<PAGE>
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 9, 1998
REGISTRATION NO. 333-61547
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------------
AMENDMENT NO. 2
TO
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
------------------------
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C> <C>
OKLAHOMA 1311 73-0767549
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of Classification Code Number) Identification
incorporation or organization) No.)
</TABLE>
--------------------------
302 NORTH INDEPENDENCE ROGER CLEMENT
SUITE 300 302 NORTH INDEPENDENCE
ENID, OKLAHOMA 73701 SUITE 300
(580) 233-8955 ENID, OKLAHOMA 73701
(Address, including Zip Code, and (580) 233-8955
telephone (Name, address, including Zip
number, including area code, of Code, and telephone number,
registrant's principal executive including area code, of agent for
offices) service)
--------------------------
COPIES TO:
THEODORE M. ELAM, ESQ.
MCAFEE & TAFT A PROFESSIONAL CORPORATION
TENTH FLOOR, TWO LEADERSHIP SQUARE
OKLAHOMA CITY, OKLAHOMA 73102
(405) 235-9621
--------------------------
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:
AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE.
--------------------------
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box: / /
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration number of the earlier effective
registration statement for the same offering. / /
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement under the earlier effective registration statement for
the same offering. / /
--------------------------
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
PROPOSED MAXIMUM PROPOSED MAXIMUM
TITLE OF EACH CLASS OF AMOUNT TO OFFERING PRICE AGGREGATE AMOUNT OF
SECURITIES TO BE REGISTERED BE REGISTERED PER UNIT(1) OFFERING PRICE(1) REGISTRATION FEE
<S> <C> <C> <C> <C>
10 1/4% Senior Subordinated Notes due
2008................................ $150,000,000 100% $150,000,000 $44,250(1)
</TABLE>
(1) Estimated solely for the purpose of computing the registration fee in
accordance with Rule 457(f)(2).
--------------------------
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8 OF THE
SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8, MAY
DETERMINE.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
ADDITIONAL REGISTRANTS
CONTINENTAL GAS, INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C> <C>
OKLAHOMA 1311 73-1363922
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of Classification Code Number) Identification
incorporation or organization) Number)
</TABLE>
302 NORTH INDEPENDENCE, SUITE 300
ENID, OKLAHOMA 73701
(580) 233-8955
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
ROGER CLEMENT
SENIOR VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER
302 NORTH INDEPENDENCE, SUITE 300
ENID, OKLAHOMA 73701
(580) 233-8955
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
CONTINENTAL CRUDE CO.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C> <C>
OKLAHOMA 1311 73-1541220
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of Classification Code Number) Identification
incorporation or organization) Number)
</TABLE>
302 NORTH INDEPENDENCE, SUITE 300
ENID, OKLAHOMA 73701
(580) 233-8955
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
ROGER CLEMENT
SENIOR VICE PRESIDENT, TREASURER
AND CHIEF FINANCIAL OFFICER
302 NORTH INDEPENDENCE, SUITE 300
ENID, OKLAHOMA 73701
(580) 233-8955
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
<PAGE>
PRELIMINARY PROSPECTUS (SUBJECT TO COMPLETION)
INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY
OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES
EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES
IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR
TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH STATE.
<PAGE>
ISSUED NOVEMBER 9, 1998
OFFER TO EXCHANGE
ALL OUTSTANDING
10 1/4% SENIOR SUBORDINATED NOTES DUE 2008
($150,000,000 PRINCIPAL AMOUNT OUTSTANDING)
FOR
10 1/4% SENIOR SUBORDINATED NOTES DUE 2008
WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT
OF
CONTINENTAL RESOURCES, INC.
----------------
The Exchange Offer will expire at 5:00 p.m., New York City time, on December
, 1998, unless extended (if and as extended, the "Expiration Date"). The
Company will accept for exchange any and all validly tendered Old Notes on or
prior to 5:00 p.m., New York City time, on the Expiration Date. Tenders of Old
Notes may be withdrawn at any time prior to 5:00 p.m., New York City time, on
the Expiration Date. See "The Exchange Offer."
--------------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 15 FOR A DISCUSSION OF CERTAIN FACTORS
WHICH INVESTORS SHOULD CONSIDER IN CONNECTION WITH THE EXCHANGE OFFER AND AN
INVESTMENT IN THE NEW NOTES OFFERED HEREBY.
--------------------------
Continental Resources, Inc., an Oklahoma corporation (the "Company" or
"Continental"), hereby offers (the "Exchange Offer"), upon the terms and subject
to the conditions set forth in this Prospectus and the accompanying Letter of
Transmittal to exchange $1,000 principal amount of its 10 1/4% Senior
Subordinated Notes Due 2008 (the "New Notes"), which have been registered under
the Securities Act of 1933, as amended (the "Securities Act"), pursuant to a
Registration Statement of which this Prospectus is a part, for each $1,000
principal amount of its outstanding 10 1/4% Senior Subordinated Notes Due 2008
(the "Old Notes"), of which an aggregate of $150,000,000 in principal amount was
outstanding as of November 6, 1998. The New Notes and the Old Notes are
collectively referred to herein as the "Notes."
(COVER CONTINUED ON PAGE II.)
--------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
--------------------------
Interest on the New Notes will be paid in cash at a rate of 10 1/4% per
annum on each February 1 and August 1, commencing February 1, 1999. The New
Notes may be redeemed at the option of the Company, in whole or in part, at any
time on or after August 1, 2003 at 105.125% of their principal amount, plus
accrued interest, declining ratably to 100% of their principal amount, plus
accrued interest, on or after August 1, 2006. In addition, at any time prior to
August 1, 2001, the Company may redeem up to 35% of the aggregate principal
amount of the New Notes with the net proceeds of one or more sales of capital
stock of the Company, at 110.250% of their principal amount, plus accrued
interest; provided that after any such redemption at least $97.5 million
aggregate principal amount of Notes remains outstanding. See "Description of
Notes."
This Prospectus, together with the Letter of Transmittal, is being sent to
all registered holders of Old Notes as of November 6, 1998. As of such date, a
nominee for The Depository Trust Company was the only registered holder of the
Old Notes.
The Company will not receive any proceeds from this Exchange Offer. No
dealer-manager is being used in connection with this Exchange Offer. See "Use of
Proceeds" and "Plan of Distribution."
WE ARE NOT ASKING YOU FOR A PROXY AND YOU ARE REQUESTED NOT TO SEND US A
PROXY.
--------------------------
THE DATE OF THIS PROSPECTUS IS , 1998.
<PAGE>
The New Notes will be general unsecured obligations of the Company entitled
to the benefits of the indenture dated July 24, 1998 among the Company, its two
wholly owned subsidiaries, Continental Gas, Inc. and Continental Crude Co., and
certain of its future subsidiaries (the "Subsidiary Guarantors") and the United
States Trust Company, as trustee (the "Indenture"), governing the Notes. The New
Notes will be (i) subordinated in right of payment to all existing and future
indebtedness of the Company and its subsidiaries as permitted under the
Indenture ("Senior Debt"), including indebtedness under the Company's revolving
credit facility with Bank One, Oklahoma, N.A. (the "Credit Facility"), (ii) rank
equally in right of payment with the Old Notes and all other senior indebtedness
of the Company, and (iii) rank senior in right of payment to all other
subordinated indebtedness of the Company. Payment of principal, premium, if any,
and interest on the New Notes will be unconditionally guaranteed, jointly and
severally, on a senior unsecured basis by the Subsidiary Guarantors. The Old
Notes are, and the New Notes will be, (i) subordinated in right of payment to
all existing and future Senior Debt, (ii) will rank equally in right of payment
to all other senior debt and (iii) will rank senior in right of payment to all
other subordinated indebtedness of the Subsidiary Guarantors. As of June 30,
1998, the Company had, on a consolidated basis, $3.8 million of Senior Debt
(exclusive of $75.0 million of unused commitments under the Credit Facility),
all of which ranks senior to the Notes, the Company had no senior subordinated
debt outstanding (exclusive of the Notes), and the Subsidiary Guarantors had no
indebtedness outstanding other than the guarantees of the Credit Facility and
the Subsidiary Guarantees. The form and terms of the New Notes are identical in
all material respects to the form and terms of the Old Notes except that the New
Notes have been registered under the Securities Act. Any Old Notes not tendered
and accepted in the Exchange Offer will remain outstanding and will be entitled
to all the rights and preferences and will be subject to the limitations
applicable thereto under the Indenture. Following consummation of the Exchange
Offer, the holders of the Old Notes will continue to be subject to the existing
restrictions upon transfer thereof and the Company will have no further
obligation to such holders to provide for the registration under the Securities
Act of the Old Notes held by them. Following the completion of the Exchange
Offer, none of the Notes will be entitled to the contingent increase in interest
rate provided pursuant to the Old Notes. The Exchange Offer is being made
pursuant to the terms of the registration rights agreement (the "Registration
Rights Agreement") entered into between the Company and Chase Securities, Inc.
(the "Initial Purchaser") pursuant to the terms of the Purchase Agreement dated
July 21, 1998 between the Company and the Initial Purchaser. See "The Exchange
Offer--Purpose and Effect of the Exchange Offer."
Based on interpretations by the staff of the Securities and Exchange
Commission (the "Commission") set forth in no-action letters issued to third
parties, the Company believes the New Notes issued pursuant to the Exchange
Offer in exchange for Old Notes may be offered for resale, resold and otherwise
transferred by any holder thereof (other than broker-dealers, as set forth
below, and any such holder that is an "affiliate" of the Company within the
meaning of Rule 405 under the Securities Act) without compliance with the
registration and prospectus delivery provisions of the Securities Act, provided
that such New Notes are acquired in the ordinary course of such holder's
business and that such holder has no arrangement or understanding with any
person to participate in the distribution of such New Notes. Any holder who
tenders in the Exchange Offer with the intention to participate, or for the
purpose of participating, in a distribution of the New Notes or who is an
affiliate of the Company may not rely upon such interpretations by the staff of
the Commission and, in the absence of an exemption therefrom, must comply with
the registration and prospectus delivery requirements of the Securities Act in
connection with any secondary resale transaction. Holders of Old Notes wishing
to accept the Exchange offer must represent to the Company in the Letter of
Transmittal that such conditions have been met.
Each broker-dealer (other than an affiliate of the Company) that receives
New Notes for its own account pursuant to the Exchange Offer as a result of
market making activities must acknowledge that it will deliver a prospectus
meeting the requirements of the Securities Act in connection with any resale of
such New Notes. The Letter of Transmittal states that by so acknowledging and by
delivering a prospectus, a broker-dealer will not be deemed to admit that it is
an "underwriter" within the meaning of the Securities Act. This Prospectus, as
it may be amended or supplemented from time to time, may be used by a broker-
dealer in connection with resales of New Notes received in exchange for Old
Notes where such Old Notes were acquired by such broker-dealer as a result of
market-making activities or other trading activities. The Company has agreed
that, for a period of 180 days after the last date Old Notes are accepted for
exchange pursuant to the Exchange Offer (the "Exchange Date"), it will make this
Prospectus available to any broker-dealer for use in connection with any such
resale. See "Plan of Distribution." Any broker-dealer who is an affiliate of the
Company may not rely on such no-action letters and must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with a secondary resale transaction.
ii
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Periodic Reports........................................................................................... iv
Available Information...................................................................................... iv
Summary.................................................................................................... 1
Risk Factors............................................................................................... 13
The Exchange Offer......................................................................................... 21
Unaudited Pro Forma Consolidated Financial Statements...................................................... 29
Selected Consolidated Financial Data....................................................................... 34
Management's Discussion and Analysis of Financial Condition and Results of Operations...................... 36
Business and Properties.................................................................................... 45
Management................................................................................................. 62
Summary Compensation Table................................................................................. 64
Certain Relationships and Related Transactions............................................................. 65
Principal Shareholders..................................................................................... 66
Description of Credit Facility............................................................................. 66
Description of Notes....................................................................................... 67
Material United States Tax Consequences.................................................................... 99
Plan of Distribution....................................................................................... 103
Legal Matters.............................................................................................. 104
Experts.................................................................................................... 104
Glossary of Terms.......................................................................................... 105
Index to Financial Statements.............................................................................. F-1
</TABLE>
------------------------
NO PERSON IS AUTHORIZED IN CONNECTION WITH THE OFFERING MADE HEREBY TO GIVE
ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS
OR THE ACCOMPANYING LETTER OF TRANSMITTAL AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATION NOT CONTAINED HEREIN MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY.
------------------------
THE EXCHANGE OFFER IS NOT BEING MADE TO, NOR WILL THE COMPANY ACCEPT
SURRENDERS FOR EXCHANGE FROM, HOLDERS OF OLD SHARES IN ANY JURISDICTION IN WHICH
THIS EXCHANGE OFFER OR THE ACCEPTANCE THEREOF WOULD NOT BE IN COMPLIANCE WITH
THE SECURITIES OR BLUE SKY LAWS OF SUCH JURISDICTION. NEITHER THE DELIVERY OF
THIS PROSPECTUS NOR THE ACCOMPANYING LETTER OF TRANSMITTAL, NOR ANY EXCHANGE
MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES IMPLY THAT THE INFORMATION HEREIN
IS CORRECT AS OF ANY DATE SUBSEQUENT TO THE DATE HEREOF.
iii
<PAGE>
PERIODIC REPORTS
The Company has agreed that, whether or not required by the rules and
regulations of the Commission, so long as any Old Notes or New Notes are
outstanding, the Company will file with the Commission all such reports and
other information as it would be required to file with the Commission by Section
13(a) or 15(d) under the Securities Exchange Act of 1934 (the "Exchange Act") as
if it were subject thereto. The Company will supply the Trustee appointed with
respect to the Old Notes or New Notes and each holder of Old Notes or New Notes,
without cost, copies of such report and other information.
------------------------
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on Form
S-4 (the "Registration Statement"), which term includes all amendments,
exhibits, annexes and schedules thereto) pursuant to the Securities Act, and the
rules and regulations promulgated thereunder, covering the New Notes being
offered hereby. This Prospectus does not contain all the information set forth
in the Registration Statement, certain parts of which are omitted in accordance
with the rules and regulations of the Commission. Statements made in this
Prospectus as to the contents of any contracts, agreement or other document
referred to are not necessarily complete. With respect to each such contract,
agreement or other document filed as an exhibit to the Registration Statement,
reference is made to the exhibit for a more complete description of the matter
involved, and each such statement shall be deemed qualified in its entirety by
such reference.
The Company is not currently subject to the informational reporting
requirements of the Securities Exchange Act of 1934, as amended. Upon
effectiveness of a registration statement with respect to an exchange offer or a
shelf registration statement with respect to resales of the Notes (see
"Description of the Notes--Registration Rights"), the Company will become
subject to the informational requirements of the Exchange Act.
------------------------
THIS PROSPECTUS INCLUDES "FORWARD-LOOKING STATEMENTS". ALL STATEMENTS
REGARDING THE COMPANY'S AND ITS SUBSIDIARIES' EXPECTED FINANCIAL POSITION,
BUSINESS AND FINANCING PLANS ARE FORWARD-LOOKING STATEMENTS. ALTHOUGH THE
COMPANY AND ITS SUBSIDIARIES BELIEVE THAT THE EXPECTATIONS REFLECTED IN SUCH
FORWARD-LOOKING STATEMENTS ARE REASONABLE, THEY CAN GIVE NO ASSURANCE THAT SUCH
EXPECTATIONS WILL PROVE TO HAVE BEEN CORRECT. IMPORTANT FACTORS THAT COULD CAUSE
ACTUAL RESULTS TO DIFFER MATERIALLY FROM SUCH EXPECTATIONS ("CAUTIONARY
STATEMENTS") ARE DISCLOSED IN THIS PROSPECTUS, INCLUDING, WITHOUT LIMITATION, IN
CONJUNCTION WITH THE FORWARD-LOOKING STATEMENTS INCLUDED IN THIS PROSPECTUS AND
UNDER "RISK FACTORS." ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS
ATTRIBUTABLE TO THE COMPANY, ITS SUBSIDIARIES OR PERSONS ACTING ON THEIR BEHALF
ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY THE CAUTIONARY STATEMENTS.
iv
<PAGE>
SUMMARY
THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY, AND SHOULD BE READ IN
CONJUNCTION WITH, THE MORE DETAILED INFORMATION AND FINANCIAL STATEMENTS,
INCLUDING THE NOTES THERETO, APPEARING ELSEWHERE IN THIS PROSPECTUS. UNLESS THE
CONTEXT OTHERWISE REQUIRES, ALL REFERENCES TO "CONTINENTAL" OR THE "COMPANY"
INCLUDE CONTINENTAL RESOURCES, INC. AND ITS CONSOLIDATED SUBSIDIARIES,
CONTINENTAL GAS, INC. AND CONTINENTAL CRUDE CO. PRO FORMA INFORMATION GIVES
EFFECT TO THE WORLAND FIELD ACQUISITION AND THE RELATED FINANCING, INCLUDING THE
OFFERING. THE TERM "PV-10" AND CERTAIN OTHER INDUSTRY TERMS ARE DEFINED IN THE
GLOSSARY.
THE COMPANY
Continental Resources, Inc. is engaged in the development, exploitation,
exploration and acquisition of oil and gas reserves, primarily in the Rocky
Mountains and the Mid-Continent and, to a lesser extent, in the Gulf Coast
region of Texas and Louisiana. In addition to its exploration, development and
production activities, the Company's subsidiary, Continental Gas, Inc., owns and
operates 1,000 miles of natural gas pipelines, five gas gathering systems and
three gas processing plants in its operating areas. Continental Gas, Inc. also
engages in natural gas marketing, gas pipeline construction and saltwater
disposal. Capitalizing on its growth through the drill-bit and its acquisition
strategy, on a pro forma basis the Company increased its estimated proved
reserves from 12.7 MMBoe in 1993 to 64.9 MMBoe in 1997, and increased its annual
production from 2.0 MMBoe in 1993 to 5.2 MMBoe in 1997. At December 31, 1997, on
a pro forma basis, approximately 80% of the Company's estimated proved reserves
were oil and approximately 63% of its total estimated reserves were classified
as proved developed. At June 30, 1998, the Company had interests in 1,399
producing wells of which it operated 1,114.
The Company's Rocky Mountain activities are concentrated in the Williston
Basin of North Dakota, South Dakota and Montana and in the Big Horn Basin of
Wyoming. The Company's operations in the Williston Basin are focused on the
Cedar Hills Field which the Company believes is, potentially, one of the largest
onshore discoveries in the lower 48 states since 1971. The Cedar Hills Field
represented approximately 45% of the PV-10 attributable to the Company's
estimated proved reserves at December 31, 1997, on a pro forma basis. In the
Williston Basin, the Company owns approximately 470,000 net leasehold acres and
has interests in 322 gross (252 net) wells, has identified 105 potential
drilling locations and conducts both primary drilling and enhanced recovery
operations. The Company recently expanded its activities into the Big Horn Basin
through the acquisition of producing and non-producing properties in the Worland
Field. The Company currently owns approximately 35,000 net leasehold acres in
the Big Horn Basin and has interests in 292 gross (125 net) producing wells
which, on a pro forma basis, represented approximately 10% of the PV-10
attributable to the Company's estimated proved reserves at December 31, 1997. In
the Big Horn Basin the Company has identified 164 potential drilling locations
which represent significant opportunities.
The Company's Mid-Continent activities are conducted primarily in the
Anadarko Basin of western Oklahoma, southwestern Kansas and the Texas Panhandle
and, to a lesser extent, in the Arkoma Basin of southeastern Oklahoma, and in
southern Illinois. At December 31, 1997 the Company's Anadarko Basin properties
represented approximately 95% of the PV-10 attributable to the Company's
estimated proved reserves in the Mid-Continent and approximately 36% of the
Company's total estimated proved reserves, on a pro forma basis. In the Anadarko
Basin the Company owns approximately 57,000 net leasehold acres, has interests
in 658 gross (408 net) producing wells and has identified 11 potential drilling
locations. The Company also owns leasehold interests and expects to expand its
exploration activities in the Arkoma Basin and Gulf Coast region of Texas and
Louisiana.
