
PART II. Other Information
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are a party to litigation or other legal proceedings
that we consider to be a part of the ordinary course of our business. We are not
involved in any legal proceedings nor are we a party to any pending or
threatened claims that could reasonably be expected to have a material adverse
effect on our financial condition or results of operations.
ITEM 2. CHANGES IN SECURITIES, 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) EXHIBITS:
EXHIBIT
NO. DESCRIPTION AND METHOD OF FILING:
--- ---------------------------------
3.1 Amended and Restated Certificate of Incorporation of Continental
Resources, Inc. [3.1](1)
3.2 Amended and Restated Bylaws of Continental Resources, Inc. [3.2](1)
4.1 Fourth Amended and Restated Credit Agreement dated March 28, 2002,
among the Registrant, Union Bank of California, N.A., Guaranty Bank,
FSB and Fortis Capital Corp. [10.1](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](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](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 Trustee. [4.2](1)
10.1 Unlimited Guaranty Agreement dated March 28, 2002. [10.2](5)
10.2 Security Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent. [10.3](5)
10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent. [10.4](5)
10.4 + Continental Resources, Inc. 2000 Stock Option Plan. [10.6](2)
10.5 + Form of Incentive Stock Option Agreement. [10.7](2)
10.6 + Form of Non-Qualified Stock Option Agreement. [10.8](2)
10.7 Collateral Assignment of Contracts dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as Agent. [10.5](5)
12.1 * Statement re computation of ratio of debt to Adjusted EBITDA.
12.2 * Statement re computation of ratio of earning to fixed charges.
31.1 * Certification pursuant to section 302 of the Sarbanes-Oxley Act of
2002 - Chief Executive Officer
31.2 * Certification pursuant to section 302 of the Sarbanes-Oxley Act of
2002 - Chief Financial Officer
-------------------------
* Filed herewith
+ Represents management compensatory plans or agreements
(1) Filed as an exhibit to the Company's Registration Statement on Form S-4, as
amended (No. 333-61547), which was filed with the Securities and Exchange
Commission. The exhibit number is indicated in brackets and is incorporated
herein by reference.
(2) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2000. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(3) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended June 30, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(4) Filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(5) Filed as an exhibit to current report on Form 8-K dated April 11, 2002. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(6) 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.
(7) Filed as an exhibit to current report on Form 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 the Company's Annual Report on Form 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 Quarterly Report on Form 10-Q for the
fiscal quarter ended March 31, 2004. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(b) REPORTS ON FORM 8-K:
None.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Continental Resources, Inc.
Date: May 13, 2004 By: ROGER V. CLEMENT
Roger V. Clement
Senior Vice President and
Chief Financial Officer
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
------- ----------- ----------------
3.1 Amended and Restated Certificate of Incorporated 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 Amendment to the Revolving 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