United States
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________to _________
Commission File Number: 333-61547
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Oklahoma 73-0767549
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
302 N. Independence, Suite 1500, Enid, Oklahoma 73701
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (580) 233-8955
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ ] No[X]
The Registrant is not subject to the filing requirements of Section 13 and 15(d)
of the Securities Exchange Act of 1934, but files reports required by those
sections pursuant to contractual obligation requirements.
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act.) Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding as of August 13, 2004
Common Stock, $.01 par value 14,368,919 shares
TABLE OF CONTENTS
PART I. Financial Information
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets............................. 4
Condensed Consolidated Income Statements.......................... 5
Condensed Consolidated Statements of Cash Flows................... 7
Notes to Condensed Consolidated Financial Statements.............. 8
ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 17
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk..... 27
ITEM 4. Controls and Procedures........................................ 29
PART II. Other Information
ITEM 1. Legal Proceedings.............................................. 29
ITEM 2. Changes in Securities, Use of Proceeds and Issuer
Purchases of Equity Securities.................................... 29
ITEM 3. Defaults Upon Senior Securities................................ 30
ITEM 4. Submission of Matters to a Vote of Security Holders............ 30
ITEM 5. Other Information.............................................. 30
ITEM 6. Exhibits and Reports on Form 8-K.............................. 31
Signatures............................................................. 32
Certifications Pursuant to Item 302 of the Sarbanes-Oxley Act of 2002.. 33
PART I. Financial Information
ITEM 1. FINANCIAL STATEMENTS
CONTINENTAL RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
December 31, June 30,
Assets 2003 2004
------------------- --------------------
Current assets: (Unaudited)
Cash and cash equivalents $ 2,277 $ 7,817
Accounts receivable:
Oil and gas sales 19,035 20,241
Joint interest and other, net 13,577 14,738
Inventories 5,465 4,790
Prepaid expenses 336 345
Fair value of derivative contracts 151 422
------------------- -------------------
Total current assets 40,841 48,353
Property and equipment, at cost:
Oil and gas properties, based on
successful efforts accounting 601,325 630,609
Gas gathering and processing facilities 49,600 52,944
Service properties, equipment and other 19,515 19,983
------------------- -------------------
Total property and equipment 670,440 703,536
Less accumulated depreciation,
depletion and amortization 231,008 252,679
------------------- -------------------
Net property and equipment 439,432 450,857
Other assets:
Debt issuance costs, net 4,707 5,386
Other assets 8 8
------------------- -------------------
Total other assets 4,715 5,394
------------------- -------------------
Total assets $ 484,988 $ 504,604
=================== ===================
Liabilities and stockholders' equity
Current liabilities:
Accounts payable $ 27,950 $ 21,876
Current portion of long-term debt 5,776 5,776
Revenues and royalties payable 8,250 9,768
Accrued liabilities:
Interest 6,312 6,371
Other 7,212 5,740
Fair value of derivative contracts 640 663
------------------- -------------------
Total current liabilities 56,140 50,194
Long-term debt, net of current portion 285,144 302,404
Asset retirement obligation 26,608 27,104
Other noncurrent liabilities 164 168
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 92,190 100,149
Accumulated other comprehensive income (489) (646)
------------------- -------------------
Total stockholders' equity 116,932 124,734
------------------- -------------------
Total liabilities and stockholders' equity $ 484,988 $ 504,604
=================== ===================
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 June 30,
------------------ -------------------
2003 2004
------------------ -------------------
Revenues: (restated)
Oil and gas sales $ 33,347 $ 40,107
Crude oil marketing and trading 39,753 56,606
Change in derivative fair value 104 800
Gas gathering, marketing and processing 17,125 19,437
Oil and gas service operations 2,423 2,609
------------------ -------------------
Total revenues 92,752 119,559
Operating costs and expenses:
Production 10,342 10,079
Production taxes 2,361 2,636
Exploration 2,551 3,216
Crude oil marketing and trading 39,392 56,727
Gas gathering, marketing and processing 15,793 17,300
Oil and gas service operations 1,341 1,424
Depreciation, depletion and amortization of oil and gas properties 6,914 9,590
Depreciation and amortization of other property and equipment 1,231 1,283
Property impairments 1,276 1,802
Asset retirement obligation accretion 358 255
General and administrative 2,698 2,795
------------------ -------------------
Total operating costs and expenses 84,257 107,107
Operating income 8,495 12,452
Other income (expense):
Interest income 28 16
Interest expense (4,964) (5,451)
Other income, net 13 19
Gain (loss) on disposition of assets 277 (68)
------------------ -------------------
Total other income (expense) (4,646) (5,484)
------------------ -------------------
Net income $ 3,849 $ 6,968
================== ===================
Basic earnings per common share $ 0.27 $ 0.48
================== ===================
Diluted earnings per common share $ 0.27 $ 0.48
================== ===================
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)
Six Months Ended June 30,
------------------------------------
2003 2004
------------------ -----------------
Revenues: (restated)
Oil and gas sales $ 69,069 $ 76,230
Crude oil marketing and trading 80,348 112,311
Change in derivative fair value 407 404
Gas gathering, marketing and processing 26,850 35,302
Oil and gas service operations 4,305 4,723
---------------- -----------------
Total revenues 180,979 228,970
Operating costs and expenses:
Production 19,755 20,628
Production taxes 5,035 5,219
Exploration 4,053 5,308
Crude oil marketing and trading 79,876 112,590
Gas gathering, marketing and processing 24,621 31,108
Oil and gas service operations 2,732 3,370
Depreciation, depletion and amortization of oil and gas properties 15,217 20,057
Depreciation and amortization of other property and equipment 2,379 2,448
Property impairments 2,552 3,699
Asset retirement obligation accretion 709 531
General and administrative 5,323 5,295
---------------- -----------------
Total operating costs and expenses 162,252 210,253
Operating income 18,727 18,717
Other income (expense):
Interest income 59 43
Interest expense (9,916) (10,740)
Other income, net 50 42
Gain (loss) on disposition of assets 270 (103)
---------------- -----------------
Total other income (expense) (9,537) (10,758)
---------------- -----------------
Income before change in accounting principle 9,190 7,959
---------------- -----------------
Cumulative effect of change in accounting principle 2,162 -
---------------- -----------------
Net income $ 11,352 $ 7,959
================ =================
Basic earnings per common share:
Earnings before cumulative effect of accounting change $ 0.64 $ 0.55
Cumulative effect of accounting change 0.15 -
---------------- -----------------
Basic $ 0.79 $ 0.55
================ =================
Diluted earnings per common share:
Earnings before cumulative effect of accounting change $ 0.64 $ 0.55
Cumulative effect of accounting change 0.15 -
---------------- -----------------
Diluted $ 0.79 $ 0.55
================ =================
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)
Six Months Ended June 30,
---------------------------------
2003 2004
--------------- ---------------
Cash flows from operating activities: (restated)
Net income $ 11,352 $ 7,959
Adjustments to reconcile net income to net cash
provided by operating activities-
Depreciation, depletion and amortization 17,596 22,518
Accretion of asset retirement obligation 709 531
Impairment of properties 2,552 3,699
Change in derivative fair value (407) (404)
Amortization of debt issuance costs 791 882
(Gain) loss on disposition of assets (450) 103
Change in accounting principle (2,162) -
Dry hole costs 2,775 3,929
Cash provided by (used in) changes in assets and liabilities-
Accounts receivable (2,401) (2,367)
Inventories (1,143) 675
Prepaid expenses 154 (9)
Accounts payable (2,623) (6,074)
Revenues and royalties payable 149 1,518
Accrued liabilities and other 828 (1,413)
Other noncurrent liabilities 23 4
--------------- ---------------
Net cash provided by operating activities 27,743 31,551
Cash flows from investing activities:
Exploration and development (49,922) (37,537)
Gas gathering and processing facilities and service
properties, equipment and other (2,806) (4,046)
Purchase of oil and gas properties (83) (322)
Proceeds from disposition of assets 4,482 195
--------------- ---------------
Net cash used in investing activities (48,329) (41,710)
Cash flows from financing activities:
Proceeds from line of credit and other debt 23,000 20,149
Repayment of debt (1,200) (2,889)
Debt issuance costs (75) (1,561)
--------------- ---------------
Net cash provided by financing activities 21,725 15,699
Net increase in cash 1,139 5,540
Cash and cash equivalents, beginning of year 2,520 2,277
--------------- ---------------
Cash and cash equivalents, end of period $ 3,659 $ 7,817
=============== ===============
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 management of Continental Resources, Inc., or CRI or the
Company, the accompanying unaudited condensed consolidated financial statements
contain all adjustments necessary to present fairly the Company's financial
position as of June 30, 2004, and the results of operations and cash flows for
the three months ended June 30, 2003 and 2004. Such adjustments are of a normal
recurring nature. The unaudited condensed consolidated financial statements for
the interim periods presented do not contain all information required by
accounting principles generally accepted in the United States. The results of
operations for any interim period are not necessarily indicative of the results
of operations for the entire year. These condensed consolidated financial
statements should be read in conjunction with the consolidated financial
statements and notes thereto included in the Company's annual report on form
10-K for the year ended December 31, 2003. Certain reclassifications have been
made to prior year amounts to conform to the current year presentation.