RECENT EVENTS
WORLAND FIELD ACQUISITION. Effective June 1, 1998 the Company completed an
$86.5 million acquisition of producing and non-producing oil and gas properties
in the Worland Field of the Big Horn Basin in
1
<PAGE>
northern Wyoming (the "Worland Field Acquisition"). Effective the same date, the
Company sold an undivided 50% interest in the Worland Field properties
(excluding inventory and certain items of equipment) to Harold Hamm, the
Company's principal shareholder for $42.6 million. See "Certain Relationships
and Related Transactions." All references to the Worland Field Acquisition and
the related properties refer only to the Company's interest in the Worland Field
properties after giving effect to the sale to the Company's principal
shareholder. See "Principal Shareholders."
Continental's interests in the Worland Field include 35,000 net leasehold
acres, on which are located 292 producing wells, 272 of which are operated by
the Company. As of December 31, 1997, the estimated net proved reserves
attributable to the Company's interest in the Worland Field properties were 32.0
MMBoe, with an estimated PV-10 of $25.4 million. The Worland Field properties
include six identified exploratory prospects for further extension of the known
producing reservoirs. The Worland Field Acquisition materially increases the
Company's proved reserves and provides additional exploration and exploitation
opportunities in areas similar to and near Continental's Williston Basin
operating area.
CEDAR HILLS FIELD TRANSACTION. On May 15, 1998, the Company entered into a
definitive agreement whereby, effective December 1, 1998, Continental and
Burlington Resources Oil & Gas Company ("Burlington"), an unrelated joint
interest owner in the Cedar Hills Field, will exchange undivided interests so
that the Company will ultimately own working interests ranging from 90% to 92%
in approximately 65,000 gross (59,000 net) leasehold acres in the northern half
of the Cedar Hills Field and the joint interest owner will acquire a substantial
portion of the Company's interests in the southern half of the Cedar Hills
Field. As a result of this agreement, the Company will enhance its ability to
unitize all interests in the northern half of the Cedar Hills Field which is
necessary in order for the Company to initiate its planned HPAI enhanced
recovery operations. See "Business--Rocky Mountains" for a discussion of a
dispute that may impede the consummation of the exchange of interests.
------------------------
The Company's principal executive and operating offices are located at Suite
300, Continental Tower, 302 North Independence, Enid, Oklahoma 73701, and its
telephone number is (580) 233-8955.
2
<PAGE>
THE EXCHANGE OFFER
TERMS OF THE EXCHANGE OFFER
This Exchange Offer is being made pursuant to the terms of the registration
rights agreement (the "Registration Rights Agreement") entered into between the
Company and Chase Securities, Inc. (the "Initial Purchaser") pursuant to the
terms of the Purchase Agreement dated July 21, 1998 between the Company and the
Placement Agents. See "The Exchange Offer--Purpose and Effect of the Exchange
Offer."
<TABLE>
<S> <C>
The Exchange Offer................ Pursuant to the Exchange Offer, $1,000 principal amount
of New Notes will be issued in exchange for each $1,000
principal amount of Old Notes that are validly tendered
and not withdrawn. As of November 6, 1998, a nominee for
The Depository Trust Company was the only registered
holder of Old Notes and $150,000,000 aggregate principal
amount of Old Notes are outstanding. Holders of Old
Notes whose Old Notes are not tendered and accepted in
the Exchange Offer will continue to hold such Old Notes
and will be entitled to all the rights and preferences
and will be subject to the limitations applicable
thereto under the Indenture governing the Old Notes and
the New Notes. Following consummation of the Exchange
Offer, the holders of Old Notes will continue to be
subject to the existing restrictions upon transfer
thereof and the Company will have no further obligation
to such holders to provide for the registration under
the Securities Act of the Old Notes held by them.
Following the completion of the Exchange Offer, none of
the Notes will be entitled to the contingent increase in
interest rate provided with respect to the Old Notes.
Resale............................ Based on interpretations by the staff of the Commission
set forth in no-action letters issued to third parties,
the Company believes the New Notes issued pursuant to
the Exchange Offer may be offered for resale, resold and
otherwise transferred by any holder thereof (other than
broker-dealers, as set forth below, and any such holder
that is an affiliate of the Company within the meaning
of Rule 405 under the Securities Act) without compliance
with the registration and prospectus delivery provisions
of the Securities Act, provided that such New Notes are
acquired in the ordinary course of such holder's
business and that such holder has no arrangement or
understanding with any person to participate in the
distribution of such New Notes. Any holder who tenders
in the Exchange Offer with the intention to participate,
or for the purpose of participating, in a distribution
of the New Notes or who is an affiliate of the Company
may not rely upon such interpretations by the staff of
the Commission and, in the absence of an exemption
therefrom, must comply with the registration and
prospectus delivery requirements of the Securities Act
in connection with any secondary resale transaction.
Failure to comply with such requirements in such
instance may result in such holder incurring liabilities
under the Securities Act for which the holder is not
indemnified by the Company. Each broker-dealer (other
than an affiliate of the
</TABLE>
3
<PAGE>
<TABLE>
<S> <C>
Company) that receives New Notes for its own account
pursuant to the Exchange Offer must acknowledge that it
will deliver a prospectus meeting the requirements of
the Securities Act in connection with any resale of such
New Notes. The Letter of Transmittal states that by so
acknowledging and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it is an
underwriter within the meaning of the Securities Act.
The Company has agreed that, for a period of 180 days
after the Exchange Date, it will make this Prospectus
available to any broker-dealer for use in connection
with any such resale. See "Plan of Distribution."
The Exchange Offer is not being made to, nor will the
Company accept surrenders for exchange from, holders of
Old Notes in any jurisdiction in which this Exchange
Offer or the acceptance thereof would not be in
compliance with the securities or blue sky laws of such
jurisdiction.
Expiration Date................... The Exchange Offer will expire at 5:00 p.m., New York
City time, on December , 1998, unless extended, in
which case the term Expiration Date shall mean the
latest date and time to which the Exchange Offer is
extended. Any extension, if made, will be publicly
announced through a release to the Dow Jones News
Service and as otherwise required by applicable law or
regulations.
Conditions to the Exchange
Offer........................... The Exchange Offer is subject to certain conditions,
which may be waived by the Company. See "The Exchange
Offer-- Conditions of the Exchange Offer." The Exchange
Offer is not conditioned upon any minimum principal
amount of Old Notes being tendered.
Procedures for Tendering
Old Notes....................... Each holder of Old Notes wishing to accept the Exchange
Offer must complete, sign and date the Letter of
Transmittal, or a facsimile thereof, in accordance with
the instructions contained herein and therein, and mail
or otherwise deliver such Letter of Transmittal, or a
facsimile thereof, together with such Old Notes and any
other required documentation to United States Trust
Company of New York, the Exchange Agent, at the address
set forth herein and therein. By executing the Letter of
Transmittal, each holder will represent to the Company
that, among other things, the New Notes acquired
pursuant to the Exchange Offer are being obtained in the
ordinary course of business of the person receiving such
New Notes, whether or not such person is the holder,
that neither the holder nor any such other person has an
arrangement or understanding with any person to
participate in the distribution of such New Notes and
that neither the holder nor any such other person is an
affiliate of the Company within the meaning of Rule 405
under the Securities Act. See "The Exchange Offer--Terms
of the Exchange Offer--Procedures for Tendering Old
Notes" and "The Exchange Offer--Terms of the Exchange
Offer--Guaranteed Delivery Procedures."
</TABLE>
4
<PAGE>
<TABLE>
<S> <C>
Special Procedures for Beneficial
Owners.......................... Any beneficial owner whose Old Notes are registered in
the name of a broker, dealer, commercial bank, trust
company or other nominee and who wishes to tender such
Old Notes in the Exchange Offer should contact such
registered holder promptly and instruct such registered
holder to tender on such beneficial owner's behalf. If
such beneficial owner wishes to tender on its own
behalf, such owner must, prior to completing and
executing the Letter of Transmittal and delivering its
Old Notes, either make appropriate arrangements to
register ownership of the Old Notes in such owner's name
or obtain a properly completed stock power from the
registered holder. The transfer of registered ownership
may take considerable time and may not be able to be
completed prior to the Expiration Date. See "The
Exchange Offer--Terms of the Exchange Offer--Procedures
for Tendering Old Notes."
Guaranteed Delivery Procedures.... Holders of Old Notes who wish to tender their Old Notes
and whose Old Notes are not immediately available or who
cannot deliver their Old Notes, the Letter of
Transmittal or any other documents required by the
Letter of Transmittal to the Exchange Agent prior to the
Expiration Date, must tender their Old Notes according
to the guaranteed delivery procedures set forth in "The
Exchange Offer--Terms of the Exchange Offer-- Guaranteed
Delivery Procedures."
Acceptance of Old Notes and
Delivery of New Notes........... Subject to certain conditions (as described more fully
in "The Exchange Offer--Conditions of the Exchange
Offer"), the Company will accept for exchange any and
all Old Notes which are properly tendered in the
Exchange Offer and not withdrawn prior to 5:00 p.m., New
York City time, on the Expiration Date. The New Notes
issued pursuant to the Exchange Offer will be delivered
as promptly as practicable following the Expiration
Date.
Withdrawal Rights................. Except as otherwise provided herein, tenders of Old
Notes may be withdrawn at any time prior to 5:00 p.m.,
New York City time, on the Expiration Date. See "The
Exchange Offer--Terms of the Exchange Offer--Withdrawal
of Tenders of Old Notes."
Material Federal Income Tax
Considerations.................. For a discussion of material federal income tax
considerations relating to the exchange of New Notes for
Old Notes, see "Material United States Tax
Consequences."
Exchange Agent.................... United States Trust Company of New York is the Exchange
Agent. The address, telephone number and facsimile
number of the Exchange Agent are set forth in "The
Exchange Offer-- Exchange Agent."
</TABLE>
5
<PAGE>
TERMS OF THE NEW NOTES
The Exchange Offer applies to all $150,000,000 aggregate principal amount of
Old Notes outstanding. The form and terms of the New Notes will be identical in
all material respects to the form and terms of the Old Notes except that the New
Notes will be registered under the Securities Act and, therefore, will not bear
legends restricting the transfer thereof. The New Notes will evidence the same
debt as the Old Notes, will be entitled to the benefits of the Indenture and
will be treated as a single class thereunder with any Old Notes that remain
outstanding. Following the Exchange Offer, none of the Notes will be entitled to
the contingent increase in interest rate provided for in accordance with the
terms of the Registration Rights Agreement which rights will terminate upon
consummation of the Exchange Offer. See "Description of Notes."
<TABLE>
<S> <C>
Issuer............................ Continental Resources, Inc.
Securities Offered................ $150,000,000 aggregate principal amount of 10 1/4%
Senior Subordinated Notes due 2008.
Maturity Date..................... August 1, 2008.
Interest Payment Dates............ February 1 and August 1 of each year, commencing on
February 1, 1999.
Mandatory Redemption.............. None.
Optional Redemption............... Except as described below, the Notes will not be
redeemable at the Company's option prior to August 1,
2003. Thereafter, the Notes will be subject to
redemption at any time at the option of the Company, in
whole or in part, at the redemption prices set forth
herein, plus accrued and unpaid interest thereon to the
applicable redemption date. In addition, prior to August
1, 2001, the Company may, at its option, on any one or
more occasions, redeem up to 35% of the original
aggregate principal amount of the Notes at a redemption
price of 110.25% of the principal amount thereof, plus
accrued and unpaid interest, if any, thereon to the
redemption date, with the net cash proceeds of one or
more public offerings of common stock of the Company;
provided that at least 65% of the original aggregate
principal amount of the Notes remains outstanding
immediately after the occurrence of such redemption. See
"Description of Notes-- Optional Redemption."
Change of Control................. Upon the occurrence of a Change of Control, (i) the
Company will have the option, at any time, on or prior
to August 1, 2003 (but in no event more than 90 days
after the occurrence of such Change of Control), to
redeem the Notes, in whole but not in part, at a
redemption price equal to 100% of the principal amount
thereof plus the Applicable Premium as of, and accrued
and unpaid interest, if any, to, the date of redemption,
and (ii) if the Company does not so redeem the Notes,
the Company will be required to offer to repurchase all
or a portion of each Holder's Notes, at an offer price
in each case equal to 101% of the aggregate principal
amount of such Notes plus accrued and unpaid interest,
if any, to the date of repurchase, and to repurchase all
Notes tendered pursuant to such offer. The Credit
Facility prohibits the Company from repurchasing any
Notes pursuant to a Change of Control offer prior to the
repayment in full of the Senior Debt under the Credit
Facility. If a Change of Control were to occur, the
Company may not have
</TABLE>
6
<PAGE>
<TABLE>
<S> <C>
sufficient available funds to purchase all Notes
tendered pursuant to the Change of Control offer after
first satisfying its obligations under the Credit
Facility or other Senior Debt that may then be
outstanding, if accelerated. The failure by the Company
to purchase all Notes tendered pursuant to the Change of
Control offer would constitute an Event of Default (as
defined). If any Event of Default occurs, the Trustee
(as defined) or holders of at least 25% in principal
amount of the Notes then outstanding may declare the
principal of and the accrued and unpaid interest on such
Notes to be due and payable immediately. However, such
repayment would be subject to certain subordination
provisions in the Indenture (as defined). See "Risk
Factors--Repurchase of Notes Upon a Change of Control
and Certain Other Events" and "Description of
Notes--Ranking and Subordination" and "--Repurchase at
the Option of Holders--Change of Control," and "--Events
of Default and Remedies."
Ranking........................... The Notes are general unsecured obligations of the
Company and are subordinated in right of payment to all
existing and future Senior Debt of the Company, which
will include borrowings under the Credit Facility. The
Notes will rank equally in right of payment with all
other senior subordinated debt of the Company and any
other indebtedness which does not expressly provide that
it is subordinated in right of payment to the Notes. As
of June 30, 1998, on a pro forma basis after giving
effect to the consummation of the Offering and the
application of the proceeds therefrom and the Worland
Field Acquisition and related financing, the aggregate
principal amount of Senior Debt outstanding would have
been approximately $3.8 million (exclusive of $75.0
million of unused commitments under the Credit Facility)
and there would have been no senior subordinated debt
outstanding (exclusive of the Notes). The Notes will
also be effectively subordinated to all secured
indebtedness of the Company, including indebtedness
under the Credit Facility. See "Capitalization,"
"Description of Notes-- Ranking and Subordination" and
"Description of Credit Facility."
Subsidiary Guarantees............. The Company's payment obligations under the Notes are
jointly, severally and unconditionally guaranteed on a
senior subordinated basis by each Restricted Subsidiary
of the Company and any future Restricted Subsidiary of
the Company. The Subsidiary Guarantees are subordinated
to all Guarantor Senior Debt of the Subsidiary
Guarantors substantially to the same extent and manner
as the Notes are subordinated to Senior Debt. At June
30, 1998, on a pro forma basis, there would have been no
Guarantor Senior Debt outstanding other than the
guarantees of the Credit Facility and the Subsidiary
Guarantees. Each Subsidiary Guarantee will be
effectively subordinated to all secured indebtedness of
the relevant Subsidiary Guarantor, including
indebtedness under the Credit Facility. See "Description
of Notes--Subsidiary Guarantees" and "Description of
Credit Facility."
</TABLE>
7
<PAGE>
<TABLE>
<S> <C>
Certain Covenants................. The Notes are issued pursuant to an indenture (the
"Indenture") containing certain covenants that, among
other things, limits the ability of the Company and its
Restricted Subsidiaries to incur additional indebtedness
and issue Disqualified Capital Stock (as defined), pay
dividends, make distributions, make investments, make
certain other Restricted Payments (as defined), enter
into certain transactions with affiliates, dispose of
certain assets, incur liens securing Indebtedness (as
defined) of any kind other than Permitted Liens (as
defined) and engage in mergers and consolidations. See
"Description of Notes--Certain Covenants."
Book-Entry; Delivery
and Form........................ Transfers of Notes between participants and The
Depository Trust Company ("DTC") will be effected in the
ordinary way in accordance with DTC rules and will be
settled in same-day funds. See "Description of the
Notes."
</TABLE>
USE OF PROCEEDS
The Company will not receive any proceeds from the issuance of the New Notes
pursuant to this Prospectus. The net proceeds from the issuance and sale of the
Old Notes were $145.9 million. The Company used $143.2 million of such net
proceeds to reduce the outstanding balance under the Credit Facility and the
balance for general corporate purposes. Advances under the Credit Facility were
used to complete the Worland Field Acquisition, for operations and for working
capital, and bore interest at variable rates for which the weighted average
annual rate at June 30, 1998, was 7.5%.
RISK FACTORS
See "Risk Factors," immediately following this Summary, for a discussion of
certain factors relating to the Company, its business and an investment in the
Notes.
8
<PAGE>
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
The following tables set forth certain historical and pro forma financial
data. The pro forma financial information gives effect to the Worland Field
Acquisition and the related financing, including the Offering, as described in
the notes to the Unaudited Pro Forma Financial Statements. The pro forma
statement of operations data give effect to the Worland Field Acquisition and
related financing, including the Offering, as if they had occurred on January 1,
1997, and the pro forma balance sheet data give effect to the Worland Field
Acquisition and related financing, including the Offering, as if they had
occurred on June 30, 1998. The pro forma financial information does not purport
to represent what the Company's results of operations would have been if the
Worland Field Acquisition and related financing, including the Offering, had
been completed on such dates nor does it indicate the future financial position
or future results of operations of the Company. The information set forth below
should be read in conjunction with "Unaudited Pro Forma Consolidated Financial
Statements," "Selected Consolidated Financial Data," "Management's Discussion
and Analysis of Financial Condition and Results of Operations," and the
Financial Statements included elsewhere herein.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------------------- ----------------------------------
PRO FORMA PRO FORMA
1995 1996 1997 1997 1997 1998 1998
--------- --------- --------- ----------- --------- ---------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and gas sales........................... $ 30,576 $ 75,016 $ 78,599 $ 88,725 $ 39,135 $ 31,291 $ 33,418
Gathering, marketing and processing......... 20,639 25,766 25,021 25,021 15,522 9,804 9,804
Oil and gas service operations.............. 6,148 6,491 6,405 6,405 3,715 3,062 3,062
--------- --------- --------- ----------- --------- ---------- -----------
Total revenues................................ 57,363 107,273 110,025 120,151 58,372 44,157 46,284
Operating costs and expenses:
Production expenses and taxes............... 7,611 19,338 20,748 25,958 10,622 9,074 10,342
Exploration expenses........................ 6,184 4,512 6,806 6,806 3,410 2,650 2,650
Gathering, marketing and processing......... 13,223 21,790 22,715 22,715 12,873 8,409 8,409
Oil and gas service operations.............. 3,680 4,034 3,654 3,654 1,855 1,825 1,825
Depreciation, depletion and amortization.... 9,614 22,876 33,354 34,930 16,713 16,483 17,935
General and administrative.................. 8,260 9,155 8,990 8,990 3,986 4,914 4,914
--------- --------- --------- ----------- --------- ---------- -----------
Total operating costs and expenses............ 48,572 81,705 96,267 103,053 49,459 43,355 46,075
--------- --------- --------- ----------- --------- ---------- -----------
Operating income.............................. 8,791 25,568 13,758 17,098 8,913 802 209
Interest income............................... 137 312 241 1,591 104 780 830
Interest expense.............................. (2,396) (4,550) (4,804) (15,684) (2,313) (5,174) (7,836)
Other income (expense), net(1)................ (411) 233 8,061 8,061 685 93 92
--------- --------- --------- ----------- --------- ---------- -----------
Income (loss) before income taxes............. 6,121 21,563 17,256 11,066 7,389 (3,499) (6,705)
Federal and state income taxes (benefit)(2)... 2,252 8,238 (8,941) (8,941) (8,941) -- --
--------- --------- --------- ----------- --------- ---------- -----------
Net income (loss)............................. $ 3,869 $ 13,325 $ 26,197 $ 20,007 $ 16,330 $ (3,499) $ (6,705)
--------- --------- --------- ----------- --------- ---------- -----------
--------- --------- --------- ----------- --------- ---------- -----------
OTHER FINANCIAL DATA:
Adjusted EBITDA(3).......................... $ 24,315 $ 53,502 $ 54,721 $ 61,447 $ 29,825 $ 20,808 $ 21,716
Net cash provided by operations............. 18,985 41,724 51,477 46,963 27,948 9,669 794
Net cash used in investing.................. (58,022) (50,619) (78,359) (116,710) (39,673) (116,132) (73,581)
Net cash provided by (used in) financing.... 37,994 10,494 24,863 99,190 8,556 106,498 64,725
Capital expenditures(4)..................... 58,226 50,341 80,937 114,838 41,678 116,534 116,534
RATIOS:
Adjusted EBITDA to interest expense......... 10.1x 11.8x 11.4x 3.9x 12.9x 4.0x 2.8x
Total debt to Adjusted EBITDA............... 1.8x 1.0x 1.5x 2.5x n/a n/a n/a
Earnings to fixed charges(5)................ 3.6x 5.7x 4.6x 1.7x 4.2x n/a n/a
</TABLE>
9
<PAGE>
<TABLE>
<CAPTION>
AT JUNE 30, 1998
----------------------
ACTUAL PRO FORMA
--------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................................................................ $ 1,336 $ 2,114
Total assets............................................................................. 257,863 247,613
Long-term debt, including current maturities............................................. 164,052 153,802
Stockholders' equity..................................................................... 74,765 74,765
</TABLE>
- --------------------------
(1) In 1997, other income includes $7.5 million resulting from the settlement of
certain litigation matters.
(2) Effective June 1, 1997, the Company elected to be treated as a S Corporation
for federal income tax purposes. The conversion resulted in the elimination
of the Company's deferred income tax assets and liabilities existing at May
31, 1997, and, after being netted against the then existing tax provision,
resulted in a net income tax benefit to the Company of $8.9 million.
(3) Adjusted EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion, amortization and exploration expense, excluding
proceeds from litigation settlements. Adjusted EBITDA is not a measure of
cash flow as determined by generally accepted accounting principles
("GAAP"). Adjusted EBITDA should not be considered as an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with GAAP or as an indicator of a company's operating performance or
liquidity. Certain items excluded from Adjusted EBITDA are significant
components in understanding and assessing a company's financial performance,
such as a company's cost of capital and tax structure, as well as historic
costs of depreciable assets, none of which are components of Adjusted
EBITDA. The Company's computation of Adjusted EBITDA may not be comparable
to other similarly titled measures of other companies. The Company believes
that Adjusted EBITDA is a widely followed measure of operating performance
and may also be used by investors to measure the Company's ability to meet
future debt service requirements, if any. Even though the volume of oil and
gas produced by the Company during the six months ended June 30, 1998, on an
actual and pro forma basis, was greater than in the comparable period in
1997, the Company's Adjusted EBITDA for the 1998 period was less than in
1997. The decrease in Adjusted EBITDA for the 1998 period was attributable
to declines in oil and gas prices. Adjusted EBITDA does not give effect to
the Company's exploration expenditures, which are largely discretionary by
the Company and which, to the extent expended, would reduce cash available
for debt service, repayment of indebtedness and dividends.
(4) Capital expenditures include costs related to acquisitions of producing oil
and gas properties.
(5) For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income before taxes from continuing operations, plus fixed
charges. Fixed charges consist of interest expense and amortization of costs
incurred in the Offering. For the six months ended June 30, 1998, earnings
were insufficient to cover fixed charges by $3.5 million. On a pro forma
basis for the six months ended June 30, 1998, earnings were insufficient to
cover fixed charges by $7.1 million.
10
<PAGE>
SUMMARY RESERVE AND OPERATING DATA
The following tables set forth summary information with respect to estimated
proved oil and gas reserves and certain operating data as of December 31, 1995,
1996, 1997 and June 30, 1997 and 1998 and on a pro forma basis as of December
31, 1997 and June 30, 1998 to give effect to the Worland Field Acquisition. See
"Risk Factors," "Management's Discussion and Analysis of Financial Condition and
Results of Operations," "Business and Properties" "Reserve Engineers" and the
Financial Statements included elsewhere herein.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
PRO
FORMA
1995 1996 1997 1997(1)
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES (at December 31):
Oil and condensate (MBbl)......................................... 17,501 19,492 24,719 51,967
Natural gas (MMcf)................................................ 54,820 50,535 49,378 77,848
Oil equivalents (MBoe)............................................ 26,638 27,915 32,949 64,942
Percent oil....................................................... 65.7% 69.8% 75.0% 80.0%
Percentage proved developed....................................... 80.3% 84.0% 83.0% 63.0%
PRODUCT PRICES (at December 31)(2):
Oil and condensate (per Bbl)(3)................................... $ 23.00 $ 23.00 $ 18.06 $ 14.59
Natural gas (per Mcf)(3).......................................... 3.28 3.28 2.25 2.07
FUTURE NET CASH FLOWS BEFORE TAX ($000):
Undiscounted(3)................................................... 405,329 420,211 386,810 545,029
Discounted(3)(4).................................................. 206,650 258,278 241,625 267,016
Standardized measure of discounted future cash flows(5)...........
ESTIMATED RESERVE LIFE INDEX (years)(6)............................. 12.0 7.0 7.0 12.5
RESERVE ADDITIONS (MBoe):
Acquisition....................................................... 6,968 307 - 31,993
Extensions, discoveries and revisions............................. 4,941 5,246 9,894 9,894
--------- --------- --------- ---------
Net additions..................................................... 11,909 5,553 9,894 41,887
--------- --------- --------- ---------
--------- --------- --------- ---------
COSTS INCURRED ($000):
Acquisitions...................................................... $ 16,293 $ 3,327 $ 476 $ 44,426
Exploration and development....................................... 22,516 37,501 59,060 59,060
--------- --------- --------- ---------
Total costs incurred.............................................. $ 38,809 $ 40,828 $ 59,536 $ 103,486
--------- --------- --------- ---------
--------- --------- --------- ---------
AVERAGE FINDING COSTS (per Boe)(7).................................. $ 3.26 $ 7.35 $ 6.02 $ 2.47
THREE YEAR WEIGHTED AVERAGE FINDING COSTS
(per Boe)(8)...................................................... 3.39 4.69 5.09 3.09
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
-------------------------------------------- ---------------------------------
PRO PRO
FORMA FORMA
1995 1996 1997 1997(9) 1997 1998 1998(9)
--------- --------- --------- ----------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION VOLUMES(10):
Oil and condensate (MBbls).................... 1,199 2,888 3,518 4,146 1,615 1,983 2,244
Natural gas (MMcf)............................ 5,880 6,527 5,789 6,399 2,881 2,933 3,314
Total (MBoe).................................. 2,179 3,976 4,483 5,213 2,095 2,472 2,796
UNIT ECONOMICS:
Average sales price per Bbl................... $ 17.11 $ 20.78 $ 18.61 $ 18.14 $ 20.08 $ 13.14 $ 12.45
Average sales price per mcf................... 1.40 2.13 2.21 2.03 2.33 1.79 1.66
Average equivalent price (per Boe)(11)........ $ 14.03 $ 18.87 $ 17.53 $ 17.02 $ 18.68 $ 12.66 $ 11.95
Lifting cost (per Boe)(12).................... 3.49 4.86 4.63 4.98 5.07 3.67 3.60
Depreciation, depletion and amortization (per
Boe)(12).................................... 3.76 5.44 6.74 6.01 7.31 5.95 5.62
General and administrative expense(13)........ 2.74 1.64 1.47 1.26 1.04 .58 1.40
--------- --------- --------- ----------- --------- --------- -----------
Gross margin.................................. $ 4.04 $ 6.93 $ 4.69 $ 4.77 $ 5.26 $ 1.46 $ 1.83
--------- --------- --------- ----------- --------- --------- -----------
--------- --------- --------- ----------- --------- --------- -----------
</TABLE>
See Notes to Summary Reserve and Operating Data.
11
<PAGE>
NOTES TO SUMMARY RESERVE AND OPERATING DATA
(1) To give effect to the Worland Field Acquisition as if it had occurred on
December 31, 1997.
(2) Reflects the actual realized prices received by the Company, including the
results of the Company's hedging activities. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
(3) In 1996, the Company changed its fiscal year-end from May 31 to December 31.
Because reports on a December 31 year-end basis prior to 1996 were not
available, information as of December 31, 1995 was determined from the
Company's production, drilling, acquisition and sale data as applied to its
December 31, 1996 reserve report.
(4) Represents the present value of estimated future net cash flows before
income tax discounted at 10%, using prices in effect at the end of the
respective periods presented and including the effects of hedging
activities. In accordance with applicable requirements of the Commission,
estimates of the Company's proved reserves and future net cash flows are
made using oil and gas sales prices estimated to be in effect as of the date
of such reserve estimates and are held constant throughout the life of the
properties (except to the extent a contract specifically provides for
escalation). The prices used in calculating PV-10 as of December 31, 1997
were $18.06 per Bbl of oil and $2.25 per Mcf of natural gas. Average prices
as of September 30, 1998, on a pro forma basis, were $12.95 per Bbl of oil
and $1.66 per Mcf of natural gas. These prices, if applied to estimated
proved reserves of the Company as of December 31, 1997, would result in a
PV-10, on a pro forma basis, of $208.7 million at such date, as estimated by
the Company.
(5) The discounted future net cash flows before tax have been determined on the
same basis as the Standardized Measure of Discounted Future Cash Flows under
SFAS 69, except that no effect was given for future income taxes because the
Company is an S Corporation for federal income tax purposes and is not a
taxpaying entity.
(6) Reserve life index is calculated by dividing proved reserves by annual
production (on a Boe basis).
(7) Average finding cost is calculated by dividing total costs incurred by
reserve additions.
(8) The three year weighted average finding cost is calculated by dividing the
sum of the finding costs for the three years ended on December 31 of each of
the referenced years by the sum of the reserve additions for each of such
years.
(9) To give effect to the Worland Field Acquisition as if it had occurred on
January 1, 1997.
(10) Production volumes are derived from the Company's production records and
reflect actual quantities of oil and gas produced without regard to the time
of receipt of proceeds from the sale of such production.
(11) Calculated by dividing oil and gas revenues, as reflected on the Financial
Statements, by production volumes on a Boe basis. Oil and gas revenues
reflected in the Financial Statements are recognized as production is sold
and may differ from oil and gas revenues reflected on the Company's
production records which reflect oil and gas revenues by date of production.
(12) Relates to drilling and development activities.
(13) Relates to drilling and development activities, net of operating overhead
income.
12
<PAGE>
RISK FACTORS
IN ADDITION TO THE OTHER INFORMATION SET FORTH ELSEWHERE IN THIS PROSPECTUS,
THE FOLLOWING FACTORS RELATING TO THE COMPANY AND THE OFFERING SHOULD BE
CONSIDERED WHEN EVALUATING AN INVESTMENT IN THE NOTES OFFERED HEREBY.
VOLATILITY OF OIL AND GAS PRICES
The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and gas and natural gas
liquids, which are dependent upon numerous factors such as weather, economic,
political and regulatory developments and competition from other sources of
energy. The Company is affected more by fluctuations in oil prices than natural
gas prices, because a majority of its production is oil. The volatile nature of
the energy markets and the unpredictability of actions of OPEC members make it
particularly difficult to estimate future prices of oil and gas and natural gas
liquids. Prices of oil and gas and natural gas liquids are subject to wide
fluctuations in response to relatively minor changes in circumstances, and there
can be no assurance that future prolonged decreases in such prices will not
occur. All of these factors are beyond the control of the Company. Any
significant decline in oil and, to a lesser extent, in natural gas prices would
have a material adverse effect on the Company's results of operations and
financial condition. Although the Company may enter into hedging arrangements
from time to time to reduce its exposure to price risks in the sale of its oil
and gas, the Company's hedging arrangements are likely to apply to only a
portion of its production and provide only limited price protection against
fluctuations in the oil and gas markets. See "Management' s Discussion and
Analysis of Financial Condition and Results of Operations" and "Business and
Properties--Oil and Gas Marketing."
REPLACEMENT OF RESERVES
The Company's future success depends upon its ability to find, develop or
acquire additional oil and gas reserves that are economically recoverable.
Unless the Company successfully replaces the reserves that it produces (through
successful development, exploration or acquisition), the Company's proved
reserves will decline. There can be no assurance that the Company will continue
to be successful in its effort to increase or replace its proved reserves.
Approximately 37% of the Company's estimated proved reserves at December 31,
1997, on a pro forma basis, was attributable to undeveloped reserves. Recovery
of such reserves will require significant capital expenditures and successful
drilling operations. There can be no certainty regarding the results of
developing these reserves. To the extent the Company is unsuccessful in
replacing or expanding its estimated proved reserves, the Company may be unable
to pay the principal of and interest on the Notes in accordance with their
terms, or otherwise to satisfy certain of its covenants contained in the
Indenture. See "Description of Notes--Certain Covenants."
UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES AND FUTURE NET CASH FLOWS
This Prospectus contains estimates of the Company's oil and gas reserves and
the future net cash flows from those reserves which have been prepared by the
Company and certain independent petroleum consultants. Reserve engineering is a
subjective process of estimating the recovery from underground accumulations of
oil and gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. There are numerous
uncertainties inherent in estimating quantities and future values of proved oil
and gas reserves, including many factors beyond the control of the Company. Each
of the estimates of proved oil and gas reserves, future net cash flows and
discounted present values relies upon various assumptions, including assumptions
required by the Commission as to constant oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
process of estimating oil and gas reserves is complex, requiring significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. As a result, such
estimates are inherently imprecise. Actual future production, oil and gas
prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable oil and gas reserves may vary substantially from
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those estimated in the report. Any significant variance in these assumptions
could materially affect the estimated quantity and value of reserves set forth
in this Prospectus. In addition, the Company's reserves may be subject to
downward or upward revision, based upon production history, results of future
exploration and development, prevailing oil and gas prices and other factors,
many of which are beyond the Company's control. The PV-10 of the Company's
proved oil and gas reserves does not necessarily represent the current or fair
market value of such proved reserves, and the 10% discount rate required by the
Commission may not reflect current interest rates, the Company's cost of capital
or any risks associated with the development and production of the Company's
proved oil and gas reserves. At December 31, 1997, the estimated future net cash
flows and PV-10 of $545.0 million and $267.0 million, respectively, attributable
to the Company's proved oil and gas reserves, on a pro forma basis, are based on
prices in effect at that date ($14.59 per Bbl of oil and $2.07 per Mcf of
natural gas), which may be materially different than actual future prices. As of
September 30, 1998, the average prices were $12.95 Bbl of oil and $1.66 per Mcf
of natural gas, on a pro forma basis. If such prices were applied to the
Company's proved oil and gas reserves at December 31, 1997, the estimated future
net cash flows and PV-10 at December 31, 1997 would have been approximately
$472.9 million and $208.7 million, respectively.
PROPERTY ACQUISITION RISKS
The Company's growth strategy includes the acquisition of oil and gas
properties. There can be no assurance, however, that the Company will be able to
identify attractive acquisition opportunities, obtain financing for acquisitions
on satisfactory terms or successfully acquire identified targets. In addition,
no assurance can be given that the Company will be successful in integrating
acquired businesses into its existing operations, and such integration may
result in unforeseen operational difficulties or require a disproportionate
amount of management's attention. Future acquisitions may be financed through
the incurrence of additional indebtedness to the extent permitted under the
Indenture or through the issuance of capital stock. Furthermore, there can be no
assurance that competition for acquisition opportunities in these industries
will not escalate, thereby increasing the cost to the Company of making further
acquisitions or causing the Company to refrain from making additional
acquisitions.
The Company is subject to risks that properties acquired by it (including
those acquired in the Worland Field Acquisition) will not perform as expected
and that the returns from such properties will not support the indebtedness
incurred or the other consideration used to acquire, or the capital expenditures
needed to develop, the properties. The addition of the Worland Field properties
may result in additional impairment of the Company's oil and gas properties to
the extent the Company's net book value of such properties exceeds the projected
discounted future net revenues of the related proved reserves. See "--Writedown
of Carrying Values." In addition, expansion of the Company's operations may
place a significant strain on the Company's management, financial and other
resources. The Company's ability to manage future growth will depend upon its
ability to monitor operations, maintain effective cost and other controls and
significantly expand the Company's internal management, technical and accounting
systems, all of which will result in higher operating expenses. Any failure to
expand these areas and to implement and improve such systems, procedures and
controls in an efficient manner at a pace consistent with the growth of the
Company's business could have a material adverse effect on the Company's
business, financial condition and results of operations. In addition, the
integration of acquired properties with existing operations will entail
considerable expenses in advance of anticipated revenues and may cause
substantial fluctuations in the Company's operating results. There can be no
assurance that the Company will be able to successfully integrate the properties
acquired and to be acquired or any other businesses it may acquire.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, and will continue to make, substantial capital
expenditures in connection with the acquisition, development, exploitation,
exploration and production of its oil and gas properties. Historically, the
Company has funded its capital expenditures through borrowings from banks and
from its
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principal stockholder, and cash flow from operations. Future cash flows and the
availability of credit are subject to a number of variables, such as the level
of production from existing wells, borrowing base determinations, prices of oil
and gas and the Company's success in locating and producing new oil and gas
reserves. If revenues were to decrease as a result of lower oil and gas prices,
decreased production or otherwise, and the Company had no availability under its
Credit Facility or other sources of borrowings, the Company could have limited
ability to replace its oil and gas reserves or to maintain production at current
levels, resulting in a decrease in production and revenues over time. If the
Company's cash flow from operations and availability under the Credit Facility
are not sufficient to satisfy its capital expenditure requirements, there can be
no assurance that additional debt or equity financing will be available.
EFFECTS OF LEVERAGE
At June 30, 1998, on a pro forma, consolidated basis, the Company and the
Subsidiary Guarantors would have had $153.8 million of indebtedness (including
current maturities of long-term indebtedness) compared to the Company's
stockholders' equity of $75.0 million. See "Use of Proceeds" and
"Capitalization." Although the Company's cash flow from operations has been
sufficient to meet its debt service obligations in the past, there can be no
assurance that the Company's operating results will continue to be sufficient
for the Company to meet its obligations. See "Unaudited Pro Forma Consolidated
Financial Statements," "Selected Consolidated Financial Data," "Capitalization"
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
The degree to which the Company is leveraged could have important
consequences to the holders of the Notes, including the following: (i) the
Company's ability to obtain additional financing for acquisitions, capital
expenditures, working capital or general corporate purposes may be impaired in
the future; (ii) a substantial portion of the Company's cash flow from
operations must be dedicated to the payment of principal of and interest on the
Notes and the borrowings under the Credit Facility, thereby reducing funds
available to the Company for its operations and other purposes; (iii) certain of
the Company's borrowings are and will continue to be at variable rates of
interest, which expose the Company to the risk of increased interest rates; (iv)
indebtedness outstanding under the Credit Facility is senior in right of payment
of, is secured by substantially all of the Company's proved reserves and certain
other assets, and will mature prior to the Notes; and (v) the Company may be
substantially more leveraged than certain of its competitors, which may place it
at a relative competitive disadvantage and make it more vulnerable to changing
market conditions and regulations. See "Description of Credit Facility" and
"Description of Notes."