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 six months ended June 30, 2003, compared
to the current restated amount:
Six Months Ended
June 30, 2003
------------------------------------
(Dollars in thousands, except share data) Originally Reported Restated
- -------------------------------------------------------------------------- ----------------
Net income before change in accounting principle $ 9,190 $ 9,190
Cumulative effect of change in accounting principle 4,090 2,162
-------------- ----------------
Net income $ 13,280 $ 11,352
Diluted earnings per share $ 0.92 $ 0.79
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 June 30, 2004, the Company had capitalized drilling and development
costs of approximately $180.4 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 41.9 MMBoe of which approximately
18.9 MMBoe, or 45%, are proved developed non-producing, or PDNP. In future
periods, the PDNP reserves will be transferred to PDP as such reserves meet the
definition of proved reserves under SEC guidelines 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. In July 2004, but effective May 31,
2004, CRI sold all of the outstanding capital stock of CGI to the shareholders
of CRI. (See Note 8.)
2. LONG-TERM DEBT:
Long-term debt as of December 31, 2003, and June 30 2004, consisted of the
following:
December 31, June 30,
(Dollars in thousands) 2003 2004
----------------- -----------------
10.25% Senior Subordinated Notes due August 1, 2008 $ 127,150 $ 127,150
Credit Facility due March 31, 2007 132,900 128,049
Credit Facility due March 31, 2006 - 25,000
Credit Facility due September 30, 2006 17,000 15,786
Capital Lease Agreement 13,827 12,159
Ford Credit 43 36
----------------- -----------------
Outstanding Debt 290,920 308,180
Less Current Portion 5,776 5,776
----------------- -----------------
Total Long-Term Debt $ 285,144 $ 302,404
================= =================
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 June 30,
2004, the lead bank's reference rate plus margins was 4.2%. 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 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 August 13, 2004, the
outstanding balances were $137.0 million and $25.0 million on the original
revolving credit facility and the term loan, respectively.
On July 21, 2004, the Company executed the Fourth Amendment to the Credit
Agreement that modified the definitions to delete any reference to CGI. (See
Note 8.)
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 June 30, 2004, the outstanding
balance on CGI's credit facility was $15.8 million.
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 the
Company receives is determined based on a published index price plus or minus a
fixed basis. Under collars and floors, if the market price of crude oil exceeds
the ceiling strike price or falls below the floor strike price, then the Company
receives the fixed price ceiling or floor. If the market price is between the
floor strike price and the ceiling strike price, the Company receives market
price.
The Company has designated its fixed price physical delivery contracts and
fixed price basis contracts as "normal sales" contracts under SFAS No. 133,
Accounting for Derivative and Hedging Activities and are therefore not marked to
market as derivatives. The Company's collars and floors have been designated as
cash flow hedges under SFAS No. 133 and are being accounted for accordingly. The
following table summarizes the Company's fixed price physical delivery
contracts, collars and floors in place at June 30, 2004:
2004 2005 2006 2007
-------- --------- --------- ----------
Natural Gas Physical Delivery Contracts:
Contract Volumes (MMBtu) 300,000 600,000 600,000 600,000
Weighted Average Fixed Price per MMBtu $ 4.83 $ 4.53 $ 4.47 $ 4.49
Crude Oil Basis Contracts: Contract Contract
Month Volumes Price
--------- --------- ----------
Aug 2004 62,000 $ 37.72
Sep 2004 30,000 $ 41.09
Crude Oil Collars and Floors for 2004: Contract Weighted-average
Volumes (Bbls) Fixed Price per Bbl
---------------- -------------------
July - Oct, Floor 602,000 $ 22.00
Sept - Oct, Floor 200,000 $ 24.00
Nov - Dec, Floor 230,000 $ 24.50
----------------
1,032,000
================
July - Oct, Ceiling 460,000 $ 36.00
Nov - Dec, Ceiling 230,000 $ 45.00
----------------
690,000
================
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 June 30, 2004, crude oil
marketing and trading revenues included $9.9 million offset by crude oil
marketing and trading expenses of $10.1 million, related to such trading
activities. 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 June 30, 2004, the Company had closed its
open trading positions, locking in an unrealized gain of $404,100 on such
contracts.
4. EARNINGS PER SHARE:
Basic earnings per common share is computed by dividing income available to
common shareholders by the weighted-average number of shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if stock options were exercised, using the treasury stock method of
calculation. The weighted-average number of shares used to compute basic
earnings per common share was 14,368,919 for the three and six months ended June
30, 2003 and 2004. The weighted-average number of shares used to compute diluted
earnings per share was 14,463,210 for the three and six months ended June 30,
2003 and 2004.
5. GUARANTOR SUBSIDIARIES:
The Company's wholly owned subsidiaries, CGI, CRII, and Continental Crude
Co. (CCC), have guaranteed the Company's obligations under its outstanding 10-
1/4% Senior Subordinated Notes due August 1, 2008. CCC has not engaged in any
business activities since its inception. The following is a summary of the
condensed consolidating balance sheets of CGI and CRII as of December 31, 2003,
and June 30, 2004, and the results of operations and cash flows for the
three-month and six-month periods ended June 30, 2003, and 2004.
As of December 31, 2003 Condensed Consolidating Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Current Assets $ 11,162 $ 44,428 $ (14,749) $ 40,841
Property and Equipment 58,826 380,606 - 439,432
Other Assets 281 4,448 (14) 4,715
---------------- -------------- --------------- ----------------
Total Assets $ 70,269 $ 429,482 $ (14,763) $ 484,988
Current Liabilities $ 18,512 $ 44,694 $ (7,066) $ 56,140
Long-Term Debt 22,286 270,541 (7,683) 285,144
Other Liabilities 4,943 21,829 - 26,772
Stockholders' Equity 24,528 92,418 (14) 116,932
---------------- -------------- --------------- ----------------
Total Liabilities and
Stockholders' Equity $ 70,269 $ 429,482 $ (14,763) $ 484,988
================ ============== =============== ================
As of June 30, 2004 Condensed Consolidating Balance Sheet
- -----------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Current Assets $ 12,850 $ 49,323 $ (13,820) $ 48,353
Property and Equipment 59,952 390,905 - 450,857
Other Assets 236 5,172 (14) 5,394
---------------- -------------- --------------- ----------------
Total Assets $ 73,038 $ 445,400 $ (13,834) $ 504,604
Current Liabilities $ 16,305 $ 37,501 $ (3,612) $ 50,194
Long-Term Debt 23,590 289,022 (10,208) 302,404
Other Liabilities 5,065 22,207 - 27,272
Stockholders' Equity 28,078 96,670 (14) 124,734
---------------- -------------- --------------- ----------------
Total Liabilities and
Stockholders' Equity $ 73,038 $ 445,400 $ (13,834) $ 504,604
================ ============== =============== ================
For the Three Months Ended June 30, 2003 Condensed Consolidating Income Statement
- -----------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Total Revenue $ 19,581 $ 72,401 $ 770 $ 92,752
Operating Expense (18,382) (65,105) (770) (84,257)
Other Expense (302) (4,344) - (4,646)
---------------- -------------- --------------- ----------------
Net Income $ 897 2,952 $ - $ 3,849
================ ============== =============== ================
For the Three Months Ended June 30, 2004 Condensed Consolidating Income Statement
- -----------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Total Revenue $ 27,576 $ 96,395 $ (4,412) $ 119,559
Operating Expense (25,319) (86,200) 4,412 (107,107)
Other Expense (315) (5,169) - (5,484)
---------------- -------------- --------------- ----------------
Net Income $ 1,942 $ 5,026 $ - $ 6,968
================ ============== =============== ================
For the Six Months Ended June 30, 2003 Condensed Consolidating Income Statement
- -----------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Total Revenue $ 35,426 $ 147,062 $ (1,509) $ 180,979
Operating Expense (32,454) (131,307) 1,509 (162,252)
Other Expense (685) (8,852) - (9,537)
Cumulative Effect of Change in Accounting Principle (50) 2,212 - 2,162
---------------- -------------- --------------- ----------------
Net Income $ 2,237 $ 9,115 $ - $ 11,352
================ ============== =============== ================
For the Six Months Ended June 30, 2004 Condensed Consolidating Income Statement
- ------------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Total Revenue $ 51,926 $ 186,641 $ (9,597) $ 228,970
Operating Expense (47,741) (172,109) 9,597 (210,253)
Other Expense (635) (10,123) - (10,758)
---------------- -------------- --------------- ----------------
Net Income $ 3,550 $ 4,409 $ - $ 7,959
================ ============== =============== ================
For the Six Months Ended June 30, 2003 Condensed Consolidated Cash Flows Statements
- -----------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Cash Flows From Operating Activities $ 4,268 $ 23,531 $ (56) $ 27,743
Cash Flows From Investing Activities (5,035) (43,294) - (48,329)
Cash Flows From Financing Activities (1,724) 21,725 1,724 21,725
---------------- -------------- --------------- ----------------
Net Increase (Decrease) in Cash (2,491) 1,962 1,668 1,139
Cash at Beginning of Period 456 2,064 - 2,520
---------------- -------------- --------------- ----------------
Cash at End of Period $ (2,035) $ 4,026 $ 1,668 $ 3,659
================ ============== =============== ================
For the Six Months Ended June 30, 2004 Condensed Consolidated Cash Flow Statements
- -----------------------------------------------------------------------------------------------------------------------
($ in thousands) Guarantor
Subsidiaries Parent Eliminations Consolidated
---------------- -------------- --------------- ----------------
Cash Flow From Operating Activities $ 7,635 $ 25,068 $ (1,152) $ 31,551
Cash Flow From Investing Activities (4,498) (37,212) - (41,710)
Cash Flow From Financing Activities (2,378) 16,925 1,152 15,699
---------------- -------------- --------------- ----------------
Net Increase in Cash 759 4,781 - 5,540
Cash at Beginning of Period 701 1,576 - 2,277
---------------- -------------- --------------- ----------------
Cash at End of Period $ 1,460 $ 6,357 $ - $ 7,817
================ ============== =============== ================
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. In July 2004, but effective May 31, 2004, CRI sold
all of the outstanding capital stock of CGI to the shareholders of CRI. (See
Note 8.) Financial information by operating segment is presented below:
Exploration Gas Gathering,
For the Three Months Ended and Marketing and
June 30, 2003 Production Processing Intersegment Total
- ------------------------------------------- ----------------- --------------- ---------------- ---------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 33,257 $ 90 $ - $ 33,347
Crude oil marketing and trading 39,753 - - 39,753
Change in derivative fair value 104 - - 104
Gas gathering, marketing and processing - 16,356 769 17,125
Oil and gas service operations 2,423 - - 2,423
----------------- --------------- ---------------- ----------------
Total revenues $ 75,537 $ 16,446 $ 769 $ 92,752
OPERATING COSTS AND EXPENSES:
Production expenses 10,291 52 - 10,343
Production taxes 2,352 9 - 2,361
Exploration 2,541 10 - 2,551
Crude oil marketing and trading 39,392 - - 39,392
Gas gathering, marketing and processing - 15,024 769 15,793
Oil and gas service operations 1,340 - - 1,340
Depreciation, depletion and amortization of
oil and gas properties 6,720 194 - 6,914
Depreciation and amortization of
other property and equipment 543 688 - 1,231
Property impairments 1,279 (3) - 1,276
Asset retirement accretion 354 4 - 358
General and administrative 2,488 210 - 2,698
----------------- --------------- ---------------- ----------------
Total operating costs and expenses $ 67,300 $ 16,188 $ 769 $ 84,257
Total operating income $ 8,237 $ 258 $ - $ 8,495
OTHER INCOME (EXPENSE):
Interest income 720 2 (694) 28
Interest expense (5,589) (69) 694 (4,964)
Other income, net 11 2 - 13
Gain on disposition of assets 277 - - 277
----------------- --------------- ---------------- ----------------
Total other income (expense) $ (4,581) $ (65) $ - $ (4,646)
Net income $ 3,656 $ 193 $ - $ 3,849
================= =============== ================ ================
Total assets $ 464,719 $ 33,590 $ (21,426) $ 476,883
================= =============== ================ ================
Capital expenditures $ 23,620 $ 1,370 $ - $ 24,990
================= =============== ================ ================
Exploration Gas Gathering,
For the Three Months Ended and Marketing and
June 30, 2004 Production Processing Intersegment Total
- ------------------------------------------- ----------------- --------------- ---------------- ---------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 39,925 $ 182 $ - $ 40,107
Crude oil marketing and trading 56,606 - - 56,606
Change in derivative fair value 800 - - 800
Gas gathering, marketing and processing - 23,849 (4,412) 19,437
Oil and gas service operations 2,609 - - 2,609
----------------- -------------- ---------------- ---------------
Total revenues $ 99,940 $ 24,031 $ (4,412) $ 119,559
OPERATING COSTS AND EXPENSES:
Production expenses 10,010 69 - 10,079
Production taxes 2,619 17 - 2,636
Exploration 3,216 - - 3,216
Crude oil marketing and trading 56,727 - - 56,727
Gas gathering, marketing and processing - 21,712 (4,412) 17,300
Oil and gas service operations 1,424 - - 1,424
Depreciation, depletion and amortization of
oil and gas properties 9,576 14 - 9,590
Depreciation and amortization of
other property and equipment 351 932 - 1,283
Property impairments 1,802 - - 1,802
Asset retirement accretion 251 4 - 255
General and administrative 2,567 228 - 2,795
----------------- -------------- ----------------- ---------------
Total operating costs and expenses $ 88,543 $ 22,976 $ (4,412) $ 107,107
Total operating income $ 11,397 $ 1,055 $ - $ 12,452
OTHER INCOME (EXPENSE):
Interest income 367 2 (353) 16
Interest expense (5,613) (191) 353 (5,451)
Other income, net 18 1 - 19
Loss on disposition of assets (68) - - (68)
----------------- -------------- ----------------- ---------------
Total other income (expense) $ (5,296) $ (188) $ - $ (5,484)
Net income $ 6,101 $ 867 $ - $ 6,968
================= ============== ================= ===============
Total assets $ 467,139 $ 51,299 $ (13,834) $ 504,604
================= ============== ================= ================
Capital expenditures $ 19,143 $ 2,071 $ - $ 21,214
================= ============== ================= =================
Exploration Gas Gathering,
For the Six Months Ended and Marketing and
June 30, 2003 Production Processing Intersegment Total
- ------------------------------------------- ----------------- --------------- ---------------- ---------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 68,787 $ 282 $ - $ 69,069
Crude oil marketing and trading 80,348 - - 80,348
Change in derivative fair value 407 - - 407
Gas gathering, marketing and processing - 28,360 (1,510) 26,850
Oil and gas service operations 4,305 - - 4,305
----------------- -------------- ---------------- ----------------
Total revenues $ 153,847 $ 28,642 $ (1,510) $ 180,979
OPERATING COSTS AND EXPENSES:
Production expenses 19,653 102 - 19,755
Production taxes 5,011 24 - 5,035
Exploration 4,021 32 - 4,053
Crude oil marketing and trading 79,876 - - 79,876
Gas gathering, marketing and processing - 26,131 (1,510) 24,621
Oil and gas service operations 2,732 - - 2,732
Depreciation, depletion and amortization of
oil and gas properties 15,270 (53) - 15,217
Depreciation and amortization of
other property and equipment 1,068 1,311 - 2,379
Property impairments 2,552 - - 2,552
Asset retirement accretion 703 6 - 709
General and administrative 4,958 365 - 5,323
----------------- -------------- ---------------- ----------------
Total operating costs and expenses $ 135,844 $ 27,918 $ (1,510) $ 162,252
Total operating income $ 18,003 $ 724 $ - $ 18,727
OTHER INCOME (EXPENSE):
Interest income 809 4 (754) 59
Interest expense (10,541) (129) 754 (9,916)
Other income, net 48 2 - 50
Gain (loss) on disposition of assets 278 (8) - 270
----------------- -------------- ---------------- ----------------
Total other income (expense) $ (9,406) $ (131) $ - $ (9,537)
Total income from operations $ 8,597 $ 593 $ - $ 9,190
----------------- -------------- ---------------- ----------------
Cumulative effect of change in accounting principle 274 1,888 - 2,162
Net income $ 8,871 $ 2,481 $ - $ 11,352
================= ============== ================ ================
Total assets $ 464,719 $ 33,590 $ (21,426) $ 476,883
================= ============== ================ ================
Capital expenditures $ 49,912 $ 2,816 $ - $ 52,728
================= ============== ================ ================
Exploration Gas Gathering,
For the Six Months Ended and Marketing and
June 30, 2004 Production Processing Intersegment Total
- ------------------------------------------- ----------------- --------------- ---------------- ---------------
(Dollars in thousands)
REVENUES:
Oil and gas sales $ 75,911 $ 319 $ - $ 76,230
Crude oil marketing and trading 112,311 - - 112,311
Change in derivative fair value 404 - - 404
Gas gathering, marketing and processing - 44,899 (9,597) 35,302
Oil and gas service operations 4,723 - - 4,723