The Company's ability to make scheduled payments or to refinance its
obligations with respect to its indebtedness will depend on its financial and
operating performance, which, in turn, is subject to the volatility of oil and
gas prices, production levels, prevailing economic conditions and to certain
financial, business and other factors beyond its control. If the Company's cash
flow and capital resources are insufficient to fund its debt service
obligations, the Company may be forced to sell assets, obtain additional debt or
equity financing or restructure its debt. Even if additional financing could be
obtained, there can be no assurance that it would be on terms that are favorable
or acceptable to the Company. There can be no assurance that the Company's cash
flow and capital resources will be sufficient to pay its indebtedness in the
future. In the absence of such operating results and resources, the Company
could face substantial liquidity problems and might be required to dispose of
material assets or operations to meet debt service and other obligations, and
there can be no assurance as to the timing of such sales or the adequacy of the
proceeds which the Company could realize therefrom. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources" and "Description of Credit Facility."
RESTRICTIVE COVENANTS
The Credit Facility and the Indenture include certain covenants that, among
other things, restrict: (i) the making of investments, loans and advances and
the paying of dividends and other restricted
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payments; (ii) the incurrence of additional indebtedness; (iii) the granting of
liens, other than liens created pursuant to the Credit Facility and certain
permitted liens; (iv) mergers, consolidations and sales of all or a substantial
part of the Company's business or property; (v) the sale of assets; and (vi) the
making of capital expenditures. The Credit Facility requires the Company to
maintain certain financial ratios, including interest coverage and leverage
ratios. All of these restrictive covenants may restrict the Company's ability to
expand or pursue its business strategies. The ability of the Company to comply
with these and other provisions of the Credit Facility may be affected by
changes in economic or business conditions, results of operations or other
events beyond the Company's control. The breach of any of these covenants could
result in a default under the Credit Facility, in which case, depending on the
actions taken by the lenders thereunder or their successors or assignees, such
lenders could elect to declare all amounts borrowed under the Credit Facility,
together with accrued interest, to be due and payable, and the Company could be
prohibited from making payments with respect to the Notes until the default is
cured or all Senior Debt is paid or satisfied in full. If the Company were
unable to repay such borrowings, such lenders could proceed against their
collateral. If the indebtedness under the Credit Facility were to be
accelerated, there can be no assurance that the assets of the Company would be
sufficient to repay in full such indebtedness and the other indebtedness of the
Company, including the Notes. See "Description of Credit Facility" and
"Description of Notes--Ranking and Subordination."
OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS
Oil and gas drilling activities are subject to numerous risks, many of which
are beyond the Company's control, including the risk that no commercially
productive oil and gas reservoirs will be encountered. The cost of drilling,
completing and operating wells is often uncertain, and drilling operations may
be curtailed, delayed or canceled as a result of a variety of factors, including
unexpected drilling conditions, pressure irregularities in formations, equipment
failure or accidents, adverse weather conditions, title problems and shortages
or delays in the delivery of equipment. The Company's future drilling activities
may not be successful and, if unsuccessful, such failure will have an adverse
effect on future results of operations and financial condition.
The Company's properties may be susceptible to hydrocarbon drainage from
production by other operators on adjacent properties. Industry operating risks
include the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards such as oil spills, gas leaks,
ruptures or discharges of toxic gases, the occurrence of any of which could
result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties and suspension of operations. In accordance with
customary industry practice, the Company maintains insurance against the risks
described above. There can be no assurance that any insurance will be adequate
to cover losses or liabilities. The Company cannot predict the continued
availability of insurance, or its availability at premium levels that justify
its purchase.
GAS GATHERING AND MARKETING
The Company's gas gathering and marketing operations depend in large part on
the ability of the Company to contract with third party producers to purchase
their gas, to obtain sufficient volumes of committed natural gas reserves, to
replace production from declining wells, to assess and respond to changing
market conditions in negotiating gas purchase and sale agreements and to obtain
satisfactory margins between the purchase price of its natural gas supply and
the sales price for such natural gas. In addition, the Company's operations are
subject to changes in regulations relating to gathering and marketing of oil and
gas. The inability of the Company to attract new sources of third party natural
gas or to promptly respond to changing market conditions or regulations in
connection with its gathering and marketing operations could have a material
adverse effect on the Company's financial condition and results of operations.
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SUBORDINATION OF NOTES AND GUARANTEES
The Notes are subordinated in right of payment to all existing and future
Senior Debt of the Company, including borrowings under the Credit Facility. In
the event of bankruptcy, liquidation or reorganization of the Company, the
assets of the Company will be available to pay obligations on the Notes only
after all Senior Debt has been paid in full, and there may not be sufficient
assets remaining to pay amounts due on any or all of the Notes outstanding. The
aggregate principal amount of Senior Debt of the Company, as of June 30, 1998,
on a pro forma basis, would have been $3.8 million exclusive of $75.0 million of
unused commitments under the Credit Facility. The Subsidiary Guarantees are
subordinated to Guarantor Senior Debt to the same extent and in the same manner
as the Notes are subordinated to Senior Debt. Additional Senior Debt may be
incurred by the Company or the Subsidiary Guarantors from time to time, subject
to certain restrictions. In addition to being subordinated to all existing and
future Senior Debt of the Company, the Notes will not be secured by any of the
Company's assets, unlike the borrowings under the Credit Facility. See
"Description of Notes--Ranking and Subordination."
POSSIBLE UNENFORCEABILITY OF SUBSIDIARY GUARANTEES; DEPENDENCE ON DISTRIBUTIONS
BY SUBSIDIARIES
Historically, the Company has derived approximately 10% of its operating
cash flows from its subsidiary, Continental Gas, Inc. The Company's other
subsidiary, Continental Crude Co., is recently formed and has not engaged in any
business activities. The holders of the Notes will have no direct claim against
such subsidiaries other than a claim created by one or more of the Subsidiary
Guarantees, which may themselves be subject to legal challenge in a bankruptcy
or reorganization case or a lawsuit by or on behalf of creditors of a Subsidiary
Guarantor. See "--Fraudulent Conveyance Considerations." If such a challenge
were upheld, such Subsidiary Guarantees would be invalid and unenforceable. To
the extent that any of such Subsidiary Guarantees are not enforceable, the
rights of the holders of the Notes to participate in any distribution of assets
of any Subsidiary Guarantor upon liquidation, bankruptcy, reorganization or
otherwise will, as is the case with other unsecured creditors of the Company, be
subject to prior claims of creditors of that Subsidiary Guarantor. The Company
relies in part upon distributions from its subsidiaries to generate the funds
necessary to meet its obligations, including the payment of principal of and
interest on the Notes. The Indenture contains covenants that restrict the
ability of the Company's subsidiaries to enter into any agreement limiting
distributions and transfers to the Company, including dividends. However, the
ability of the Company's subsidiaries to make distributions may be restricted by
among other things, applicable state corporate laws and other laws and
regulations or by terms of agreements to which they are or may become a party.
In addition, there can be no assurance that such distributions will be adequate
to fund the interest and principal payments on the Credit Facility and the Notes
when due. See "Description of Notes."
REPURCHASE OF NOTES UPON A CHANGE OF CONTROL AND CERTAIN OTHER EVENTS
Upon a Change of Control, holders of the Notes may have the right to require
the Company to repurchase all Notes then outstanding at a purchase price equal
to 101% of the principal amount thereof, plus accrued interest to the date of
repurchase. In the event of certain asset dispositions, the Company will be
required under certain circumstances to use the Excess Cash (as defined herein)
to offer to repurchase the Notes at 100% of the principal amount thereof, plus
accrued interest to the date of repurchase (an "Excess Cash Offer"). See
"Description of Notes--Repurchase at the Option of Holders" and "--Certain
Covenants."
The events that constitute a Change of Control or require an Excess Cash
Offer under the Indenture may also be events of default under the Credit
Facility or other Senior Debt of the Company and the Subsidiary Guarantors, the
terms of which may prohibit the purchase of the Notes by the Company until the
Company's indebtedness under the Credit Facility or other Senior Debt is paid in
full. In addition, such events may permit the lenders under such debt
instruments to accelerate the debt and, if the debt is not paid, to enforce
security interests on substantially all the assets of the Company and the
Subsidiary Guarantors, thereby limiting the Company's ability to raise cash to
repurchase the Notes and reducing the
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practical benefit of the offer to repurchase provisions to the holders of the
Notes. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources." There can be no
assurance that the Company will have sufficient funds available at the time of
any Change of Control or Excess Cash Offer to make any debt payment (including
repurchases of Notes) as described above. Any failure by the Company to
repurchase Notes tendered pursuant to a Change of Control Offer (as defined
herein) or an Excess Cash Offer will constitute an Event of Default under the
Indenture. See "Description of Notes--Certain Covenants."
RISK OF HEDGING AND OIL TRADING ACTIVITIES
From time to time the Company may use energy swap and forward sale
arrangements to reduce its sensitivity to oil and gas price volatility. If the
Company's reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, or otherwise, the Company would be required to satisfy
its obligations under potentially unfavorable terms. If the Company enters into
financial instrument contracts for the purpose of hedging prices and the
estimated production volumes are less than the amount covered by these
contracts, the Company would be required to mark-to-market these contracts and
recognize any and all losses within the determination period. Further, under
financial instrument contracts, the Company may be at risk for basis
differential, which is the difference in the quoted financial price for contract
settlement and the actual physical point of delivery price. The Company will
from time to time attempt to mitigate basis differential risk by entering into
physical basis swap contracts. Substantial variations between the assumptions
and estimates used by the Company in the hedging activities and actual results
experienced could materially adversely affect the Company's anticipated profit
margins and its ability to manage risk associated with fluctuations in oil and
gas prices. Furthermore, the fixed price sales and hedging contracts limit the
benefits the Company will realize if actual prices rise above the contract
prices. The Company had no energy swap or forward sale arrangements in place at
December 31, 1997 or at June 30, 1998. The Company plans to reduce its hedging
transactions. In August 1998, the Company began entering into oil trading
arrangements as part of its oil marketing activities. Under these arrangements,
the Company contracts to purchase oil from one source and to sell oil to an
unrelated purchaser, usually at disparate prices. Should the Company's purchaser
fail to complete the contracts for purchase, the Company may suffer a loss. The
Company's realized gains on these arrangements, determined before $.1 million of
transportation costs and related expenses, of $1.6 million for July, $1.2
million for August and $.8 million for September 1998. The Company's policy is
to limit its exposure from open positions to $1.0 million at any one time.
WRITEDOWN OF CARRYING VALUES
The Company periodically reviews the carrying value of its oil and gas
properties in accordance with Statement of Financial Accounting Standards No.
121 "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed Of" ("SFAS No. 121"). SFAS No. 121 requires that long-lived assets,
including proved oil and gas properties, and certain identifiable intangibles to
be held and used by the Company be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. In performing the review for recoverability, the Company
estimates the future cash flows expected to result from the use of the asset and
its eventual disposition. If the sum of the expected future cash flows
(undiscounted and without interest charges) is less than the carrying value of
the asset, an impairment loss is recognized in the form of additional
depreciation, depletion and amortization expense. Measurement of an impairment
loss for proved oil and gas properties is calculated on a property-by-property
basis as the excess of the net book value of the property over the projected
discounted future net cash flows of the impaired property, considering expected
reserve additions and price and cost escalations. The Company may be required to
write down the carrying value of its oil and gas properties when oil and gas
prices are depressed or unusually volatile, which would result in a charge to
earnings. Once incurred, a writedown of oil and gas properties is not reversible
at a later date.
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LAWS AND REGULATIONS; ENVIRONMENTAL RISK
Oil and gas operations are subject to various federal, state and local
governmental regulations which may be changed from time to time in response to
economic or political conditions. From time to time, regulatory agencies have
imposed price controls and limitations on production in order to conserve
supplies of oil and gas. In addition, the production, handling, storage,
transportation and disposal of oil and gas, by-products thereof and other
substances and materials produced or used in connection with oil and gas
operations are subject to regulation under federal, state and local laws and
regulations. See "Business and Properties--Regulation."
The Company is subject to a variety of federal, state and local governmental
regulations related to the storage, use, discharge and disposal of toxic,
volatile or otherwise hazardous materials. These regulations subject the Company
to increased operating costs and potential liability associated with the use and
disposal of hazardous materials. Although these laws and regulations have not
had a material adverse effect on the Company's financial condition or results of
operations, there can be no assurance that the Company will not be required to
make material expenditures in the future. If such laws and regulations become
increasingly stringent in the future, it could lead to additional material costs
for environmental compliance and remediation by the Company. See "Business and
Properties--Regulation."
The Company's twenty years of experience with the use of HPAI technology has
not resulted in any known environmental claims. The Company's saltwater
injection operations will pose certain risks of environmental liability to the
Company. Although the Company will monitor the injection process, any leakage
from the subsurface portions of the wells could cause degradation of fresh
groundwater resources, potentially resulting in suspension of operation of the
wells, fines and penalties from governmental agencies, expenditures for
remediation of the affected resource, and liability to third parties for
property damages and personal injuries. In addition, the sale by the Company of
residual crude oil collected as part of the saltwater injection process could
impose liability on the Company in the event the entity to which the oil was
transferred fails to manage the material in accordance with applicable
environmental health and safety laws.
Any failure by the Company to obtain required permits for, control the use
of, or adequately restrict the discharge of, hazardous substances under present
or future regulations could subject the Company to substantial liability or
could cause its operations to be suspended. Such liability or suspension of
operations could have a material adverse effect on the Company's business,
financial condition and results of operations.
COMPETITION
The Company operates in a highly competitive environment. The Company
competes with major and independent oil and gas companies and with individual
producers and developers for the acquisition of desirable oil and gas
properties, as well as for the equipment and labor required to develop and
operate such properties. Many of these competitors have financial and other
resources substantially greater than those of the Company. See "Business and
Properties--Competition."
CONTROLLING SHAREHOLDER
At August 31, 1998, Harold Hamm, President and Chief Executive Officer and a
Director of the Company, beneficially owned 44,496 shares of Common Stock
representing, in the aggregate, approximately 91% of the outstanding Common
Stock of the Company. As a result, Harold Hamm is in a position to control the
Company. The Company is provided oilfield services by several affiliated
companies controlled by Harold Hamm. Such transactions will continue in the
future and may result in conflicts of interest between the Company and such
affiliated companies. There can be no assurance that such conflicts will be
resolved in favor of the Company. If Harold Hamm ceases to be an executive
officer of the Company, such would constitute an event of default under the
Credit Facility, unless waived by the
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requisite percentage of banks. See "Principal Shareholders," "Certain
Relationships and Related Transactions" and "Description of Credit Facility."
ABSENCE OF PUBLIC MARKET; RESTRICTIONS ON TRANSFER
The Notes are a new issue of securities for which there has been no public
market and there can be no assurance that such a market for the Notes will
develop or, if such a market develops, as to the liquidity of such market. The
Company does not intend to apply for listing of the Notes on any securities
exchange; however, the Notes have been designated for trading in the PORTAL
market. If the Notes are traded after their initial issuance, they may trade at
a discount from their initial offering price, depending upon prevailing interest
rates, the market for similar securities, the performance of the Company and
certain other factors. Although the Initial Purchaser has informed the Company
that it intends to make a market in the Notes as permitted by applicable laws
and regulations the Initial Purchaser is not obligated to do so and any such
market making activities may be discontinued at any time without notice. See
"Transfer Restrictions," "Exchange and Registration Rights Agreement" and "Plan
of Distribution."
FRAUDULENT CONVEYANCE CONSIDERATIONS
The incurrence of indebtedness (such as the Notes) is subject to review
under relevant federal bankruptcy and state fraudulent conveyance statutes in a
bankruptcy or reorganization proceeding or a lawsuit by or on behalf of
creditors of the Company. The Company's obligations under the Notes will be
guaranteed on a subordinated, unsecured basis by existing and future Restricted
Subsidiaries pursuant to the provisions of the Indenture. Under such laws, to
the extent a court were to find that (a) the Notes or a Subsidiary Guarantee was
incurred with the intent to hinder, delay or defraud any present or future
creditor or that the Company or such Subsidiary Guarantor contemplated
insolvency with a design to favor one or more creditors to the exclusion in
whole or in part of other creditors or (b) at the time such person incurred
obligations under the Notes or a Subsidiary Guarantee, it received less than
fair consideration or reasonably equivalent value therefor, and (c) either (i)
was insolvent, (ii) was rendered insolvent by such guarantee or pledge, (iii)
was engaged in a business or transaction for which its remaining unencumbered
assets constituted unreasonably small capital or (iv) intended to incur or
believed that it would incur debts beyond its ability to pay such debts as they
matured, such court could void such obligations and direct the return of any
amounts paid with respect thereto. The measure of insolvency for purposes of the
foregoing will vary depending on the law of the jurisdiction being applied.
Generally, however, an entity would be considered insolvent if the sum of its
debts (including contingent or unliquidated debts) is greater than all of its
property at a fair valuation or if the present fair salable value of its assets
is less than the amount that would be required to pay its probable liability on
its existing debts as they become absolute and mature. There can be no assurance
that, after providing for all prior claims, if any, there would be sufficient
assets to satisfy the claims of the holders of the Notes relating to any voided
portion of a Subsidiary Guarantee. To the extent a Subsidiary Guarantee is
voided as a fraudulent conveyance or held unenforceable for any other reason,
the holders of the Notes would cease to have any claim in respect of such
Subsidiary Guarantor and would be creditors solely of the Company and any other
Subsidiary Guarantors.
CONSEQUENCES OF THE EXCHANGE OFFER ON NON-TENDERING HOLDERS OF OLD NOTES.
In the event the Exchange Offer is consummated, the Company and the
Subsidiary Guarantors will not be required to register any Old Notes not
tendered and accepted in the Exchange Offer (other than, in certain
circumstances, Notes entitled to be covered by a shelf registration statement).
In such event, holders of Old Notes seeking liquidity in their investment would
have to rely on exemptions to the registration requirements under the securities
laws, including the Securities Act. Following the Exchange Offer, assuming the
Company and the Subsidiary Guarantors have no shelf registration obligation with
respect to any Notes, none of the holders of Notes will be entitled to receive
liquidated damages. See "The Exchange Offer--Purpose and Effect of The Exchange
Offer."
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THE EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
The Old Notes were sold by the Company on July 24, 1998 to Chase Securities,
Inc. (the "Initial Purchaser") in reliance on Section 4(2) of the Securities
Act. The Placement Agents offered and sold the Old Notes only (i) to "qualified
institutional buyers" (as defined in Rule 144A) in compliance with Rule 144A and
(ii) outside the United States to persons other than U.S. Persons, which term
includes dealers or other professional fiduciaries in the United States acting
on a discretionary basis for foreign beneficial owners (other than an estate or
trust), in reliance upon Regulation S under the Securities Act.
In connection with the sale of the Old Notes, the Company and the Initial
Purchaser entered into a Registration Rights Agreement dated as of July 21, 1998
(the "Registration Rights Agreement"), which requires the Company (i) to cause
the Old Notes to be registered under the Securities Act, or (ii) to file with
the Commission a registration statement under the Securities Act with respect to
an issue of New Notes of the Company identical in all material respects to the
Old Notes and use its best efforts to cause such registration statement to
become effective under the Securities Act and, upon the effectiveness of that
registration statement, to offer to the holders of the Old Notes the opportunity
to exchange their Old Notes for a like principal amount of New Notes, which will
be issued without a restrictive legend and which may be reoffered and resold by
the holder without restrictions or limitations under the Securities Act. A copy
of the Registration Rights Agreement has been filed as an exhibit to the
Registration Statement of which this Prospectus is a part. The Exchange Offer is
being made pursuant to the Registration Rights Agreement to satisfy the
Company's obligations thereunder. The term "holder" with respect to the Exchange
Offer means any person in whose name Old Notes are registered on the Company's
books or any other person who has obtained a properly completed stock power from
the registered holder, or any person whose Old Notes are held of record by The
Depository Trust Company ("DTC") who desires to deliver such Old Notes by
book-entry transfer at DTC.