----------------- -------------- ---------------- ----------------
Total revenues $ 193,349 $ 45,218 $ (9,597) $ 228,970
OPERATING COSTS AND EXPENSES:
Production expenses 20,490 138 - 20,628
Production taxes 5,190 29 - 5,219
Exploration 5,308 - - 5,308
Crude oil marketing and trading 112,590 - - 112,590
Gas gathering, marketing and processing - 40,705 (9,597) 31,108
Oil and gas service operations 3,370 - - 3,370
Depreciation, depletion and amortization of
oil and gas properties 20,021 36 - 20,057
Depreciation and amortization of
other property and equipment 699 1,749 - 2,448
Property impairments 3,699 - - 3,699
Asset retirement accretion 523 8 - 531
General and administrative 4,789 506 - 5,295
----------------- -------------- ---------------- ----------------
Total operating costs and expenses $ 176,679 $ 43,171 $ (9,597) $ 210,253
Total operating income $ 16,670 $ 2,047 $ - $ 18,717
OTHER INCOME (EXPENSE):
Interest income 392 4 (353) 43
Interest expense (10,708) (385) 353 (10,740)
Other income, net 30 12 - 42
Loss on disposition of assets (103) - - (103)
----------------- -------------- ------- -------- ----------------
Total other income (expense) $ (10,389) $ (369) $ - $ (10,758)
Net income $ 6,281 $ 1,678 $ - $ 7,959
================= ============== ================ ================
Total assets $ 467,139 $ 51,299 $ (13,834) $ 504,604
================= ============== ==================================
Capital expenditures $ 38,474 $ 3,430 $ - $ 41,904
================= ============== ================ ================
7. COMPREHENSIVE INCOME:
The components of total comprehensive income for the three and six months
ended June 30, 2003 and 2004 are as follows:
Three Months Ended June 30, Six Months Ended June 30,
-------------------------------- -----------------------------------
2003 2004 2003 2004
---------------- ------------- --------------- ----------------
(Dollars in thousands) (restated) (restated)
Net Income $ 3,849 $ 6,968 $ 11,352 $ 7,959
Other Comprehensive Income (loss) -
net of income tax:
Deferred Hedging Gain (loss) - 350 - (646)
---------------- ------------- --------------- ----------------
Total Comprehensive Income $ 3,849 $ 7,318 $ 11,352 $ 7,313
================ ============= =============== ================
8. SUBSEQUENT EVENTS:
On July 19, 2004, CRI paid a cash dividend of $14.9 million to its
shareholders.
On July 21, 2004, CRI purchased $7.65 million of its 10-1/4% Senior
Subordinated Notes due August 1, 2008, from its principal shareholder, Harold
Hamm, and certain of his affiliates. Through June 30, 2004, CRI has purchased an
aggregate of $30.5 million principal amount of these Senior Subordinated Notes.
On July 21, 2004, CRI completed the sale of all of its Continental Gas,
Inc., or CGI, stock to its shareholders, Harold Hamm and Bert Mackie, as Trustee
of the Harold Hamm DST Trust (the "DST Trust") and of the Harold Hamm HJ Trust
(the "Buyers") for $22.6 million in cash. The sales price was representative of
the fair value of the net assets based on an appraisal by an independent third
party who also provided the Company with an opinion of the fairness from a
financial point of view, of the sale of CGI to the Buyers. The CGI assets
included seven gas gathering systems, three gas-processing plants, and
approximately 750 miles of gas gathering lines. These assets represented the
entire gas gathering, marketing and processing segment of the Company.
On July 21, 2004, the Company executed the Fourth Amendment to the Credit
Agreement that modified the definition to delete any reference to CGI.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in conjunction with
our unaudited condensed consolidated financial statements, and the notes thereto
that appear elsewhere in this report, and our annual report on Form 10-K for the
year ended December 31, 2003. Our operating results for the periods discussed
may not be indicative of future performance. Statements concerning future
results are forward-looking statements. In the text below, financial statement
numbers have been rounded; however, the percentage changes are based on amounts
that have not been rounded.
OVERVIEW
We foresee continued growth through the second half of 2004. Relatively
high oil and gas prices 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 18 months. Response is occurring
as initially simulated by our Resource Development group. Oil production in our
Cedar Hills North Unit at June 30, 2004, was approximately 3,500 Bbls per day,
an increase of 883 Bbls per day, or BOPD, since November 2003, and 1,300 BOPD
over projected primary rates of production without enhanced recovery. During the
six months ended June 30, 2004, 9.7 million net barrels of reserves in the Cedar
Hills North Unit were moved from proved undeveloped, or PUD, reserves to proved
developed producing, or PDP, reserves and 18.9 million net barrels were moved to
proved developed non-producing, or PDNP, reserves from PUD reserves. Currently,
we anticipate that the 18.9 million barrels will be re-classified to PDP by
mid-year 2005 as response to HPAI continues, and our oil production in our Cedar
Hills North Unit, on a daily basis, to reach 6,200 BOPD by the end of 2004 and
be above 7,100 BOPD by mid-year 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
June 2004:
Monthly Production (Bbls) Increase
------------------------------
Property Nov 2003 Jun 2004 Bbls per Day
- ------------------------ ------------- ---------------- --------------
Cedar Hills North Unit 69,800 95,400 853
West Cedar Hills Unit 7,700 8,600 30
------------- ---------------- --------------
Total 77,500 104,000 883
Currently, lifting costs in our Rocky Mountain Region are significantly
higher than our historic average due to the energy costs and other associated
costs used in HPAI recovery, coupled with the conversion of producing wells to
injector wells to complete the injection pattern engineered for the field. Thus,
less production is available at a time when injection costs are high. We expect
our lifting costs per barrel to decline dramatically in the Rocky Mountain
Region as response and increased production occurs. We project a reduction of
more than $5.00 per barrel in lifting costs by late 2004 or early 2005.
Excluding Cedar Hills, we completed nine wells during the second quarter of
2004, resulting in seven producers and two dry holes for a success rate of 78%
for the quarter. Of these nine wells, three are located in the Rocky Mountain
region, five wells are in the Mid-Continent region and one well is in the Gulf
Coast region. We currently have six wells drilling and nine wells ready for and
waiting on completion.
We continue to experience 100% success drilling wells in our Middle Bakken,
or MB, project, located in Richland County, Montana. Since completing our first
well in the third quarter of 2003, we have drilled and completed 10 wells, (6.1
net wells) to date. These wells have added an estimated 5.5 MMBOE of gross PDP
reserves (2.6 MMBOE net) for an average of 548 MBOE per gross well. These
reserve figures are in line with expectations. Initial flow rates have ranged
from 400 BOPD to 1,600 BOPD. We have invested approximately $3.0 million leasing
an additional 28,000 net acres in the MB project during 2004, bringing our total
leasehold in the MB project to 92,000 net acres. With this additional leasehold,
our inventory of potential wells to drill in the MB project has grown to 126
gross wells and 63 net wells. During the second half of 2004, we anticipate
completing an additional seven wells (4.6 net wells) bringing the total
producing well count in the MB project to 17 gross wells (10.7 net wells) by
year-end 2004. We currently have one rig drilling in MB and plan to add a second
rig in the third quarter of 2004 and a third rig in the fourth quarter of 2004.
Using the MB project as our model, we have expanded our search for Bakken
oil reserves into North Dakota. During the first half of 2004, we have invested
approximately $8.7 million acquiring 232,000 net leasehold acres on
opportunities in North Dakota identified by our geotechnical staff. Drilling
evaluation of this leasehold has begun and will continue through year-end. The
net reserve potential of these new leases could exceed those in the MB project
but remains unproven at this time.
As a result of the additional leasing in MB and the new North Dakota
projects, leasing expenditures for 2004 are projected to total an estimated
$20.0 million or $12.3 million over the $7.7 million originally budgeted for the
year.
During the second quarter of 2004, we agreed to sell a 60% working interest
in our Stanley Cup project located in Saskatchewan, Canada, to three industry
partners on a promoted basis to accelerate development and mitigate risk of not
developing this promising prospect. Stanley Cup is a horizontal Red River
project similar to the Cedar Hills field with reserve potential of up to 24
MMBO. Drilling is anticipated to begin in the third quarter of 2004.
We have recently elected to discontinue our participation in the Challenger
Minerals Inc. Gulf of Mexico venture. Although our five-year results have been
profitable, we believe these dollars can be more profitably invested in other
Company projects. We will continue to develop the East Island and Breton Sound
projects; however, we are contemplating selling and monetizing all other Gulf of
Mexico assets. We have an insurance claim on a Eugene Island well, and if
successful, we should receive approximately $0.6 million that would be booked to
other income in the third quarter of 2004.
We have decided to package and sell all undeveloped leasehold in the Black
Warrior Basin in Mississippi. As noted in our 2003 annual report, drilling
results have not met expectations. The Smith Creek project is the only project
in the basin where we anticipate drilling additional wells over the next 12
months.
During the first half of 2004, the plant throughput in our Matli gas
processing system was 2.8 Bcf, an increase of 1.1 Bcf, or 58% over the Matli
plant throughput in the first half of 2003.
Our capital expenditure budget for 2004 is $83.3 million. Through the end
of the first half of 2004, our aggregate capital expenditures were $41.9
million.
THREE MONTHS ENDED JUNE 30, 2003, COMPARED TO THREE MONTHS ENDED JUNE 30, 2004
Certain reclassifications have been made to prior year amounts to conform
to the current year presentation.
The following table shows our income statements for the second quarter of
2003 compared to the second quarter of 2004 with dollar and percentage increases
or decreases:
Three Months Ended June 30,
----------------------------- Increase Increasse
REVENUES: 2003 2004 (Decrease) (Decrease)
------------- --------------- -------------- -----------------
Oil and gas sales $ 33,347 $ 40,107 $ 6,760 20.27%
Crude oil marketing and trading 39,753 56,606 16,853 42.39%
Change in derivative fair value 104 800 696 669.23%
Gas gathering, marketing and processing 17,125 19,437 2,312 13.50%
Oil and gas service operations 2,423 2,609 186 7.68%
------------- --------------- -------------- -----------------
Total revenues $ 92,752 $ 119,559 $ 26,807 28.90%
OPERATING COSTS AND EXPENSES:
Production $ 10,342 $ 10,079 $ (263) -2.54%
Production taxes 2,361 2,636 275 11.65%
Exploration 2,551 3,216 665 26.07%
Crude oil marketing and trading 39,392 56,727 17,335 44.01%
Gas gathering, marketing and processing 15,793 17,300 1,507 9.54%
Oil and gas service operations 1,341 1,424 83 6.19%
DD&A of oil and gas properties 6,914 9,590 2,676 38.70%
D&A of other assets 1,231 1,283 52 4.22%
Property impairments 1,276 1,802 526 41.22%
Asset retirement obligation accretion 358 255 (103) -28.77%
General and administrative 2,698 2,795 97 3.60%
------------- --------------- -------------- -----------------
Total operating costs and expenses $ 84,257 $ 107,107 $ 22,850 27.12%
OPERATING INCOME $ 8,495 $ 12,452 $ 3,957 46.58%
OTHER INCOME (EXPENSE):
Interest income $ 28 $ 16 $ (12) -42.86%
Interest expense (4,964) (5,451) (487) 9.81%
Other income, net 13 19 6 46.15%
Gain (loss) on disposition of assets 277 (68) (345) -
------------- --------------- -------------- -----------------
Total other income (expense) $ (4,646) $ (5,484) $ (838) 18.04%
NET INCOME $ 3,849 $ 6,968 $ 3,119 81.03%
============= =============== ============== =================
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 June 30,
------------------------------
2003 2004
------------- --------------
NET PRODUCTION:
Oil (MBbl) 884 858
Gas (MMcf) 2,590 2,147
Oil equivalent (MBoe) 1,316 1,216
OIL AND GAS SALES (dollars in thousands)
Oil sales, excluding hedges $ 24,660 $ 30,467
Hedges (2,579) (1,270)
------------- --------------
Total oil sales, including hedges 22,081 29,197
Gas sales 11,266 10,910
------------- --------------
Total oil and gas sales $ 33,347 $ 40,107
============= ==============
AVERAGE SALES PRICE:
Oil, excluding hedges (dollar per barrel) $ 27.90 $ 35.50
Oil, including hedges (dollar per barrel) $ 24.98 $ 34.02
Gas (dollar per Mcf) $ 4.35 $ 5.08
Oil equivalent, excluding hedges (dollar per Boe) $ 27.30 $ 34.02
Oil equivalent, including hedges (dollar per Boe) $ 25.35 $ 32.98
EXPENSES (dollars per Boe):
Production expenses (including taxes) $ 9.65 $ 10.46
General and administrative $ 2.05 $ 2.30
DD&A (on oil and gas properties) $ 5.25 $ 7.89
REVENUES
GENERAL
The increase in revenues is attributable to higher oil and gas prices
realized on our oil and gas 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 June 30, 2004, compared to the same
period in 2003 primarily due to increased prices and our acquisition of the
Carmen Gathering System in July 2003, which increased our total throughput.
OIL AND GAS SALES
The increase in oil and gas sales revenues was primarily attributable to
higher oil and gas prices in the 2004 period even though volumes decreased to
1,216 thousand barrels of oil equivalent, or MBoe, in the three months ended
June 30, 2004, from 1,316 MBoe during the three months ended June 30, 2003.
The following table shows our production by region for the three months
ended June 30, 2003 and 2004:
Three Months Ended June 30,
-------------------------------------------------------
2003 2004
------------------------- ----------------------------
MBoe Percent MBoe Percent
--------- --------------- ------------ ---------------
Rocky Mountain 752 57.14% 758 62.34%
Mid-Continent 399 30.32% 357 29.36%
Gulf 165 12.54% 101 8.30%
--------- --------------- ------------ ---------------
1,316 100.00% 1,216 100.00%
========= =============== ============ ===============
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 second 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 June
30, 2004, crude oil marketing revenues were $9.9 million and crude oil marketing
expenses were $10.1 million related to such trading activities. Our derivative
trading activities are being marked to market with all changes in fair value
being recorded in the income statement under the accounting prescribed by SFAS
No. 133, Accounting for Derivative and Hedging Activities. Effective May 2004,
we closed out all open trading positions and have terminated our derivative
trading activities.
CHANGE IN DERIVATIVE FAIR VALUE
The change in derivative fair value for the three months ended June 30,
2003, is related to a crude oil derivative contract used to reduce our exposure
to changes in crude oil prices that did not qualify for special hedge accounting
under SFAS No. 133. Such contract expired at December 31, 2003. The change in
derivative fair value for the three months ended June 30, 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 second quarter of 2004 was attributable to increased throughput volumes
resulting from growth in our existing systems, increase in product prices, and
our acquisition of the Carmen Gathering System in July 2003.
OIL AND GAS SERVICE OPERATIONS
We started selling HPAI services to a third party in 2004 which increased
our oil and gas service operations $0.6 million in the second quarter of 2004
compared to the second quarter of 2003. This increase was mostly offset by a
decrease of $0.3 million in equipment rental income for the second quarter of
2004.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expenses including taxes for the second quarter of 2004
compared to the second quarter of 2003 did not change significantly, but the 8%
decrease in volumes for the same periods caused our production expenses
including taxes per BOE for the second quarter of 2004 to increase to $10.46
from $9.65 for the second quarter of 2003.
EXPLORATION EXPENSES
The increase in exploration expense was primarily due to an increase in our
dry hole costs in the Gulf Coast region, which were amplified by significant
mechanical problems and cost overruns while drilling the Shaffer D-2 well in
Nueces County, Texas.
CRUDE OIL MARKETING AND TRADING
The 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 second quarter of 2004 was attributable to increased throughput volumes
resulting from growth in our existing systems, increased product prices, 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 for the second
quarter of 2004 compared to the second quarter of 2003 was immaterial.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES (DD&A)
Depletion increased $2.7 million in the second quarter of 2004 compared to
the second quarter of 2003, due to adjustments to the mid-year reserve report
and certain developmental dry hole costs being added to our amortization base
and depleted with the costs of the related property offsets. In the second
quarter of 2004, our DD&A expense on our oil and gas properties was calculated
at $7.89 per BOE, compared to $5.25 per BOE for the second quarter of 2003. The
decrease in volumes for the 2004 period also contributed to a higher DD&A
expense per BOE in 2004.
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 June 30, 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 for the second quarter of 2004 compared to the second
quarter of 2003 did not change significantly, but the decrease in volumes for
the same periods caused our G&A expense per BOE for the second quarter of 2004
to increase to $2.30 from $2.05 for the second 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
second quarter of 2004 compared to the second quarter of 2003.
SIX MONTHS ENDED JUNE 30, 2003, COMPARED TO SIX MONTHS ENDED JUNE 30, 2004.
Certain reclassifications have been made to prior year amounts to conform
to the current year presentation.