The Company has not requested, and does not intend to request, an
interpretation by the staff of the Commission with respect to whether the New
Notes issued pursuant to the Exchange Offer in exchange for the Old Notes may be
offered for sale, resold or otherwise transferred by any holder without
compliance with the registration and prospectus delivery provisions of the
Securities Act. Based on interpretations by the staff of the Commission set
forth in no-action letters issued regarding EXXON CAPITAL HOLDINGS CORPORATION
(available May 13, 1989) and MORGAN STANLEY & CO. INCORPORATED (available June
5, 1991), the Company believes the New Notes issued pursuant to the Exchange
Offer in exchange for Old Notes may be offered for resale, resold and otherwise
transferred by any holder thereof (other than broker-dealers, as set forth
below, and any such holder that is an "affiliate" of the Company within the
meaning of Rule 405 under the Securities Act) without compliance with the
registration and prospectus delivery provisions of the Securities Act, provided
that such New Notes are acquired in the ordinary course of such holder's
business and that such holder has no arrangement or understanding with any
person to participate in the distribution of such New Notes. Any holder who
tenders in the Exchange Offer with the intention to participate, or for the
purpose of participating, in a distribution of the New Notes or who is an
affiliate of the Company may not rely upon such interpretations by the staff of
the Commission and, in the absence of an exemption therefrom, must comply with
the registration and prospectus delivery requirements of the Securities Act in
connection with any secondary resale transaction. Failure to comply with such
requirements in such instance may result in such holder incurring liabilities
under the Securities Act for which the holder is not indemnified by the Company.
Each broker-dealer (other than an affiliate of the Company) that receives New
Notes for its own account pursuant to the Exchange Offer as a result of market
making or other activities must acknowledge that it will deliver a prospectus
meeting the requirements of the Securities Act in connection with any resale of
such New Notes. The Letter of Transmittal states that by so acknowledging and by
delivering a prospectus, a broker-dealer will not be deemed to admit that it is
an "underwriter" within the meaning of the Securities Act. The Company has
agreed that, for a period of
21
<PAGE>
180 days after the Exchange Date, it will make the Prospectus available to any
broker-dealer for use in connection with any such resale. See "Plan of
Distribution."
The Exchange Offer is not being made to, nor will the Company accept
surrenders for exchange from, holders of Old Notes in any jurisdiction in which
this Exchange Offer or the acceptance thereof would not be in compliance with
the securities or blue sky laws of such jurisdiction.
By tendering in the Exchange Offer, each holder of Old Notes will represent
to the Company that, among other things, (i) the New Notes acquired pursuant to
the Exchange Offer are being obtained in the ordinary course of business of the
person receiving such New Notes, whether or not such person is the holder, (ii)
neither the holder of Old Notes nor any such other person has an arrangement or
understanding with any person to participate in the distribution of such New
Notes, (iii) if the holder is not a broker-dealer, or is a broker-dealer but
will not receive New Notes for its own account in exchange for Old Notes,
neither the holder nor any such other person is engaged in or intends to
participate in the distribution of such New Notes, and (iv) neither the holder
nor any such other person is an "affiliate" of the Company within the meaning of
Rule 405 under the Securities Act or, if such holder is an "affiliate," that
such holder will comply with the registration and prospectus delivery
requirements of the Securities Act to the extent applicable.
Each holder, by tendering, also acknowledges and agrees that any holder
using the Exchange Offer to participate in a distribution of the New Notes (a)
could not rely on the position of the Commission enunciated in EXXON CAPITAL
HOLDINGS CORPORATION (available May 13, 1998) and MORGAN STANLEY AND CO., INC.
(available June 5, 1991) as interpreted in the Commission's letter to SHERMAN &
STERLING (available July 2, 1993), and similar no-action letters, and (b) must
comply with the registration and prospectus delivery requirements of the
Securities Act in connection with a secondary resale transaction and that such a
secondary resale transaction should be covered by an effective registration
statement containing the selling security holder information required by Item
507 or 508, as applicable, of Regulation S-K if the resales are of New Notes
obtained by such holder in exchange for Old Notes acquired by such holder
directly from the company.
Following the completion of the Exchange Offer, none of the Old Notes will
be entitled to the contingent increase in interest rate applicable to the Old
Notes. Following the consummation of the Exchange Offer, holders of Old Notes
will not have any further registration rights, and the Old Notes will continue
to be subject to certain restrictions on transfer. See "--Consequences of
Failure to Exchange." Accordingly, the liquidity of the market for the Old Notes
could be adversely affected. See "Risk Factors-- Consequences of the Exchange
Offer on Non-Tendering Holders of the Old Notes."
Participation in the Exchange Offer is voluntary and holders should
carefully consider whether to accept. Holders of the Old Notes are urged to
consult their financial and tax advisors in making their own decisions on
whether to participate in the Exchange Offer.
TERMS OF THE EXCHANGE OFFER
GENERAL. Upon the terms and subject to the conditions set forth in this
Prospectus and in the Letter of Transmittal, the Company will accept any and all
Old Notes validly tendered and not withdrawn prior to 5:00 p.m., New York City
time, on the Expiration Date. The Company will issue $1,000 principal amount of
New Notes in exchange for each $1,000 principal amount of Old Notes accepted in
the Exchange Offer. Holders may tender some or all of their Old Notes pursuant
to the Exchange Offer. However, Old Notes may be tendered only in amounts that
are integral multiples of $1,000 principal amount.
The form and terms of the New Notes will be identical in all material
respects to the form and terms of the Old Notes except that the New Notes will
be registered under the Securities Act and, therefore, certificates representing
New Notes will not bear legends restricting the transfer thereof. The New Notes
will evidence the same debt as the Old Notes, will be entitled to the benefits
of the Indenture and will be
22
<PAGE>
treated as a single class thereunder with any Old Notes that remain outstanding.
The Exchange Offer is not conditioned upon any minimum number of Old Notes being
tendered for exchange.
As of November 6, 1998, $150,000,000 aggregate principal amount of the Old
Notes were outstanding. This Prospectus, together with the Letter of
Transmittal, is being sent to all registered holders.
Holders of Old Notes do not have any appraisal or dissenters' rights under
the Oklahoma General Corporation Act or the Indenture in connection with the
Exchange Offer. The Company intends to conduct the Exchange Offer in accordance
with the provisions of the Registration Rights Agreement and the applicable
requirements of the Exchange Act, and the rules and regulations of the
Commission thereunder. Old Notes which are not tendered for exchange in the
Exchange Offer will remain outstanding and interest thereon will continue to
accrue, but such Old Notes will not be entitled to any rights or benefits under
the Registration Rights Agreement.
The Company will be deemed to have accepted validly tendered Old Notes when,
as and if the Company has given oral or written notice thereof to the Exchange
Agent. The Exchange Agent will act as agent for the tendering holders for the
purposes of receiving the New Notes from the Company. If any tendered Old Notes
are not accepted for exchange because of an invalid tender, the occurrence of
certain other events set forth herein or otherwise, certificates for any such
unaccepted Old Notes will be returned, without expense, to the tendering holder
thereof as promptly as practicable after the Expiration Date.
Holders who tender Old Notes in the Exchange Offer will not be required to
pay brokerage commissions or fees or, subject to the instructions in the Letter
of Transmittal, transfer taxes with respect to the exchange of Old Notes
pursuant to the Exchange Offer. The Company will pay all charges and expenses,
other than certain applicable taxes described below, in connection with the
Exchange Offer. See "--Fees and Expenses."
EXPIRATION DATE; EXTENSIONS; AMENDMENTS. The term "Expiration Date" shall
mean 5:00 p.m., New York City time, on December , 1998, unless the Company, in
its sole discretion, extends the Exchange Offer, in which case the term
"Expiration Date" shall mean the latest date and time to which the Exchange
Offer is extended. Although the Company has no current intention to extend the
Exchange Offer, the Company reserves the right to extend the Exchange Offer at
any time and from time to time by giving oral or written notice to the Exchange
Agent and by timely public announcement communicated, unless otherwise required
by applicable law or regulation, by making a release to the Dow Jones News
Service. During any extension of the Exchange Offer, all Old Notes previously
tendered pursuant to the Exchange Offer and not withdrawn will remain subject to
the Exchange Offer. The date of the exchange of the New Notes for Old Notes will
be as soon as practicable following the Expiration Date.
The Company reserves the right, in its sole discretion, (i) to delay
accepting any Old Notes, to extend the Exchange Offer or to terminate the
Exchange Offer if any of the conditions set forth below under "--Conditions of
the Exchange Offer" shall not have been satisfied, by giving oral or written
notice of such delay, extension or termination to the Exchange Agent, or (ii) to
amend the terms of the Exchange Offer in any manner. Any such delay in
acceptance, extension, termination or amendment will be followed as promptly as
practicable by oral or written notice thereof to the registered holders. If the
Exchange Offer is amended in any manner determined by the Company to constitute
a material change, the Company will promptly disclose such amendment by means of
a prospectus supplement that will be distributed to the registered holders, and
the Company will extend the Exchange Offer for a period of time, depending upon
the significance of the amendment and the manner of disclosure to the registered
holders, if the Exchange Offer would otherwise expire during such period.
In all cases, issuance of the New Notes for Old Notes that are accepted for
exchange pursuant to the Exchange Offer will be made only after timely receipt
by the Exchange Agent of a properly completed and duly executed Letter of
Transmittal and all other required documents; provided, however, that the
Company reserves the absolute right to waive any conditions of the Exchange
Offer or defects or
23
<PAGE>
irregularities in the tender of Old Notes. If any tendered Old Notes are not
accepted for any reason set forth in the terms and conditions of the Exchange
Offer or if Old Notes are submitted for a greater principal amount than the
holder desires to exchange, such unaccepted or non-exchanged Old Notes or
substitute Old Notes evidencing the unaccepted portion, as appropriate, will be
returned without expense to the tendering holder, unless otherwise provided in
the Letter of Transmittal, as promptly as practicable after the expiration or
termination of the Exchange Offer.
INTEREST ON THE NEW NOTES. Holders of Old Notes that are accepted for
exchange will not receive accrued interest thereon at the time of exchange.
However, each New Note will bear interest from the most recent date to which
interest has been paid on the Old Notes or New Notes, or if no interest has been
paid on the Old Notes or the New Notes, from June 12, 1998.
PROCEDURES FOR TENDERING OLD NOTES. The tender to the Company of Old Notes
by a holder thereof pursuant to one of the procedures set forth below will
constitute an agreement between such holder and the Company in accordance with
the terms and subject to the conditions set forth herein and in the Letter of
Transmittal. A holder of the Old Notes may tender such Old Notes by (i) properly
completing and signing a Letter of Transmittal or a facsimile thereof (all
references in this Prospectus to a Letter of Transmittal shall be deemed to
include a facsimile thereof) and delivering the same, together with any
corresponding certificate or certificates representing the Old Notes being
tendered (if in certificated form) and any required signature guarantees, to the
Exchange Agent at its address set forth in the Letter of Transmittal on or prior
to the Expiration Date (or complying with the procedure for book-entry transfer
described below), or (ii) complying with the guaranteed delivery procedures
described below.
If tendered Old Notes are registered in the name of the signer of the Letter
of Transmittal and the New Notes to be issued in exchange therefor are to be
issued (and any untendered Old Notes are to be reissued) in the name of the
registered holder (which term, for the purposes described herein, shall include
any participant in DTC (also referred to as a book-entry facility) whose name
appears on a security listing as the owner of Old Notes), the signature of such
signer need not be guaranteed. In any other case, the tendered Old Notes must be
endorsed or accompanied by written instruments of transfer in form satisfactory
to the Company and duly executed by the registered holder and the signature on
the endorsement or instrument of transfer must be guaranteed by an eligible
guarantor institution which is a member of one of the following recognized
signature guarantee programs (an "Eligible Institution"): (i) The Securities
Transfer Agents Medallion Program (STAMP), (ii) The New York Stock Exchange
Medallion Signature Program (MSF), or (iii) The Stock Exchange Medallion Program
(SEMP). If the New Notes or Old Notes not exchanged are to be delivered to an
address other than that of the registered holder appearing on the note register
for the Old Notes, the signature in the Letter of Transmittal must be guaranteed
by an Eligible Institution.
THE METHOD OF DELIVERY OF OLD NOTES, THE LETTER OF TRANSMITTAL AND ALL OTHER
REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK OF THE
HOLDER. IF SUCH DELIVERY IS BY MAIL, IT IS RECOMMENDED THAT REGISTERED MAIL,
PROPERLY INSURED, WITH RETURN RECEIPT REQUESTED, BE USED. IN ALL CASES,
SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE DELIVERY TO THE EXCHANGE AGENT
BEFORE THE EXPIRATION DATE. NO LETTER OF TRANSMITTAL OR OLD NOTES SHOULD BE SENT
TO THE COMPANY. HOLDERS MAY REQUEST THEIR RESPECTIVE BROKERS, DEALERS,
COMMERCIAL BANKS, TRUST COMPANIES OR NOMINEES TO EFFECT THE ABOVE TRANSACTIONS
FOR SUCH HOLDERS.
The Company understands that the Exchange Agent has confirmed with DTC that
any financial institution that is a participant in DTC's system may utilize
DTC's Automated Tender Offer Program ("ATOP") to tender Old Notes. The Company
further understands that the Exchange Agent will request, within two business
days after the date the Exchange Offer commences, that DTC establish an account
with respect to the Old Notes for the purpose of facilitating the Exchange
Offer, and any participant may
24
<PAGE>
make book-entry delivery of Old Notes by causing DTC to transfer such Old Notes
into the Exchange Agent's account in accordance with DTC's ATOP procedures for
transfer. However, the exchange of the Old Notes so tendered will only be made
after timely confirmation (a "Book-Entry Confirmation") of such book-entry
transfer and timely receipt by the Exchange Agent of an Agent's Message (as
defined in the next sentence), and any other documents required by the Letter of
Transmittal. The term "Agent's Message" means a message, transmitted by DTC and
received by the Exchange Agent and forming part of Book-Entry Confirmation,
which states that DTC has received an express acknowledgment from a participant
tendering Old Notes which are the subject of such Book-Entry Confirmation and
that such participant has received and agrees to be bound by the terms of the
Letter of Transmittal and that the Company may enforce such agreement against
such participant.
A tender will be deemed to have been received as of the date when (i) the
tendering holder's properly completed and duly signed Letter of Transmittal
accompanied by the Old Notes (or a confirmation of book-entry transfer of such
Old Notes into the Exchange Agent's account at DTC), is received by the Exchange
Agent, or (ii) a Notice of Guaranteed Delivery or letter, telegram or facsimile
transmission to similar effect (as provided below) from an Eligible Institution
is received by the Exchange Agent. Issuances of New Notes in exchange for Old
Notes tendered pursuant to a Notice of Guaranteed Delivery or letter, telegram
or facsimile transmission to similar effect (as provided below) by an Eligible
Institution will be made only against submission of a duly signed Letter of
Transmittal (and any other required documents) and deposit of the tendered Old
Notes.
All questions as to the validity, form, eligibility (including time of
receipt) and acceptance for exchange of any tender of Old Notes will be
determined by the Company, whose determination will be final and binding. The
Company reserves the absolute right to reject any or all tenders not in proper
form or the acceptance for exchange of which may, in the opinion of the
Company's counsel, be unlawful. The Company also reserves the absolute right to
waive any of the conditions of the Exchange Offer or any defect or irregularity
in the tender of any Old Notes. None of the Company, the Exchange Agent or any
other person will be under any duty to give notification of any defects or
irregularities in tenders or incur any liability for failure to give any such
notification. Any Old Notes received by the Exchange Agent that are not validly
tendered and as to which the defects or irregularities have not been cured or
waived, or if Old Notes are submitted in principal amount greater than the
principal amount of Old Notes being tendered by such tendering holder, such
unaccepted or non-exchanged Old Notes will be returned by the Exchange Agent to
the tendering holder, unless otherwise provided in the Letter of Transmittal, as
soon as practicable following the Expiration Date.
In addition, the Company reserves the right in its sole discretion (a) to
purchase or make offers for any Old Notes that remain outstanding subsequent to
the Expiration Date, and (b) to the extent permitted by applicable law, to
purchase Old Notes in the open market, in privately negotiated transactions or
otherwise. The terms of any such purchases or offers will differ from the terms
of the Exchange Offer.
GUARANTEED DELIVERY PROCEDURES. If the holder desires to accept the
Exchange Offer and time will not permit a Letter of Transmittal or Old Notes to
reach the Exchange Agent before the Expiration Date or the procedure for
book-entry transfer cannot be completed on a timely basis, a tender may be
effected if the Exchange Agent has received at its office, on or prior to the
Expiration Date, a letter, telegram or facsimile transmission from an Eligible
Institution setting forth the name and address of the tendering holder, the
name(s) in which the Old Notes are registered and the certificate number(s) of
the Old Notes to be tendered, and stating that the tender is being made thereby
and guaranteeing that, within three New York Stock Exchange trading days after
the date of execution of such letter, telegram or facsimile transmission by the
Eligible Institution, such Old Notes, in proper form for transfer (or a
confirmation of book-entry transfer of such Old Notes into the Exchange Agent's
account at DTC), will be delivered by such Eligible Institution together with a
properly completed and duly executed Letter of Transmittal (and any other
required documents). Unless Old Notes being tendered by the above-described
method are deposited with the Exchange Agent within the time period set forth
above (accompanied or preceded by a
25
<PAGE>
properly competed Letter of Transmittal and any other required documents), the
Company may, at its option, reject the tender. Copies of a Notice of Guaranteed
Delivery which may be used by Eligible Institutions for the purposes described
in this paragraph are available from the Exchange Agent.
TERMS AND CONDITIONS OF THE LETTER OF TRANSMITTAL. The Letter of
Transmittal contains, among other things, the following terms and conditions,
which are part of the Exchange Offer.
The party tendering Old Notes for exchange (the "Transferor") exchanges,
assigns and transfers the Old Notes to the Company and irrevocably constitutes
and appoints the Exchange Agent as the Transferor's agent and attorney-in-fact
to cause the Old Notes to be assigned, transferred and exchanged. The Transferor
represents and warrants that it has full power and authority to tender,
exchange, assign and transfer the Old Notes and to acquire New Notes issuable
upon the exchange of such tendered Old Notes, and that, when the same are
accepted for exchange, the Company will acquire good and unencumbered title to
the tendered Old Notes, free and clear of all liens, restrictions, charges and
encumbrances and not subject to any adverse claim. The Transferor also warrants
that it will, upon request, execute and deliver any additional documents deemed
by the Company to be necessary or desirable to complete the exchange, assignment
and transfer of tendered Old Notes or to transfer ownership of such Old Notes on
the account books maintained by DTC. All authority conferred by the Transferor
will survive the death, bankruptcy or incapacity of the Transferor and every
obligation of the Transferor shall be binding upon the heirs, personal
representatives, executors, administrators, successors, assigns, trustees in
bankruptcy and other legal representatives of such Transferor.
By executing a Letter of Transmittal, each holder will make to the Company
the representations set forth above under the heading "--Purpose and Effect of
the Exchange Offer."
WITHDRAWAL OF TENDERS OF OLD NOTES. Except as otherwise provided herein,
tenders of Old Notes may be withdrawn at any time prior to 5:00 p.m., New York
City time, on the Expiration Date.
To withdraw a tender of Old Notes in the Exchange Offer, a written or
facsimile transmission notice of withdrawal must be received by the Exchange
Agent at its address set forth herein prior to 5:00 p.m., New York City time, on
the Expiration Date. Any such notice of withdrawal must (i) specify the name of
the person having deposited the Old Notes to be withdrawn (the "Depositor"),
(ii) identify the Old Notes to be withdrawn (including the certificate number or
numbers and principal amount of such Old Notes), (iii) contain a statement that
such holder is withdrawing its election to have such Old Notes exchanged, (iv)
be signed by the holder in the same manner as the original signature on the
Letter of Transmittal by which such Old Notes were tendered (including any
required signature guarantees) or be accompanied by documents of transfer
sufficient to have the Trustee with respect to the Old Notes register the
transfer of such Old Notes in the name of the person withdrawing the tender, and
(v) specify the name in which any such Old Notes are to be registered, if
different from that of the Depositor. If Old Notes have been tendered pursuant
to the procedure for book-entry transfer, any notice of withdrawal must specify
the name and number of the account at the book-entry transfer facility. All
questions as to the validity, form and eligibility (including time of receipt)
of such notices will be determined by the Company, whose determination shall be
final and binding on all parties. Any Old Notes so withdrawn will be deemed not
to have been validly tendered for purposes of the Exchange Offer and no New
Notes will be issued with respect thereto unless the Old Notes so withdrawn are
validly retendered. Any Old Notes which have been tendered but which are not
accepted for exchange will be returned to the holder thereof without cost to
such holder as soon as practicable after withdrawal, rejection of tender or
termination of the Exchange Offer. Properly withdrawn Old Notes may be
retendered by following one of the procedures described above under
"--Procedures for Tendering Old Notes" at any time prior to the Expiration Date.