The following table shows our income statement for the six months ended
June 30, 2003, compared to the six months ended June 30, 2004, with dollar and
percentage increases or decreases:
Six Months Ended June 30,
----------------------------- Increase Increasse
REVENUES: 2003 2004 (Decrease) (Decrease)
------------ --------------- ------------- -----------------
Oil and gas sales $ 69,069 $ 76,230 $ 7,161 10.37%
Crude oil marketing and trading 80,348 112,311 31,963 39.78%
Change in derivative fair value 407 404 (3) -0.74%
Gas gathering, marketing and processing 26,850 35,302 8,452 31.48%
Oil and gas service operations 4,305 4,723 418 9.71%
------------ --------------- ------------- ----------------
Total revenues $ 180,979 $ 228,970 $ 47,991 26.52%
OPERATING COSTS AND EXPENSES:
Production $ 19,755 $ 20,628 $ 873 4.42%
Production taxes 5,035 5,219 184 3.65%
Exploration 4,053 5,308 1,255 30.96%
Crude oil marketing and trading 79,876 112,590 32,714 40.96%
Gas gathering, marketing and processing 24,621 31,108 6,487 26.35%
Oil and gas service operations 2,732 3,370 638 23.35%
DD&A of oil and gas properties 15,217 20,057 4,840 31.81%
D&A of other assets 2,379 2,448 69 2.90%
Property impairments 2,552 3,699 1,147 44.95%
Asset retirement obligation accretion 709 531 (178) -25.11%
General and administrative 5,323 5,295 (28) -0.53%
------------ --------------- ------------- ----------------
Total operating costs and expenses $ 162,252 $ 210,253 $ 48,001 29.58%
OPERATING INCOME $ 18,727 $ 18,717 $ (10) -0.05%
OTHER INCOME (EXPENSE):
Interest income $ 59 $ 43 $ (16) -27.12%
Interest expense (9,916) (10,740) (824) 8.31%
Other income, net 50 42 (8) -16.00%
Gain (loss) on sale of assets 270 (103) (373) -
------------ --------------- ------------- ----------------
Total other income (expense) $ (9,537) $ (10,758) $ (1,221) 12.80%
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE $ 9,190 $ 7,959 $ (1,231) -13.39%
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE $ 2,162 $ - $ (2,162) -
NET INCOME $ 11,352 $ 7,959 $ (3,393) -29.89%
============ =============== ============= ================
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 Six Months
Ended June 30,
------------- --------------
2003 2004
------------- --------------
NET PRODUCTION:
Oil (MBbl) 1,791 1,646
Gas (MMcf) 4,958 4,469
Oil equivalent (MBoe) 2,617 2,390
OIL AND GAS SALES (dollars in thousands)
Oil sales, excluding hedges $ 52,775 $ 55,917
Hedges (7,305) (1,724)
------------- --------------
Total oil sales, including hedges 45,470 54,193
Gas sales 23,599 22,037
------------- --------------
Total oil and gas sales $ 69,069 $ 76,230
============= ==============
AVERAGE SALES PRICE:
Oil, excluding hedges (dollar per barrel) $ 29.47 $ 33.98
Oil, including hedges (dollar per barrel) $ 25.39 $ 32.93
Gas (dollar per Mcf) $ 4.76 $ 4.93
Oil equivalent, excluding hedges (dollar per Boe) $ 29.18 $ 32.61
Oil equivalent, including hedges (dollar per Boe) $ 26.39 $ 31.89
EXPENSES (dollars per Boe):
Production expenses (including taxes) $ 9.47 $ 10.81
General and administrative $ 2.03 $ 2.22
DD&A (on oil and gas properties) $ 5.81 $ 8.39
REVENUES
GENERAL
Our revenues increased due to higher oil and gas prices realized on our oil
and gas production and an increase in volumes from our oil marketing and trading
programs. Gas gathering, marketing and processing revenues were higher for the
six months ended June 30, 2004, compared to the six months ended June 30, 2003,
due to higher prices and the acquisition of the Carmen Gathering System that
increased our total throughput.
OIL AND GAS SALES
Although our volumes for the first six months of 2004 decreased 227 MBoe
compared to the first six months of 2003, our oil and gas sales revenues for the
six months of 2004 increased compared to the first six months of 2003 due to
higher oil and gas prices.
The following table shows our production by region for the six months ended
June 30, 2003 and 2004:
Six Months Ended June 30,
-------------------------------------------------------
2003 2004
------------------------- ----------------------------
MBoe Percent MBoe Percent
--------- --------------- ------------ ---------------
Rocky Mountain 1,523 58.20% 1,439 60.21%
Mid-Continent 790 30.19% 726 30.38%
Gulf 304 11.61% 225 9.41%
--------- --------------- ------------ ---------------
2,617 100.00% 2,390 100.00%
========= =============== ============ ===============
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 six months of 2004, we engaged in certain crude
oil trading activities, exclusive of our own production, utilizing fixed price
and variable priced physical delivery contracts. For the six months ended June
30, 2004, crude oil marketing revenues were $20.2 million and crude oil
marketing expenses were also $20.4 million, related to such trading activities.
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 six months ended June 30, 2003,
is related to a crude oil derivative contract used to reduce our exposure to
changes in crude oil prices that did not qualify for special hedge accounting
under SFAS No. 133. Such contract expired at December 31, 2003. The change in
derivative fair value for the six months ended June 30, 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 six months of 2004 was attributable to increased throughput volumes
resulting from growth in our existing systems, increased product prices, and the
acquisition of the Carmen Gathering system in July 2003.
OIL AND GAS SERVICE OPERATIONS
We started selling HPAI services to a third party in 2004 which increased
our oil and gas service operations $0.6 million in the first six months of 2004
compared to the first six months of 2003. This increase was offset by a decrease
of $0.2 million in saltwater disposal fees due to shut-in wells in the first six
months of 2004.
COSTS AND EXPENSES
PRODUCTION EXPENSES AND TAXES
Our production expense including taxes for the first six months of 2004
compared to the first six months of 2003 did not change significantly, but the
9% decrease in volumes from the same periods caused our production expenses
including taxes per BOE for the first six months of 2004 to increase to $10.81
from $9.47 for the first six months of 2003.
EXPLORATION EXPENSES
The increase in exploration expense was primarily due to an increase in our
dry hole costs in the Gulf Coast region, which were amplified by significant
mechanical problems and cost overruns associated with the Shaffer D-2 well in
Nueces County, Texas in the first six months of 2004 compared to the first six
months of 2003.
CRUDE OIL MARKETING AND TRADING
The increase in our crude oil marketing expense was primarily due to
increased prices for oil we purchased and greater volumes marketed and traded.
GAS GATHERING, MARKETING, AND PROCESSING
During the six months ended June 30, 2004, gas gathering, marketing and
processing expenses increased over the six months ended June 30, 2003 due to
increased throughput volumes from growth in our existing systems, increased
product prices, and the acquisition of the Carmen Gathering System in July 2003.
OIL AND GAS SERVICE OPERATIONS
The increase in our oil and gas service operations expense was due to high
prices paid for purchasing and treating reclaimed oil for resale.
DEPRECIATION, DEPLETION AND AMORTIZATION OF OIL AND GAS PROPERTIES ("DD&A")
For the six months ended June 30, 2004, DD&A of our oil and gas properties
increased due to certain developmental dry hole costs being added to our
amortization base and depleted with the costs of the related property offsets
and due to slightly higher production decline rates in the Gulf Coast region. In
the first six months of 2004, our DD&A expense on oil and gas properties was
calculated at $8.39 per BOE compared to $5.81 per BOE for the first six months
of 2003. The decrease in volumes for the 2004 period also contributed to a
higher DD&A expense per BOE in 2004.
DEPRECIATION AND AMORTIZATION OF OTHER ASSETS ("D&A")
Our change in depreciation and amortization expense related to our other
properties and equipment was immaterial.
PROPERTY IMPAIRMENTS
The increase in our property impairments for the six months ended June 30,
2004 compared to the six months ended June 30, 2003, was primarily due to
increased impairment on capitalized costs of our undeveloped leasehold.
ASSET RETIREMENT ACCRETION
Recalculation of our asset retirement obligation lowered our obligation and
accretion expense in the first six months of 2004 compared to the first six
months of 2003.
GENERAL AND ADMINISTRATIVE (G&A)
Our G&A expense for the first half of 2004 compared to the first half of
2003 did not change significantly, but the decrease in volumes from the same
periods caused our G&A expense per BOE for the first half of 2004 to increase to
$2.22 from $2.03 for the first half 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
six months ended June 30, 2004, compared to the six months ended June 30, 2003.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Net cash provided by our operating activities for the six months ended June
30, 2004, was $31.6 million, an increase of $3.9 million from $27.7 million
provided by our operating activities during the comparable 2003 period. Our cash
balance as of June 30, 2004, was $7.8 million, an increase of $5.5 million from
our cash balance of $2.3 million held at December 31, 2003.
DEBT
Our long-term debt at December 31, 2003, and June 30, 2004, consisted of
the following:
December 31, June 30,
(Dollars in thousands) 2003 2004
------------ -------------
10.25% Senior Subordinated Notes due August 1, 2008 $ 127,150 $ 127,150
Credit Facility due March 31, 2007 132,900 128,049
Credit Facility due March 31, 2006 - 25,000
Credit Facility due September 30, 2006 17,000 15,786
Capital Lease Agreement 13,827 12,159
Ford Credit 43 36
------------ -------------
Outstanding Debt 290,920 308,180
Less Current Portion 5,776 5,776
------------ -------------
Total Long-Term Debt $ 285,144 $ 302,404
============ =============
CREDIT FACILITY
On July 21, 2004, the Company executed the Fourth Amendment to the credit
Agreement that modified the definitions to delete any reference to CGI. (See
Note 8.)
On April 14, 2004, we executed the Third Amendment to our secured credit
agreement that added a $25.0 million term credit facility that matures on March
31, 2006. The amendment also extended the maturity date of the original facility
to March 31, 2007. Borrowings under the term credit facility have margins of
5.5% on LIBOR loans and 3% on prime loans. On April 14, 2004, we drew $25
million on the new term credit facility and paid down the balance of the
original revolving credit facility. Borrowings under the revolving credit
facility bear interest based on an annual rate equal to the rate at which
eurodollar deposits for one, two, three or six months are offered by the lead
bank plus an applicable margin ranging from 150 to 250 basis points or the lead
bank's reference rate plus an applicable margin ranging from 25 to 50 basis
points. The effective rate of interest on our borrowings under our credit
facility was 4.2% at June 30, 2004. The borrowing base of our credit facility
was $150.0 million on June 30, 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.
A cash dividend paid to our shareholders on July 19, 2004, was funded with
short-term borrowings under our credit facility and we used corporate funds to
acquire $7.65 million of our 10-1/4% Senior Subordinated Notes on July 21, 2004.
(See Note 8.)
At August 13, 2004, the outstanding balances were $137.0 million and $25.0
million on the original revolving credit facility and the term loan,
respectively.
On October 22, 2003, our subsidiary, CGI, established a new $35.0 million
secured credit facility consisting of a senior secured term loan facility of up
to $25.0 million and a senior revolving credit facility of up to $10.0 million.
On that date, CGI ceased to be a guarantor of our obligations under our credit
agreement. 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 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 June 30,
2004, the outstanding balance on CGI's credit facility was $15.8 million. On
July 21, 2004, but effective May 31, 2004, we sold all of the outstanding
capital stock of CGI to our shareholders. Section 4.10 of our indenture requires
that within 360 days after the receipt of any net proceeds from any asset sale,
we may apply such net proceeds, at our option, in any order or combination, (a)
to reduce Senior Debt or Guarantor Senior Debt, (b) to make permitted
investments, (c) to make investments in interests in oil and gas businesses or
(d) to make capital expenditures in respect of our Restricted Subsidiaries' oil
and gas business. Pending the final application of any such net proceeds, we may
temporarily reduce indebtedness under our revolving credit facility or otherwise
invest such net proceeds in any manner that is not prohibited by the indenture.
We intend to use the proceeds from the sale of the stock of CGI to fund our
drilling program for the next six months.
Our credit agreement contains certain financial and other covenants. At
June 30, 2004, we were in compliance with all of the covenants.
CAPITAL EXPENDITURES
Our 2004 capital expenditures budget, exclusive of acquisitions, is $83.3
million, of which $6.7 million is dedicated to our Cedar Hills Field secondary
recovery project. During the six months ended June 30, 2004, we incurred $41.9
million of capital expenditures, compared to $52.7 million during the comparable
six- month period of 2003. Of the total $41.9 million of capital expenditures,
we expended $27.2 million in exploration and development, $5.0 million on
secondary recovery operations, and $5.3 million on leasing. We used the majority
of the remaining $4.4 million for additions to our gas gathering systems. The
$10.8 million decrease in our capital expenditures during the first six months
of 2004 compared to the first six months of 2003 was the result of our
completion of the high-pressure air injection project in the Cedar Hills Field
in our Rocky Mountain Region. We expect to fund the remainder of our 2004
capital budget through cash flows from operations and borrowings under our
credit facility. At August 13, 2004, we had $13.0 million of availability at 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 or minus a fixed
basis. Under the collars and floors, if the market price of crude oil exceeds
the ceiling strike price or falls below the floor strike price, then we receive
the fixed price ceiling or floor. If the market price is between the floor
strike price and the ceiling strike price, we receive market price.
These contracts allow us to predict with greater certainty the effective
oil and gas prices to be received for hedged production and benefit operating
cash flows and earnings when market prices are less than the fixed prices
provided in the contracts. However, we will not benefit from market prices that
are higher than the fixed, or ceiling prices in the contracts for hedged
production.
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 June 30, 2004, we had collars and/or
floors in place covering approximately 1.0 million barrels of crude oil
representing approximately 50% of our forecasted production through December 30,
2004. At June 30, 2004, we had a mark-to-market unrealized loss of approximately
$645,700 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 June 30, 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. The 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 June
30, 2004:
2004 2005 2006 2007
------- -------- ------- -------
Natural Gas Physical Delivery Contracts:
Contract Volumes (MMBtu) 300,000 600,000 600,000 600,000
Weighted Average Fixed Price per MMBtu $ 4.83 $ 4.53 $ 4.47 $ 4.49
Crude Oil Basis Contracts: Contract Contract
Month Volumes Price
--------- --------- ---------
Aug 2004 62,000 $ 37.72
Sep 2004 30,000 $ 41.09
Crude Oil Collars and Floors for 2004: Contract Weighted-average
Volumes (Bbls) Fixed Price per Bbl
-------------------- -------------------
July - Oct, Floor 602,000 $ 22.00
Sept - Oct, Floor 200,000 $ 24.00
Nov - Dec, Floor 230,000 $ 24.50
--------------------
1,032,000
====================
July - Oct, Ceiling 460,000 $ 36.00
Nov - Dec, Ceiling 230,000 $ 45.00
--------------------
690,000
====================
The following table represents our fixed basis contracts in place at June
30, 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
-------------- ---------------- -------
Aug 2004 62,000 $ 37.72
Sep 2004 30,000 $ 41.09
TRADING
In the first half 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 June 30, 2004, we had no open trading
derivative contracts in place.
INTEREST RATE RISK
Our exposure to changes in interest rates relates primarily to long-term
debt obligations. We manage our interest rate exposure by limiting our
variable-rate debt to a certain percentage of total capitalization and by
monitoring the effects of market changes in interest rates. We may utilize
interest rate derivatives to alter interest rate exposure in an attempt to
reduce interest rate expense related to existing debt issues. Interest rate
derivatives are used solely to modify interest rate exposure and not to modify
the overall leverage of the debt portfolio. The fair value of long-term debt is
estimated based on quoted market prices and management's estimate of current
rates available for similar issues. The following table itemizes our long-term
debt maturities and the weighted-average interest rates by maturity date.
June 30,
2004
(Dollars in thousands) 2004 2005 2006 2007 Thereafter Total Fair Value
- --------------------------------- ---------- ---------- ---------- ----------- ----------- ---------- -----------
Fixed rate debt:
Senior subordinated
notes
Principal amount $ - $ - $ - $ - $ 119,500 $ 119,500 $ 123,085
Weighted-average
interest rate 10.25% 10.25% 10.25% 10.25% 10.25%
- --------------------------------- ---------- ---------- ---------- ----------- ----------- ---------- -----------
Variable rate debt:
Credit facility-Tranch A
Principal amount $ - $ - $ - $ 128,049 $ - $ 128,049 $ 128,049
Weighted-average
interest rate 4.2% 4.2% 4.2% 4.2% 4.2%
- --------------------------------- ---------- ---------- ---------- ----------- ----------- ---------- -----------
Variable rate debt:
Credit facility-Tranch B
Principal amount $ - $ - $ 25,000 $ - $ - $ 25,000 $ 25,000
Weighted-average
interest rate 7.0% 7.0% 7.0% 7.0% 7.0%
- --------------------------------- ---------- ---------- ---------- ----------- ----------- ---------- -----------
Variable rate debt:
Capital lease agreement
Principal amount $ 1,668 $ 3,336 $ 3,336 $ 3,336 $ 483 $ 12,159 $ 12,159
Weighted-average
interest rate 4.0% 4.0% 4.0% 4.0% 4.0%
- --------------------------------- ---------- ---------- ---------- ----------- ----------- ---------- -----------
Variable rate debt:
Ford Credit agreement
Principal amount $ 4 $ 13 $ 11 $ 8 $ - $ 36 $ 36
Weighted-average
interest rate 5.5% 5.5% 5.5% 5.5% 5.5%
- --------------------------------- ---------- ---------- ---------- ----------- ----------- ---------- -----------
The Senior subordinated notes were reduced by $7.65 million purchased by CRI and the credit facility was
adjusted for the sale of CGI on July 21, 2004.