26
<PAGE>
CONDITIONS OF THE EXCHANGE OFFER
Notwithstanding any other term of the Exchange Offer, or any extension of
the Exchange Offer, the Company shall not be required to accept for exchange, or
exchange New Notes for, any Old Notes, and may terminate the Exchange Offer as
provided herein before the acceptance of such Old Notes, if:
(a) any statute, rule or regulation shall have been enacted, or any
action shall have been taken by any court or governmental authority which,
in the reasonable judgment of the Company, would prohibit, restrict or
otherwise render illegal consummation of the Exchange Offer; or
(b) any change, or any development involving a prospective change, in
the business or financial affairs of the Company or any of its subsidiaries
has occurred which, in the sole judgment of the Company, might materially
impair the ability of the Company to proceed with the Exchange Offer or
materially impair the contemplated benefits of the Exchange Offer to the
Company; or
(c) there shall occur a change in the current interpretations by the
staff of the Commission which, in the Company's reasonable judgment, might
materially impair the Company's ability to proceed with the Exchange Offer.
If the Company determines in its sole discretion that any of the above
conditions are not satisfied, the Company may (i) refuse to accept any Old Notes
and return all tendered Old Notes to the tendering holders, (ii) extend the
Exchange Offer and retain all Old Notes tendered prior to the Expiration Date,
subject, however, to the right of holders to withdraw such Old Notes (see
"--Terms of the Exchange Offer--Withdrawal of Tenders of Old Notes"), or (iii)
waive such unsatisfied conditions with respect to the Exchange Offer and accept
all validly tendered Old Notes which have not been withdrawn. If such waiver
constitutes a material change to the Exchange Offer, the Company will promptly
disclose such waiver by means of a prospectus supplement that will be
distributed to the registered holders, and the Company will extend the Exchange
Offer for a period of time, depending upon the significance of the waiver and
the manner of disclosure to the registered holders, if the Exchange Offer would
otherwise expire during such period.
EXCHANGE AGENT
United States Trust Company of New York has been appointed as Exchange Agent
for the Exchange Offer. Questions and requests for assistance, requests for
additional copies of this Prospectus or of the Letter of Transmittal and
requests for Notices of Guaranteed Delivery should be directed to the Exchange
Agent addressed as follows:
<TABLE>
<S> <C> <C>
By Mail: By Overnight Courier: By Hand:
United States Trust Company United States Trust Company United States Trust Company
of New York of New York of New York
P. O. Box 844 Corporate Trust Operations 111 Broadway
Cooper Station Department Lower Level
New York, NY 10276-0844 770 Broadway - 13th Floor New York, NY 10006
Attn: Corporate Trust New York, NY 10003 Attn: Corporate Trust
Services Services
(registered or certified mail
recommended)
By Facsimile:
(212) 420-6152
(For Eligible Institutions Only)
Confirm by Telephone:
(800) 548-6565
</TABLE>
27
<PAGE>
FEES AND EXPENSES
The expenses of soliciting tenders will be borne by the Company. The
principal solicitation is being made by mail; however, additional solicitation
may be made by telecopy, telephone or in person by officers and regular
employees of the Company and its affiliates. No additional compensation will be
paid to any such officers and employees who engage in soliciting tenders.
The Company has not retained any dealer-manager or other soliciting agent in
connection with the Exchange Offer and will not make any payments to brokers,
dealers or others soliciting acceptance of the Exchange Offer. The Company,
however, will pay the Exchange Agent reasonable and customary fees for its
services and will reimburse it for its reasonable out-of-pocket expenses in
connection therewith. The Company may also pay brokerage houses and other
custodians, nominees and fiduciaries the reasonable out-of-pocket expenses
incurred by them in forwarding copies of this Prospectus, the Letter of
Transmittal and related documents to the beneficial owners of the Old Notes and
in handling or forwarding tenders for exchange.
The expenses to be incurred in connection with the Exchange Offer will be
paid by the Company. Such expenses include fees and expenses of the Exchange
Agent and transfer agent and registrar, accounting and legal fees and printing
costs, among others.
The Company will pay all transfer taxes, if any, applicable to the exchange
of the Old Notes pursuant to the Exchange Offer. If, however, New Notes, or Old
Notes for principal amounts not tendered or accepted for exchange, are to be
delivered to, or are to be issued in the name of, any person other than the
registered holder of the Old Notes tendered or if a transfer tax is imposed for
any reason other than the exchange of the Old Notes pursuant to the Exchange
Offer, then the amount of any such transfer taxes (whether imposed on the
registered holder or any other persons) will be payable by the tendering holder.
If satisfactory evidence of payment of such taxes or exemption therefrom is not
submitted with the Letter of Transmittal, the amount of such transfer taxes will
be billed directly to such tendering holder.
CONSEQUENCES OF FAILURE TO EXCHANGE
The Old Notes that are not exchanged for New Notes pursuant to the Exchange
Offer will remain restricted securities within the meaning of Rule 144 of the
Securities Act. Accordingly, such Old Notes may be resold only (i) to the
Company or any subsidiary thereof, (ii) to a qualified institutional buyer in
compliance with Rule 144A, (iii) to an institutional accredited investor that,
prior to such transfer, furnishes to the Trustee a signed letter containing
certain representations and agreements relating to the restrictions on transfer
of the Old Notes (the form of which letter can be obtained from the Trustee)
and, if such transfer is in respect of an aggregate principal amount of Old
Notes at the time of transfer of less than $100,000, an opinion of counsel
acceptable to the Company that such transfer is in compliance with the
Securities Act, (iv) outside the United States in compliance with Rule 904 under
the Securities Act, (v) pursuant to the exemption from registration provided by
Rule 144 under the Securities Act (if available), or (vi) pursuant to an
effective registration statement under the Securities Act. The liquidity of the
Old Notes could be adversely affected by the Exchange Offer. Following the
consummation of the Exchange Offer, holders of the Senior Preferred Stock will
have no further registration rights under the Registration Rights Agreement and
will not be entitled to the contingent increase in the dividend rate applicable
to the Old Notes.
28
<PAGE>
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
The Unaudited Pro Forma Combined Statements of Operations and other
financial data for the year ended December 31, 1997, and for the six months
ended June 30, 1998, and the Unaudited Pro Forma Combined Balance Sheet at June
30, 1998, reflect the historical results and the historical financial position,
respectively, of the Company, adjusted to give effect to the Offering and the
application of the net proceeds therefrom, the completion of the Worland Field
Acquisition and the related financing, as though each of the transactions had
occurred on January 1, 1997 with regard to the Unaudited Pro Forma Combined
Statements of Operations and on June 30, 1998 with regard to the Unaudited Pro
Forma Combined Balance Sheet. The pro forma adjustments are based upon available
information and assumptions that management of the Company believes are
reasonable. The Unaudited Pro Forma Consolidated Financial Statements do not
purport to represent the financial position or results of operations which would
have occurred had such transactions been consummated on the dates indicated or
the Company's financial position or results of operations for any future date or
period. The Unaudited Pro Forma Consolidated Financial Statements and notes
thereto should be read in conjunction with the Financial Statements included
elsewhere in this Prospectus.
29
<PAGE>
CONTINENTAL RESOURCES, INC.
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
AT JUNE 30, 1998
<TABLE>
<CAPTION>
ADJUSTMENTS
--------------------------------------------
JUNE 30, WORLAND FIELD
1998 ACQUISITION COMBINING OFFERING PRO FORMA
----------- -------------- ----------- --------------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................... $ 1,336 $ 19,581(a) $ 1,336 $ 145,335(c) $ 2,113
(19,581)(b) (140,669)(d)
(3,889)(e)
Accounts receivable:
Oil and gas sales.......................... 6,350 6,350 6,350
Joint interest and other................... 9,383 9,383 9,383
Inventories.................................. 4,963 4,963 4,963
Prepaid expenses............................. 360 360 360
Advances to affiliates....................... 19,625 (19,581)(a) 44 44
----------- -------------- ----------- --------------- -----------
Total current assets........................... 42,017 (19,581) 22,436 777 23,213
----------- -------------- ----------- --------------- -----------
Oil and gas properties(f):
Producing properties......................... 233,600 233,600 233,600
Non-producing properties..................... 49,029 49,029 49,029
Gas gathering and processing facilities........ 22,561 22,561 22,561
Service properties, equipment and other........ 13,650 13,650 13,650
----------- -------------- ----------- --------------- -----------
Total property and equipment, net.............. 318,840 -- 318,840 318,840
Less--accumulated depreciation, depletion and
amortization.................................. (103,918) (103,918) (103,918)
----------- -------------- ----------- -----------
Net property and equipment..................... 214,922 -- 214,922 214,922
3,889(e)
Other assets................................... 924 924 4,665(c) 9,478
----------- -------------- ----------- --------------- -----------
Total assets................................... $ 257,863 $ (19,581) $ 238,282 $ 9,331 $ 247,613
----------- -------------- ----------- --------------- -----------
----------- -------------- ----------- --------------- -----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................. $ 12,235 $ 12,235 $ 12,235
Current portion of long-term debt............ 315 315 315
Revenues and royalties payable............... 3,654 3,654 3,654
Accrued liabilities and other................ 2,951 2,951 2,951
----------- -------------- ----------- --------------- -----------
Total current liabilities...................... 19,155 -- 19,155 19,155
----------- -------------- ----------- --------------- -----------
Long-term debt, net of current portion......... 163,737 (19,581)(b) 144,156 $ 150,000(c) 153,487
(140,669)(d)
Other non-current liabilities.................. 206 206 206
Stockholders' equity........................... 74,765 74,765 74,765
----------- -------------- ----------- --------------- -----------
Total liabilities and stockholders' equity..... $ 257,863 $ (19,581) $ 238,282 $ 9,331 $ 247,613
----------- -------------- ----------- --------------- -----------
----------- -------------- ----------- --------------- -----------
</TABLE>
See Notes to Unaudited Pro Forma Combined Balance Sheet.
30
<PAGE>
NOTES TO UNAUDITED PRO FORMA COMBINED BALANCE SHEET
(a) To record payment by principal shareholder for balance owed on sale of
Worland Field Properties.
(b) To apply proceeds from principal shareholder received on sale of Worland
Field Properties to outstanding balance owed on Credit Facility.
(c) To record the proceeds from the Offering, net of Offering costs of $4.7
million, and the related debt.
(d) To record the use of the net proceeds of the Offering to reduce debt
outstanding under the Credit Facility.
(e) To record a $3.9 million settlement of a forward interest rate swap contract
which the Company entered into in May 1998 to hedge its exposure to changes
in prevailing interest rates in connection with the Old Notes Offering. Due
to changes in interest rates for U.S. treasury notes, the Company was
required to pay $3.9 million, which will result in an increase of
approximately 0.5% to the Company's effective interest rate on the Notes and
which will increase interest expense on the Notes by approximately $0.4
million per year through 2008.
(f) See "Business and Properties--Oil and Gas Reserves" for information
regarding pro forma reserve quantities and the standardized measure of
discounted cash flows with respect to such pro forma reserve quantities.
31
<PAGE>
CONTINENTAL RESOURCES, INC.
UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
ADJUSTMENTS
--------------------------------------------
WORLAND FIELD
HISTORICAL ACQUISITION COMBINING OFFERING PRO FORMA
----------- -------------- ----------- --------------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenue:
Oil and gas sales.......................... $ 78,599 $ 10,126(a) $ 88,725 $ 88,725
Gathering, marketing and processing........ 25,021 25,021 25,021
Oil and gas service operations............. 6,405 6,405 6,405
----------- -------------- ----------- -----------
Total revenues............................... 110,025 10,126 120,151 120,151
Operating costs and expenses:
Production expenses and taxes.............. 20,748 5,210(a) 25,958 25,958
Exploration expenses....................... 6,806 6,806 6,806
Gathering, marketing and processing........ 22,715 22,715 22,715
Oil and gas service operations............. 3,654 3,654 3,654
Depreciation, depletion and amortization... 33,354 1,116(b) 34,470 $ 460(c) 35,319
389(d)
General and administrative................. 8,990 8,990 8,990
----------- -------------- ----------- --------------- -----------
Total operating costs and expenses........... 96,267 6,326 102,593 849 103,442
----------- -------------- ----------- --------------- -----------
Operating income............................. 13,758 3,800 17,558 (849) 16,709
Interest income.............................. 241 241 1,350(e) 1,591
Interest expense............................. (4,804) (4,804) (10,880)(f) (15,684)
Other income (expense), net.................. 8,061 8,061 8,061
----------- -------------- ----------- --------------- -----------
Income before income taxes................... 17,256 3,800 21,056 (10,379) 10,677
Federal and state income taxes (benefit)..... (8,941) (8,941) (8,941)
----------- -------------- ----------- --------------- -----------
Net income................................... $ 26,197 $ 3,800 $ 29,997 $ (10,379) $ 19,618
----------- -------------- ----------- --------------- -----------
----------- -------------- ----------- --------------- -----------
</TABLE>
- --------------------------
(a) To record the revenues and direct operating expenses attributable to the
Company's net interest in oil and gas properties acquired in the Worland
Field Acquisition for the periods indicated.
(b) To record estimated pro forma depreciation, depletion and amortization
related to the Company's net interest in the Worland Field properties as if
the Worland Field Acquisition had occurred on January 1, 1997. The estimated
pro forma depreciation, depletion and amortization was at an average rate of
$1.53 per Boe based on an allocation of the purchase price to the individual
properties acquired and the actual production during the year ended December
31, 1997.
(c) To record the pro forma amortization of estimated costs of the Offering,
assuming the Offering was completed on January 1, 1997.
(d) To record the pro forma amortization expense of capitalized interest rate
hedge associated with the sale of the Old Notes assuming such sale was
completed on January 1, 1997. In May 1998, the Company entered into a
forward interest rate swap contract to hedge its exposure to changes in
prevailing interest rates. Due to changes in treasury note rates, the
Company paid $3.9 million to settle the forward interest rate swap contract.
This payment will result in an increase of approximately 0.5% to the
Company's effective interest rate or an increase in interest expense of
approximately $0.4 million per year over the next 10 years.
(e) To record the estimated pro forma interest income resulting from an
investment at a 5% interest rate of the net proceeds of the Offering
remaining after payment of the Credit Facility, assuming the Offering was
consummated on January 1, 1997.
(f) To record the pro forma effect of interest expense related to the Notes
assuming (i) the Offering occurred on January 1, 1997 and (ii) the net
proceeds from the Offering are used to reduce debt outstanding under the
Credit Facility which was incurred to finance the Worland Field Acquisition,
and taking into consideration the proceeds from the sale of a 50% interest
in the Worland Field properties to the Company's principal shareholder as if
the sale had occurred on January 1, 1997.
32
<PAGE>
CONTINENTAL RESOURCES, INC.
UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1998
<TABLE>
<CAPTION>
ADJUSTMENTS
-----------------------------------------
WORLAND FIELD
HISTORICAL ACQUISITION COMBINING OFFERING PRO FORMA
----------- ------------- ----------- ------------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenue:
Oil and gas sales............................ $ 31,291 $ 2,127(a) $ 33,418 $ 33,418
Gathering, marketing and processing.......... 9,804 9,804 9,804
Oil and gas service operations............... 3,062 3,062 3,062
----------- ------------- ----------- -----------
Total revenues................................. 44,157 2,127 46,284 0 46,284
----------- ------------- ----------- -----------
Operating costs and expenses:
Production expenses and taxes................ 9,074 1,268(a) 10,342 10,342
Exploration expenses......................... 2,650 2,650 2,650
Gathering, marketing and processing.......... 8,409 8,409 8,409
Oil and gas service operations............... 1,825 1,825 1,825
Depreciation, depletion and amortization..... 16,483 1,025(b) 17,508 $ 233(c) 17,935
194(d)
General and administrative................... 4,914 4,914 4,914
----------- ------------- ----------- ------------- -----------
Total operating costs and expenses............. 43,355 2,293 45,648 427 46,075
----------- ------------- ----------- ------------- -----------
Operating income............................... 802 (166) 636 (427) 209
Interest income................................ 780 780 50(e) 830
Interest expense............................... (5,174) (5,174) (2,662)(f) (7,836)
Other income (expense), net.................... 92 92 92
----------- ------------- ----------- ------------- -----------
Total other income and (expenses).............. (4,302) -- (4,302) (2,612) (6,914)
Income (loss) before income taxes.............. (3,500) (166) (3,666) (3,039) (6,705)
Federal and state income taxes................. 0 0 0 0 0
----------- ------------- ----------- ------------- -----------
Net income (loss).............................. $ (3,500) $ (166) $ (3,666) $ (3,039) $ (6,705)
----------- ------------- ----------- ------------- -----------
----------- ------------- ----------- ------------- -----------
Earnings (loss) per common share............... $ (71.37) $ (74.75) $ (136.73)
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
- --------------------------
(a) To record the revenues and direct operating expenses attributable to the
Company's net interest in oil and gas properties acquired in the Worland
Field Acquisition for the periods indicated.
(b) To record the estimated pro forma depreciation, depletion and amortization
related to the Company's net interest in the Worland Field properties as if
the Worland Field Acquisition had occurred on January 1, 1997. The estimated
pro forma depreciation, depletion and amortization was at an average rate of
$3.16 per Boe based on an estimated allocation of the purchase price to the
individual properties acquired in 1998 and the actual production during the
six months ended June 30, 1998.
(c) To record the pro forma amortization of estimated costs of the Offering,
assuming the Offering was completed on January 1, 1997.
(d) To record the pro forma amortization expense of capitalized interest rate
hedge associated with the sale of the Old Notes assuming such sale was
completed on January 1, 1997. In May 1998, the Company entered into a
forward interest rate swap contract to hedge its exposure to changes in
prevailing interest rates. Due to changes in treasury note rates, the
Company paid $3.9 million to settle the forward interest rate swap contract.
This payment will result in an increase of approximately 0.5% to the
Company's effective interest rate or an increase in interest expense of
approximately $0.4 million per year over the next 10 years.
(e) To record the estimated pro forma interest income resulting from an
investment at a 5% interest rate of the net proceeds of the Offering
remaining after payment of the Credit Facility, assuming the Offering was
consummated on January 1, 1997.
(f) To record the pro forma effect of interest expense related to the Notes
assuming (i) the Offering occurred on January 1, 1997 and (ii) the net
proceeds from the Offering are used to reduce debt outstanding under the
Credit Facility which was incurred to finance the Worland Field Acquisition,
and taking into consideration the proceeds from the sale of a 50% interest
in the Worland Field properties to the Company's principal shareholder as if
the sale had occurred on January 1, 1997.
33
<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth selected historical consolidated financial
data for the periods ended and as of the dates indicated. The statements of
operations and other financial data for the periods ended December 31, 1994,
1995, 1996 and 1997, and the balance sheet data as of December 31, 1995, 1996
and 1997 have been derived from, and should be reviewed in conjunction with, the
consolidated financial statements of the Company, and the notes thereto, which
have been audited by Arthur Andersen LLP, independent public accountants. The
statements of operations and other financial data for the periods ended December
31, 1993, June 30, 1997 and June 30, 1998, and the balance sheet data as of
December 31, 1994, June 30, 1997 and June 30, 1998, have been derived from the
unaudited financial statements of the Company, which, in the opinion of
management, include all adjustments necessary to present fairly the data for
such periods. The financial statements as of December 31, 1996, December 31,
1997 and June 30, 1998 and for the years ended December 31, 1995, 1996 and 1997
and for the periods ended June 30, 1997 and June 30, 1998 are included elsewhere
in this Prospectus. The data should be read in conjunction with
"Capitalization," "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Financial Statements and the related notes
thereto included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
SIX
MONTHS
ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------------------------------------- ---------
1993 1994 1995 1996 1997 1997
--------- --------- --------- --------- --------- ---------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and gas sales........................................... $ 16,002 $ 21,427 $ 30,576 $ 75,016 $ 78,599 $ 39,135
Gathering, marketing and processing......................... 3,061 14,806 20,639 25,766 25,021 15,522
Oil and gas service operations.............................. 3,063 5,630 6,148 6,491 6,405 3,715
--------- --------- --------- --------- --------- ---------
Total revenues................................................ 22,126 41,863 57,363 107,273 110,025 58,372
Operating costs and expenses:
Production expenses and taxes............................... 2,455 6,905 7,611 19,338 20,748 10,622
Exploration expenses........................................ 1,996 6,338 6,184 4,512 6,806 3,410
Gathering, marketing and processing......................... 2,436 8,415 13,223 21,790 22,715 12,873
Oil and gas service operations.............................. 1,975 2,708 3,680 4,034 3,654 1,855
Depreciation, depletion and amortization.................... 4,816 6,068 9,614 22,876 33,354 16,713
General and administrative.................................. 3,658 6,396 8,260 9,155 8,990 3,986
--------- --------- --------- --------- --------- ---------
Total operating costs and expenses............................ 17,336 36,830 48,572 81,705 96,267 49,459
--------- --------- --------- --------- --------- ---------
Operating income.............................................. 4,790 5,033 8,791 25,568 13,758 8,913
Interest income............................................... 138 108 137 312 241 104
Interest expense.............................................. (314) (670) (2,396) (4,550) (4,804) (2,313)
Other revenue (expense), net(1),(2)........................... 4,132 -- (411) 233 8,061 685
--------- --------- --------- --------- --------- ---------
Income before income taxes.................................... 8,746 4,471 6,121 21,563 17,256 7,389
Federal and state income taxes (benefit)(3)................... 2,974 1,596 2,252 8,238 (8,941) (8,941)
--------- --------- --------- --------- --------- ---------
Net income.................................................... $ 5,772 $ 2,875 $ 3,869 $ 13,325 $ 26,197 $ 16,330
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
OTHER FINANCIAL DATA:
Adjusted EBITDA(4)............................................ $ 11,872 $ 17,547 $ 24,315 $ 53,502 $ 54,721 $ 29,825
Net cash provided by operations............................... 12,758 18,787 18,985 41,724 51,477 27,948
Net cash used in investing.................................... (12,402) (19,256) (58,022) (50,619) (78,359) (39,673)
Net cash provided by (used in) financing...................... 2,963 (1,138) 37,994 10,494 24,863 8,556
Capital expenditures(5)....................................... 11,818 20,143 58,226 50,341 80,937 41,678
RATIOS:
Adjusted EBITDA to interest expense........................... 37.8x 26.2x 10.1x 11.8x 11.4x 12.9x
Total debt to Adjusted EBITDA................................. 0.6x 0.4x 1.8x 1.0x 1.5x n/a
Earnings to fixed charges(6).................................. 28.9x 7.7x 3.6x 5.7x 4.6x 4.2x
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents..................................... $ 4,373 $ 2,766 $ 1,722 $ 3,320 $ 1,301 $ 151
Total assets.................................................. 49,592 56,759 107,825 145,693 188,386 159,755
Long-term debt, including current maturities.................. 7,514 6,272 44,265 54,759 79,632 63,325
Stockholders' equity.......................................... 32,008 34,883 38,752 52,077 78,264 68,398
<CAPTION>
1998
---------
<S> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Oil and gas sales........................................... $ 31,291
Gathering, marketing and processing......................... 9,804
Oil and gas service operations.............................. 3,062
---------
Total revenues................................................ 44,157
Operating costs and expenses:
Production expenses and taxes............................... 9,074
Exploration expenses........................................ 2,650
Gathering, marketing and processing......................... 8,409
Oil and gas service operations.............................. 1,825
Depreciation, depletion and amortization.................... 16,483
General and administrative.................................. 4,914
---------
Total operating costs and expenses............................ 43,355
---------
Operating income.............................................. 802
Interest income............................................... 780
Interest expense.............................................. (5,174)
Other revenue (expense), net(1),(2)........................... 93
---------
Income before income taxes.................................... (3,499)
Federal and state income taxes (benefit)(3)................... 0
---------
Net income.................................................... $ (3,499)
---------
---------
OTHER FINANCIAL DATA:
Adjusted EBITDA(4)............................................ $ 20,808
Net cash provided by operations............................... 9,669
Net cash used in investing.................................... (116,132)
Net cash provided by (used in) financing...................... 106,498
Capital expenditures(5)....................................... 116,534
RATIOS:
Adjusted EBITDA to interest expense........................... 4.0x
Total debt to Adjusted EBITDA................................. n/a
Earnings to fixed charges(6).................................. n/a
BALANCE SHEET DATA (AT PERIOD END):
Cash and cash equivalents..................................... $ 1,336
Total assets.................................................. 257,863
Long-term debt, including current maturities.................. 164,052
Stockholders' equity.......................................... 74,765
</TABLE>
See Notes to Selected Consolidated Financial Data.
34
<PAGE>
NOTES TO SELECTED CONSOLIDATED FINANCIAL DATA
(1) In 1993, other income includes $4.0 million resulting from the settlement of
certain litigation matters.
(2) In 1997, other income includes $7.5 million resulting from the settlement of
certain litigation matters.
(3) Effective June 1, 1997, the Company elected to be treated as a S Corporation
for federal income tax purposes. The conversion resulted in the elimination
of the Company's deferred income tax assets and liabilities existing at May
31, 1997 and, after being netted against the then existing tax provision,
resulted in a net income tax benefit to the Company of $8.9 million.
(4) Adjusted EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion, amortization and exploration expense, excluding
proceeds from litigation settlements. Adjusted EBITDA is not a measure of
cash flow as determined in accordance with GAAP. Adjusted EBITDA should not
be considered as an alternative to, or more meaningful than, net income or
cash flow as determined in accordance with GAAP or as an indicator of a
company's operating performance or liquidity. Certain items excluded from
adjusted EBITDA are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and tax
structure, as well as historic costs of depreciable assets, none of which
are components of adjusted EBITDA. The Company's computation of Adjusted
EBITDA may not be comparable to other similarly titled measures of other
companies. The Company believes that Adjusted EBITDA is a widely followed
measure of operating performance and may also be used by investors to
measure the Company's ability to meet future debt service requirements, if
any. Even though the volume of oil and gas produced by the Company during
the six months ended June 30, 1998, on an actual and pro forma basis, was
greater than in the comparable period in 1997, the Company's Adjusted EBITDA
for the 1998 period was less than in 1997. The decrease in Adjusted EBITDA
for the 1998 period was attributable to declines in oil and gas prices.
Adjusted EBITDA does not give effect to the Company's exploration
expenditures, which are largely discretionary by the Company and which, to
the extent expended, would reduce cash available for debt service, repayment
of indebtedness and dividends.
(5) Capital expenditures include costs related to acquisitions of producing oil
and gas properties.
(6) For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income before taxes from continuing operations, plus fixed
charges. Fixed charges consist of interest expense and amortization of costs
incurred in the Offering. For the six months ended June 30, 1998, earnings
were insufficient to cover fixed charges by $3.5 million.
35
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the Company's
consolidated financial statements and notes thereto and the Selected
Consolidated Financial Data included elsewhere herein.
OVERVIEW
The Company's revenue, profitability and cash flow are substantially
dependent upon prevailing prices for oil and gas and the volumes of oil and gas
it produces. Although the Company produced more oil and gas in the first quarter
of 1998 than in the first quarter of 1997, it experienced a significant decline
in revenues, net income and Adjusted EBITDA in the first half of 1998 compared
to the first half of 1997 because of lower prevailing oil and gas prices. These
lower prices have continued to adversely affect the Company's revenues and
results of operation since June 30, 1998. Given the volatile nature of oil and
gas prices, it is difficult to predict whether such effects will continue during
the remainder of 1998. Average prices as of September 30, 1998, on a pro forma
basis, were $12.95 per Bbl of oil and $1.66 per Mcf of natural gas compared to
$18.06 per Bbl of oil and $2.25 per Mcf of natural gas as of December 31, 1997.
If the September 30, 1998 pro forma prices were applied to the Company's
estimated proved reserves as of December 31, 1997, the Company's pro forma PV-10
would have been approximately $208.7 million compared to a pro forma PV-10 of
$267.0 million using December 31, 1997 prices. In addition, the Company's proved
reserves and oil and gas production will decline as oil and gas are produced
unless the Company is successful in acquiring producing properties or conducting
successful exploration and development drilling activities.
The Company uses the successful efforts method of accounting for its
investment in oil and gas properties. Under the successful efforts method of
accounting, costs to acquire mineral interests in oil and gas properties, to
drill and provide equipment for exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. These costs are amortized
to operations on a unit-of-production method based on petroleum engineer
estimates. Geological and geophysical costs, lease rentals and costs associated
with unsuccessful exploratory wells are expensed as incurred. Maintenance and
repairs are expensed as incurred, except that the cost of replacements or
renewals that expand capacity or improve production are capitalized. Significant
downward revisions of quantity estimates or declines in oil and gas prices that
are not offset by other factors could result in a writedown for impairment of
the carrying value of oil and gas properties. Once incurred, a writedown of oil
and gas properties is not reversible at a later date, even if oil or gas prices
increase.
The Company is a S Corporation for federal income tax purposes. The Company
currently anticipates it will pay periodic dividends in amounts sufficient to
enable the Company's shareholders to pay their income tax obligations with
respect to the Company's taxable earnings. Based upon funds available to the
Company under its Credit Facility and the Company's anticipated cash flow from
operating activities, the Company does not currently expect these distributions
to materially impact the Company's liquidity.
36
<PAGE>
RESULTS OF OPERATIONS
The following tables set forth selected financial and operating information
for each of the three years in the period ended December 31, 1997 and for the
six months ended June 30, 1997 and 1998:
<TABLE>
<CAPTION>
YEAR ENDED SIX MONTHS
DECEMBER 31, ENDED JUNE 30,
--------------------------------- --------------------
1995 1996 1997 1997 1998
--------- ---------- ---------- --------- ---------
(DOLLARS IN THOUSANDS, EXCEPT PRICE DATA)
<S> <C> <C> <C> <C> <C>
Revenues................................................ $ 57,363 $ 107,273 $ 110,025 $ 58,372 $ 44,157
Operating expenses...................................... 48,572 81,705 96,267 49,459 43,355
Non-Operating income (expense).......................... (2,670) (4,005) 3,498 (1,524) (4,301)
Net income after tax.................................... 3,869 13,325 26,197 16,330 (3,499)
Adjusted EBITDA(1)...................................... 24,315 53,502 54,721 29,825 20,807
Production Volumes(2):
Oil and condensate (MBbls)............................ 1,199 2,888 3,518 1,615 1,983
Natural gas (MMcf).................................... 5,880 6,527 5,789 2,881 2,933
Oil equivalents (MBoe)................................ 2,179 3,976 4,483 2,095 2,472
Average Prices(3):
Oil and condensate (per Bbl).......................... $ 17.11 $ 20.78 $ 18.61 $ 20.08 $ 13.14
Natural gas (per Mcf)................................. 1.40 2.13 2.21 2.33 1.79
Oil equivalents (per Boe)............................. 14.03 18.87 17.53 18.68 12.66
</TABLE>
- --------------------------
(1) Adjusted EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion, amortization and exploration expense, excluding
proceeds from litigation settlements. Adjusted EBITDA is not a measure of
cash flow as determined in accordance with GAAP. Adjusted EBITDA should not
be considered as an alternative to, or more meaningful than, net income or
cash flow as determined in accordance with GAAP or as an indicator of a
company's operating performance or liquidity. Certain items excluded from
Adjusted EBITDA are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and tax
structure, as well as historic costs of depreciable assets, none of which
are components of Adjusted EBITDA. The Company's computation of Adjusted
EBITDA may not be comparable to other similarly titled measures of other
companies. The Company believes that Adjusted EBITDA is a widely followed
measure of operating performance and may also be used by investors to
measure the Company's ability to meet future debt service requirements, if
any. Even though the volume of oil and gas produced by the Company during
the six months ended June 30, 1998, on an actual and pro forma basis, was
greater than in the comparable period in 1997, the Company's Adjusted EBITDA
for the 1998 period was less than in 1997. The decrease in Adjusted EBITDA
for the 1998 period was attributable to declines in oil and gas prices.
Adjusted EBITDA does not give effect to the Company's exploration
expenditures, which are largely discretionary by the Company and which, to
the extent expended, would reduce cash available for debt service, repayment
of indebtedness and dividends.
(2) Production volumes of oil and condensate, and natural gas, are derived from
the Company's production records and reflect actual quantities produced
without regard to the time of receipt of proceeds from the sale of such
production. Production volumes of oil equivalents (on a Boe basis) are
determined by dividing the total Mcfs of natural gas produced by six and by
adding the resultant sum to barrels of oil and condensate produced.
(3) Average prices of oil and condensate, and of natural gas, are derived from
the Company's production records which are maintained on an "as produced"
basis, which give effect to gas balancing and oil produced and in the tanks,
and, accordingly, may differ from oil and gas revenues for the same periods
as reflected in the Financial Statements. Average prices of oil equivalents
were calculated by dividing oil and gas revenues, as reflected in the
Financial Statements, by production volumes on a per Boe basis. Average sale
prices per Boe realized by the Company, according to its production records
which are maintained on an "as produced" basis, for the years ended December
31, 1995, 1996 and 1997, were $13.19, $18.59 and $17.53, respectively.
37
<PAGE>
SIX MONTHS ENDED JUNE 30, 1998 COMPARED TO SIX MONTHS ENDED JUNE 30, 1997
OIL AND GAS SALES revenue for the six months ended June 30, 1998 decreased
$7.8 million, or 20%, to $31.3 million from $39.1 million for the comparable
period in 1997. Oil price decreases from an average of $20.08 per Bbl in the
period during 1997 to $13.14 per Bbl in 1998 which resulted in an $11.2 million
reduction in revenues. The effect of the price reduction was partially offset by
a 368 MBbl increase in oil production. The increase in production, based on 1998
prices, resulted in $4.8 million of additional revenue for the six month period
in 1998. Gas revenues for the six months ended June 30, 1998 decreased by $1.5
million, or 22%, to $5.2 million from $6.7 million during the comparable period
in 1997, attributable mainly to lower gas prices for the six-month period in
1998 on relatively stable gas volumes. Average prices fell to $1.79 per Mcf
during the six-month period in 1998 from $2.33 per Mcf in the comparable period
in 1997.
GATHERING, MARKETING AND PROCESSING revenue for the six months ended June
30, 1998 was $9.8 million, a decrease of $5.7 million, or 37%, from $15.5
million in the same period in 1997, which was attributable primarily to the
elimination of purchases and resales of third party gas for marketing purposes
and a refocus on purchases to supply the Company's gas plants.
OIL AND GAS SERVICE OPERATIONS revenue for the six months ended June 30,
1998 was $3.1 million, a decrease of $0.6 million, or 18%, compared to $3.7
million in the same period in 1997, which was attributable to declining oil
prices on reclaimed oil sales.
PRODUCTION EXPENSES AND TAXES for the six months ended June 30, 1998 were
$9.1 million, a decrease of $1.5 million, or 15%, compared to $10.6 million in
the same period in 1997, which was attributable to increased production
efficiencies and lower gross production taxes per Boe due to price declines.
EXPLORATION EXPENSES for the six months ended June 30, 1998 were $2.6
million, a decrease of $0.8 million, or 22%, compared to $3.4 million in the
same period in 1997, resulting primarily from a $0.3 million decrease in expired
lease expense and a $0.6 million decrease in geological expense. During the
period from July 1, 1998 through December 31, 1998, leases on approximately
26,000 net leasehold acres, with a cost of $1.4 million, will expire and in
1999, leases on approximately 40,000 net acres, with a cost of $2.2 million,
will expire. The Company has not yet determined if all or any of these leases
will be drilled, renewed or allowed to expire.
GATHERING, MARKETING AND PROCESSING EXPENSE for the six months ended June
30, 1998 was $8.4 million, a $4.5 million, or 35% decrease compared to $12.9
million in the same period in 1997. The decrease was attributable primarily to
the eliminations of purchases of third party gas not used for gas plant supply,
but sold as part of the Company's gas marketing activities.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") EXPENSE for the six months
ended June 30, 1998 was $16.5 million, a $0.2 million, or .1% decrease compared
to $16.7 million in 1997. The insignificant decrease in DD&A expense is
primarily attributable to a reduction in the rate of production on the Company's
older properties, and the fact that the older properties are almost fully
depreciated and incur less depreciation expense each year. The unit rate of DD&A
expense per Boe in the first half of 1998 was $6.95, compared with $7.31 in the
1997 period. The calculations of DD&A for the first half of 1997 were based on
December 31, 1996 reserve reports. These resulted in higher DD&A rates for the
interim period than was seen for the entire year. The December 31, 1997 reserve
reports reflected an increase in reserves due to better pricing and less risk
being assigned to the reserves by reserve engineers.
GENERAL AND ADMINISTRATIVE ("G&A") EXPENSE for the six months ended June 30,
1998 was $4.9 million minus overhead reimbursement of $1.0 million for a net G&A
expense of $3.9 million, or an increase of $1.7 million, or 80%, compared to G&A
expense of $4.0 million in the first half of 1997 minus overhead reimbursement
of $1.8 million for a net G&A expense of $2.2 million. The increase was
primarily due to an employment and benefits increase of $0.5 million and a
reduction of overhead reimbursement of $0.8 million.
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INTEREST EXPENSE for the six months ended June 30, 1998 was $5.2 million, an
increase of $2.9 million, or 124%, compared to $2.3 million in the 1997 period
attributable primarily to higher levels of indebtedness outstanding during 1998.
In May 1998, the Company entered into a forward interest rate swap contract to
hedge its exposure to changes in the prevailing interest rates in connection
with its planned debt offering. Due to the change in treasury note rates, the
Company paid $3.9 million to settle the forward interest rate swap contract,
which will result in an increase of approximately 0.5% to the Company's
effective interest rate, or an annual increase in interest expense of
approximately $2.4 million in 1998.
INTEREST AND OTHER INCOME for the six months ended June 30, 1998 was $0.8
million, an increase of $0.7 million, or 652%, from $0.1 million realized in the
same period in 1997. Other income decreased $0.6 million or 87%, to $0.1 million
for the six months ended June 30, 1998 from $0.7 million for the comparable 1997
period. The decrease was due to lower gains on the sale of assets. The Company
has orally agreed to sell all of its interests in certain Illinois properties to
the operator of the properties. Based on a sales price of $3.5 million, it is
estimated that the Company will recognize a gain of approximately $2.7 million
during 1998.
INCOME BEFORE INCOME TAXES for the six months ended June 30, 1998 was a loss
of $3.5 million, a decrease of $10.9 million, or 147%, from $7.4 million in the
1997 period, attributable primarily to lower revenues from oil and gas sales,
and increased interest expense, partially offset by reduced operations expenses.