ITEM 4. CONTROLS AND PROCEDURES
The Securities and Exchange Commission rules require that we maintain
disclosure controls and procedures to provide reasonable assurance that we are
able to record, process, summarize and report the information required in
quarterly and annual reports filed under the Securities Exchange Act of 1934.
While we believe that our existing disclosure controls and procedures are
reasonably adequate to accomplish these objectives, we intend to continue to
examine, refine and formalize our disclosure controls and procedures and to
maintain ongoing developments in this area.
As of the end of the period covered by this report, our principal executive
officer and principal financial officer have evaluated our disclosure controls
and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act
of 1934) and concluded that our disclosure controls and procedures are
effective.
There have been no significant changes in our internal controls or in other
factors that could significantly affect these controls, since the date the
controls were evaluated.
PART II. Other Information
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are a party to litigation or other legal proceedings
that we consider to be a part of the ordinary course of our business. We are not
involved in any legal proceedings nor are we a party to any pending or
threatened claims that could reasonably be expected to have a material adverse
effect on our financial condition or results of operations.
ITEM 2. 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:
DESCRIPTION AND METHOD OF FILING
3.1 Amended and Restated Certificate of Incorporation of Continental
Resources, Inc. [3.1](1)
3.2 Amended and Restated Bylaws of Continental Resources, Inc. [3.2](1)
4.1 Fourth Amended and Restated Credit Agreement dated March 28, 2002,
among the Registrant, Union Bank of California, N.A., Guaranty Bank,
FSB and Fortis Capital Corp. [10.1](3)
4.1.1 First Amendment to the Revolving Credit Agreement dated June 12, 2003,
among the Registrant, Union Bank of California, N.A., Guaranty Bank,
FSB and Fortis Capital Corp. [10.1](4)
4.1.2 Second Amendment to the Revolving Credit Agreement dated October 22,
2003, among the Registrant, Union Bank of California, N.A., Guaranty
Bank, FSB and Fortis Capital Corp. [10.1](5)
4.1.3 Third Amendment to the Revolving Credit Agreement dated April 14,
2004, among the Registrant, Union Bank of California, N.A., Guaranty
Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc.
[10.1](7)
4.1.4 * Fourth Amendment to the Revolving Credit Agreement dated July 21,
2004, among the Registrant, Union Bank of California, N.A., Guaranty
Bank, FSB, Fortis Capital Corp., and The Royal Bank of Scotland plc.
4.2 Indenture dated as of July 24, 1998, between Continental Resources,
Inc. as Issuer, the Subsidiary Guarantors named therein and the United
States Trust Company of New York, as Trustee. [4.2](1)
10.1 Unlimited Guaranty Agreement dated March 28, 2002. [10.2](3)
10.2 Security Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent. [10.3](3)
10.3 Stock Pledge Agreement dated March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent. [10.4](3)
10.4 + Continental Resources, Inc. 2000 Stock Option Plan. [10.6](2)
10.5 + Form of Incentive Stock Option Agreement. [10.7](2)
10.6 + Form of Non-Qualified Stock Option Agreement. [10.8](2)
10.7 Collateral Assignment of Contracts dated March 28, 2002, between
Registrant and Guaranty Bank, FSB, as Agent. [10.5](3)
10.8 Stock Purchase Agreement dated July 19, 2004, among the Registrant,
Harold Hamm and Bert H. Mackie, as Trustee of the Harold Hamm DST
Trust and the Harold Hamm HJ Trust, providing for the sale of all of
the outstanding capital stock of Continental Gas, Inc. to the
shareholders of the Registrant [10](6)
12.1 * Statement re computation of ratio of debt to Adjusted EBITDA.
12.2 * Statement re computation of ratio of earnings 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 current report on Form 8-K dated April 11, 2002. The
exhibit number is indicated in brackets and is incorporated herein by
reference.
(4) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended June 30, 2003. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(5) Filed as an exhibit to current report on Form 8-K dated October 22, 2003.
The exhibit number is indicated in brackets and is incorporated herein by
reference.
(6) Filed as an exhibit to the Registrant's current report on Form 8-K dated
August 5, 2004. The exhibit number is indicated in brackets and is
incorporated herein by reference.
(7) Filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
fiscal quarter ended March 31, 2004. The exhibit number is indicated in
brackets and is incorporated herein by reference.
(b) REPORTS ON FORM 8-K:
On August 4, 2004, the Registrant filed a current report on Form 8-K
to report under Item 2. Acquisition or Disposition of Assets the
Registrant's sale of all the issued and outstanding capital stock of
Continental Gas, Inc. to the Registrant's shareholders.
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: August 13, 2004 By: /S/ ROGER V. CLEMENT
Roger V. Clement
Senior Vice President and Chief
Financial Officer
EXHIBIT INDEX
Exhibit
No. Description Method of Filing
--- ----------- ----------------
3.1 Amended and Restated Certificate of Incorporated herein by reference
Incorporation of Continental Resources,
Inc.
3.2 Amended and Restated Bylaws of Incorporated herein by reference
Continental Resources, Inc.
4.1 Fourth Amended and Restated Credit Incorporated herein by reference
Agreement dated March 28, 2002, among
the Registrant, Union Bank of
California, N.A., Guaranty Bank, FSB and
Fortis Capital Corp.
4.1.1 First Amendment to the Revolving Credit Incorporated herein by reference
Agreement dated June 12, 2003, among the
Registrant, Union Bank of California,
N.A., Guaranty Bank, FSB and Fortis
Capital Corp.
4.1.2 Second Amendment to the Revolving Credit Incorporated herein by reference
Agreement dated October 22, 2003, among
the Registrant, Union Bank of
California, N.A., Guaranty Bank, FSB and
Fortis Capital Corp.
4.1.3 Third Amendment to the Revolving Credit Incorporated herein by reference
Agreement dated April 14, 2004, among
the Registrant, Union Bank of
California, N.A., Guaranty Bank, FSB,
Fortis Capital Corp., and The Royal Bank
of Scotland plc.
4.1.4 Fourth Amendment to the Revolving Credit Filed herewith electronically
Agreement dated July 21, 2004, among the
Registrant, Union Bank of California,
N.A., Guaranty Bank, FSB, Fortis Capital
Corp., and The Royal Bank of Scotland
plc.
4.2 Indenture dated as of July 24, 1998, Incorporated herein by reference
between Continental Resources, Inc. as
Issuer, the Subsidiary Guarantors named
therein and the United States Trust
Company of New York, as Trustee.
10.1 Unlimited Guaranty Agreement dated March Incorporated herein by reference
28, 2002.
10.2 Security Agreement dated March 28, 2002, Incorporated herein by reference
between Registrant and Guaranty Bank,
FSB, as Agent.
10.3 Stock Pledge Agreement dated March 28, Incorporated herein by reference
2002, between Registrant and Guaranty
Bank, FSB, as Agent.
10.4 Continental Resources, Inc. 2000 Stock Incorporated herein by reference
Option Plan.
10.5 Form of Incentive Stock Option Incorporated herein by reference
Agreement.
10.6 Form of Non-Qualified Stock Option Incorporated herein by reference
Agreement.
10.7 Collateral Assignment of Contracts dated Incorporated herein by reference
March 28, 2002, between Registrant and
Guaranty Bank, FSB, as Agent.
10.8 Stock Purchase Agreement dated July 19, Incorporated herein by reference
2004, among the Registrant, Harold Hamm
and Bert H. Mackie, as Trustee of the
Harold Hamm DST Trust and the Harold
Hamm HJ Trust, providing for the sale of
all of the outstanding capital stock of
Continental Gas, Inc. to the
shareholders of the Registrant
12.1 Statement re computation of ratio of Filed herewith electronically
debt to Adjusted EBITDA.
12.2 Statement re computation of ratio of Filed herewith electronically
earnings to fixed charges.
31.1 Certification pursuant to section 302 of Filed herewith electronically
the Sarbanes-Oxley Act of 2002 - Chief
Executive Officer
31.2 Certification pursuant to section 302 of Filed herewith electronically
the Sarbanes-Oxley Act of 2002 - Chief
Financial Officer