NET INCOME for the six months ended June 30, 1998 was a net loss of $3.5
million, a decrease of $19.8 million, or 121%, compared to the 1997 period. Net
income for the period declined by a $14.2 million reduction in revenues because
of lower oil and gas prices which was partially offset by a $6.1 million
reduction in operating expenses, and an increase of $2.9 million in interest
expense. Net income for 1997 also included a $8.9 million tax benefit due to the
"S" election that will not have an impact on 1998 net income.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
OIL AND GAS SALES revenue in 1997 was $78.6 million, an increase of $3.6
million, or 5.0%, over $75.0 million in 1996. In 1997, the Company sold an
aggregate of 3,518 MBbls, a 22% increase over 1996 oil sales of 2,888 MBbls. The
Company's natural gas sales in 1997 aggregated to 5,789 MMcf, an 11% decrease
over its 1996 natural gas sales of 6,527 MMcf. In 1997, the Company received
average prices of $18.61 per Bbl and $2.21 per Mcf, compared to $20.78 per Bbl
and $2.13 per Mcf, respectively, in 1996.
GATHERING, MARKETING AND PROCESSING revenue in 1997 was $25.0 million, a
decrease of $0.8 million, or 3.0%, from $25.8 million in 1996, which was
attributable primarily to lower spot prices for natural gas.
OIL AND GAS SERVICE OPERATIONS revenue in 1997 was $6.4 million, a decrease
of $0.1 million, or 1%, compared to $6.5 million in 1996.
PRODUCTION EXPENSES AND TAXES in 1997 were $20.7 million, an increase of
$1.4 million, or 7%, compared to $19.3 million in 1996, which was attributable
to a 13% increase in production volume offset by a 5% decrease in production
costs per Boe.
EXPLORATION EXPENSES were $6.8 million in 1997, an increase of $2.3 million,
or 51%, compared to $4.5 million in 1996, resulting primarily from a $0.5
million increase in expired lease expense and a $1.0 million increase in 3-D
seismic expenditures.
GATHERING, MARKETING AND PROCESSING EXPENSE in 1997 was $22.7 million, a
$0.9 million, or 4% increase, compared to $21.8 million, which in 1996 was
attributable to reduced margins on natural gas and natural gas liquids.
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OIL AND GAS SERVICE OPERATIONS EXPENSE in 1997 was $3.7 million, a $0.3
million, or 9%, decrease from $4.0 million in 1996, attributable to a reduction
in saltwater disposal activity and warehouse activity.
DD&A EXPENSE in 1997 was $33.4 million, a $10.5 million, or 46% increase
compared to $22.9 million in 1996. DD&A expense related to oil and gas
operations in 1997 was $30.2 million, an $8.6 million, or 40% increase, compared
to $21.6 million in 1996, attributable primarily to higher production levels in
1997. The unit rate of DD&A expense per Boe in 1997 was $6.74, compared with
$5.44 in 1996. The 1997 DD&A rate included $5.0 million of additional impairment
for writedown of certain long-lived assets in accordance with the provisions of
SFAS No. 121, or $1.12 per Boe, while 1996 includes $2.1 million or $0.53 per
Boe. The 1997 per Boe rate of DD&A, before giving effect to the SFAS 121
writedown, increased due to the increased costs to drill and equip 93 net wells
that the Company completed during 1996 and 1997, and with respect to which the
Company is currently recognizing DD&A expense.
G&A EXPENSE for 1997 was $9.0 million minus overhead reimbursement of $2.4
million for a net G&A expense of $6.6 million, which was equal to net G&A
expense of 6.6 million in 1996.
INTEREST EXPENSE in 1997 was $4.8 million, an increase of $0.2 million, or
6%, compared to $4.6 million in 1996, attributable primarily to higher levels of
indebtedness outstanding during 1997.
INTEREST AND OTHER INCOME in 1997 was $8.3 million, a $7.8 million, or
1,560%, increase over $0.5 million realized in 1996. The substantial increase in
1997 was primarily attributable to non-recurring income of approximately $7.5
million resulting from the settlement of certain litigation matters.
INCOME BEFORE INCOME TAXES in 1997 was $17.3 million, a decrease of $4.3
million, or 20%, from $21.6 million in 1996, attributable primarily to increased
production expenses and taxes, exploration expenses, gathering, marketing and
processing expenses and DD&A expense, partially offset by an increase in total
revenues of approximately $10.5 million, which included approximately $7.5
million related to the settlement of certain litigation matters.
NET INCOME in 1997 was $26.2 million, an increase of $12.9 million, or 97%,
compared to $13.3 million in 1996, primarily attributable to an $8.9 million tax
benefit realized in 1997, compared to a $8.2 million tax expense in 1996, and
the recognition of approximately $7.5 million related to the settlement of
certain litigation matters.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
OIL AND GAS SALES revenue in 1996 was $75.0 million, an increase of $44.4
million, or 145%, over $30.6 million in 1995. In 1996, the Company sold an
aggregate of 2,888 MBbls, a 141% increase over 1995 oil sales of 1,199 MBbls.
During 1995 and 1996 the Company drilled 33 and 34 net wells, respectively, and
in December 1995 acquired four High Pressure Air Injection units and 10
individual wells from Koch Exploration Co. Production in 1996 from the wells
drilled in 1995 and 1996 was 407 MBbls and 411 Mbbls, respectively, and
production from the acquired properties added an additional 839 Mbbls of oil to
production. The Company's natural gas sales in 1996 aggregated to 6,527 MMcf, an
11% increase over its 1995 natural gas sales of 5,880 MMcf. In 1996, the Company
received average prices of $20.78 per Bbl and $2.13 per Mcf, compared to $17.11
per Bbl and $1.40 per Mcf, respectively, in 1995.
GATHERING, MARKETING AND PROCESSING revenue in 1996 was $25.8 million, an
increase of $5.2 million, or 25%, from $20.6 million in 1995, attributable to
increased throughput on the Company's natural gas gathering systems.
OIL AND GAS SERVICE OPERATIONS revenue in 1996 was $6.5 million, an increase
of $0.4 million, or 6%, compared to $6.1 million in 1995, attributable to an
increase in warehouse pipe sales.
PRODUCTION EXPENSES AND TAXES in 1996 were $19.3 million, an increase of
$11.7 million, or 154%, compared to $7.6 million in 1995, attributable to
increased production volumes.
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EXPLORATION EXPENSES in 1996 were $4.5 million, a decrease of $1.6 million,
or 27%, compared to $6.2 million in 1995, resulting primarily from a reduction
of dry hole expenses of $1.6 million.
GATHERING, MARKETING AND PROCESSING EXPENSE in 1996 was $21.8 million, an
$8.6 million, or 65% increase, compared to $13.2 million in 1995, was
attributable to increased throughput on the Company's natural gas gathering
systems.
OIL AND GAS SERVICE OPERATIONS EXPENSE in 1996 was $4.0 million, a $0.3
million, or 10%, increase from $3.7 million in 1995, attributable to an increase
in repairs on saltwater disposal wells.
DD&A EXPENSE in 1996 was $22.9 million, a $13.3 million, or 138% increase
compared to $9.6 million in 1995. DD&A expense related to oil and gas operations
in 1996 was $21.6 million, a $12.6 million, or 140% increase, compared to $9.0
million in 1995, attributable primarily to higher production levels in 1996. The
unit rate of DD&A expense per Boe in 1996 was $5.44, compared with $3.76 in
1995. The 1996 DD&A rate included $2.1 million of additional impairment for
writedown of certain long-lived assets in accordance with the provisions of SFAS
No. 121, or $0.53 per Boe. In addition to such writedown, the Company's DD&A
rate increased due to the depletion of higher cost horizontal wells and the full
depletion of lower cost mature wells.
G&A EXPENSE in 1996 was $9.2 million minus overhead reimbursed of $2.6
million for a net G&A expense of $6.6 million, an increase of $0.6 million, or
9%, compared to G&A expense of $8.3 million in 1995 minus overhead reimbursement
of $2.3 million for net G&A expense of $6 million. The increase was attributable
to an increase in salaries and hiring of additional employees.
INTEREST EXPENSE in 1996 was $4.6 million, an increase of $2.2 million, or
90%, compared to $2.4 million in 1995, attributable primarily to higher levels
of indebtedness outstanding during 1996 related to drilling activities in North
Dakota.
INTEREST AND OTHER INCOME in 1996 was $0.5 million, a $0.8 million, or 299%,
increase over $(0.3) million realized in 1995. The increase in 1996 was
primarily attributable to gain on the sale of assets.
INCOME BEFORE INCOME TAXES in 1996 was $21.6 million, an increase of $15.5
million, or 252%, from $6.1 million in 1995, attributable primarily to increased
oil and gas sales and gathering, marketing and processing revenues, partially
offset by increases in production expenses and taxes, gathering, marketing and
processing expenses and DD&A expense.
NET INCOME in 1996 was $13.3 million, an increase of $9.4 million, or 244%,
compared to $3.9 million in 1995, primarily attributable to increased income
before income taxes partially offset by a larger income tax expense.
LIQUIDITY AND CAPITAL RESOURCES
During 1997, and the six months ended June 30, 1998, the Company utilized
its beginning cash balance, cash flow from operations and financing provided by
a bank and by the Company's principal shareholder to fund its exploration and
development expenditures, as well as the construction of a natural gas
processing plant and pipeline infrastructure in the Williston Basin.
CASH FLOW FROM OPERATIONS. Net cash provided by operating activities was
$51.5 million for 1997, a 23% and 171% increase from the $41.7 million and $19.0
million in 1996 and 1995, respectively. Net cash provided by operating
activities was $9.7 million for the six months ended June 30, 1998, a 66%
decrease from the $28.0 million for the six months ended June 30, 1997. Cash and
short-term cash investments decreased to $1.3 million at December 31, 1997, from
$3.3 million at year-end 1996, and increased to $1.3 million at June 30, 1998,
from $.2 million at June 30, 1997.
RESERVES ADDED AND FINDING COST. During 1997 and the six months ended June
30, 1998, the Company spent $59.5 million and $114.0 million, respectively, on
acquisitions, exploration, exploitation
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and development of oil and gas properties. The 1998 amount includes the
acquisition of the Worland Field properties. Total estimated proved reserves of
natural gas decreased from 50.5 Bcf at year-end 1996 to 49.4 Bcf at year-end
1997, and estimated total proved oil reserves increased from 19.5 MMBbls at
year-end 1996 to 24.7 MMBbls at year-end 1997.
FINANCING. Long-term debt at December 31, 1997 and June 30, 1998 was $79.3
million and $163.7 million, respectively. The $84.4 million, or 106%, increase
was mainly due to the acquisition of approximately $86.5 million of producing
and non-producing oil and gas properties and certain other related assets in the
Worland Field effective as of June 1, 1998.
CREDIT FACILITY. Long-term debt outstanding under the Credit Facility at
December 31, 1997 and June 30, 1998 included $53.7 million and $160.3 million,
respectively, of revolving credit debt under the Credit Facility. The effective
rate of interest under the Credit Facility was 7.7% at December 31, 1997 and was
7.5% at June 30, 1998. On July 24, 1998 the balance under the Credit Facility
was $162.8 million which was paid off with $19.6 million in proceeds from the
sale of a 50% interest in the Worland Properties and $143.2 million of the
proceeds from the issuance of the Notes. Upon issuance of the Notes and payment
of the outstanding balance on the Credit Facility the Credit Facility was
amended to a $75.0 million Credit Facility with a $75.0 million borrowing base.
The Credit Facility matures May 14, 2001. The Credit Facility provides for
interest based on the prime rate of Bank One Oklahoma, N.A., or the London
Interbank Offered Rate for 1, 2, 3 or 6-month offshore deposits as offered by
Bank One to major banks in the London Interbank Market, rounded upwards, if
necessary, to the nearest 1/16%, and adjusted for maximum cost of reserves, if
any. As of October 31, 1998 the Company has borrowed $3.0 million against this
Credit Facility.
SENIOR NOTES. On July 24, 1998, the Company consummated a private sale of
$150.0 million principal amount of Old Notes. Interest on the Old Notes (and New
Notes issued in exchange therefor) accrues at an annual rate of 10 1/4% and is
payable semiannually on each February 1 and August 1, commencing February 1999.
Approximately $143.2 million of the net proceeds from the sale of the Old Notes
was used to reduce indebtedness under the Credit Facility, which indebtedness
had been incurred in order to consummate the Worland Field Acquisition. As a
result of the issuance of the Old Notes the maturity of the Company's
outstanding indebtedness was extended from four to ten years, availability under
the Company's Credit Facility was increased by $50 million, and the interest
rate on outstanding indebtedness was increased by 2.5%. The issuance of the Old
Notes and the application of the net proceeds therefrom has not adversely
impacted the Company's liquidity.
CAPITAL EXPENDITURES. The Company expects higher production volumes in 1998
compared to 1997. The expected increase in volume is primarily due to the
production associated with the Worland Field properties, as well as certain new
oil and gas properties expected to commence production during the year. Revenue
in 1998, however, has been and continues to be adversely impacted by lower
prevailing oil and gas prices, which are expected to remain volatile. The
Company's 1998 capital expenditures budget is $45.4 million, exclusive of
acquisitions. During the six months ended June 30, 1998, the Company incurred
$30.0 million of capital expenditures, exclusive of acquisitions. The Company
expects to fund the 1998 capital budget through cash flow from operations and
its Credit Facility.
PURCHASE OF WORLAND FIELD. On May 18, 1998, the Company consummated the
purchase for approximately $86.5 million of producing and non-producing oil and
gas properties and certain other related assets in the Worland Properties
effective as of June 1, 1998, which the Company funded through borrowings on its
line of credit. Subsequently, and effective June 1, 1998, the Company sold an
undivided 50% interest in the Worland Properties (excluding inventory and
certain equipment) to the Company's principal stockholder for approximately
$42.6 million. Of the total sale price to the stockholder, approximately
$23,000,000 plus interest of approximately $.3 million was offset against the
outstanding balance of notes payable to the stockholder and approximately $19.6
million was recorded as an increase in advances to affiliates in the
accompanying June 30, 1998 consolidated condensed balance sheet. Based on
current
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contract prices and production levels, proceeds from the sale of oil produced by
the Worland Field properties are sufficient to cover operating costs and
interest expense. The Company expects that the development potential of its
Worland Field properties should increase future cash flows from such properties.
At present, the Worland Field Acquisition has not materially affected the
Company's liquidity.
SHAREHOLDER DISTRIBUTION. The 1997 tax returns of the Company's
shareholders are expected to be filed by October 15, 1998. The Company expects
to distribute a dividend of approximately $2.5 million to its shareholders prior
to December 31, 1998 to cover the shareholders' 1997 tax liability. Because of
funds available to the Company under its Credit Facility, such dividend will not
have a material effect on the Company's liquidity.
YEAR 2000. The Company is reviewing its computer software and hardware,
telecommunications systems, process control systems and business relationships
to locate potential operational problems associated with the year 2000.
The Company's computer consultant has reviewed the Company's mainframe
hardware and operating software and updates to both have been performed. One
additional programming change has been provided for the operating system, and it
will be installed before the end of 1998. At that time the Company believes the
mainframe computer system will be year 2000 compatible. The financial software
package utilized on the mainframe computer has already been tested and updated
by the software vendor. The Company is in the process of developing a plan to
further test the financial software during the first quarter of 1999 to insure
the compatibility of the software with the year 2000. Assessment of other less
critical software systems and various types of computer equipment is continuing
and should be completed by November 1998. The Company believes that the
potential impact, if any, of these systems not being year 2000 compliant may, at
most, require employees to manually complete otherwise automated tasks or
calculations.
The telephone system billing software utilized in tracking telephone usage
is known to be incompatible with the year 2000. A plan is already in place to
increase the capacity of the telephone system and new software will be installed
at that time to make the system year 2000 compatible. The cost of this update
will be less than $15,000. The Company believes that the radios being used for
communications with field operations will not be impacted. The Company also
relies on various public telephone companies to supply normal voice and
electronic data service and service to operating locations which utilize process
control alarms. These alarms notify Company personnel if there are operations
abnormalities that need to be checked and, if necessary, corrected. If the
telephone service were disrupted, the operations would need to be more closely
monitored by Company personnel, but because the operations are not actually
controlled through the phone systems, there should be no interruption in
operations. Surveys will be made of all telephone companies to determine their
system readiness and contingency plans will be developed for those areas where
service that is year 2000 compliant has not been verified.
The gas measurement systems and gas processing facilities that the Company
operates use various Program Logic Controllers ("PLC's") and alarm mechanisms.
The Company has been verbally notified that the measurement systems that it
currently uses are year 2000 compatible and Company tests have been done to
verify that information. The dates on test meters were adjusted to December 29,
1999 and the meters were ran for several days. When the meters rolled to the
year 2000, and for several days after the change to the new year, there were no
complications encountered. However, the Company utilizes a third party for gas
chart integration and has not verified the readiness of that company to
integrate charts which cross into the year 2000. The Company will include the
third party in surveys to be sent to vendors prior to the end of March, 1999. At
this time there has been no action taken to evaluate the gas processing
facilities for potential problem areas. The management of these facilities has
been notified of the need to evaluate the systems and is in the process of
putting together a plan of action which will coincide with routine maintenance.
The Company believes that the PLC and alarms at its Medicine Pole Hills Gas
Plant are the most likely to be at risk for incompatibility and could be
replaced at a cost of about $20,000.
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There can be no guarantee that the systems of other companies on which the
Company's systems rely will be timely converted, or that a failure to convert by
another company, or a conversion that is incompatible with the Company's systems
would not have a material adverse effect on the Company. The Company will be
evaluating its relationships with third parties to determine any critical
services, suppliers, or customers. The third parties will include financial
services, utility services, oil and gas purchasers and parts and supply vendors.
Once critical relationships have been identified the third parties will be
surveyed and their preparedness for year 2000 evaluated. If the Company believes
that the third parties have not minimized risk satisfactorily it will evaluate
alternatives to the current relationships. The survey and evaluation of
preparedness should be completed by June 30, 1999.
The Company believes that there is minimal risk associated with internal
operating systems in relation to year 2000 compatibility. Plans are already in
place to address known areas of incompatibility at costs estimated to be less
than $100,000. Because of the immaterial nature of the expenditures on an
individual basis, the Company plans to finance all costs through normal
operating funds.
HEDGING. From time to time, the Company may use energy swap and forward
sale arrangements to reduce its sensitivity to oil and gas price volatility.
However, the Company had no energy swap or forward sale arrangement in place at
December 31, 1997 or at June 30, 1998. The Company plans to reduce its hedging
transactions. In August, 1998, the Company began engaging in oil trading
arrangements as part of its oil and gas marketing activities. See "Business--Oil
and Gas Marketing."
The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119 "Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments" and does not use them for
trading purposes. The Company's objective is to hedge a portion of its exposure
to price volatility from producing oil and natural gas. These arrangements
expose the Company to the credit risk of its counterparties and to basis risk.
In connection with the Notes Offering, the Company entered into an interest
rate hedge on which it experienced a $3.9 million loss. The Company has no
present plans to engage in further interest rate hedges. See "Unaudited Pro
Forma Consolidated Financial Statements."
OTHER. The Company follows the "sales method" of accounting for its gas
revenue, whereby the Company recognizes sales revenue on all gas sold,
regardless of whether the sales are proportionate to the Company's ownership in
the property. A liability is recognized only to the extent that the Company has
a net imbalance in excess of its share of the reserves in the underlying
properties. The Company's historical aggregate imbalance positions have been
immaterial. The Company believes that any future periodic settlements of gas
imbalances will have little impact on its liquidity.
The Company has sold a number of non-strategic oil and gas properties and
other properties over the past three years, recognizing a pretax loss of
approximately $411,000 in 1995, and pretax gains of approximately $233,000 and
$674,000 in 1996 and 1997, respectively. Total amounts of oil and gas reserves
associated with these dispositions during the last three years were 294 MBbls of
oil and 2,298 MMcf of natural gas. The Company recently initiated, and is
currently pursuing, litigation with Burlington in connection with the agreement
dated May 15, 1998, which provided for the exchange of undivided interests in
the Cedar Hills Field. See "Business and Properties--Rocky Mountains." In the
event the Company is unsuccessful in such litigation, Management does not
believe that such adverse result would have a material adverse impact upon the
financial position, results of operations and liquidity of the Company in the
future. However, should the Company be unable to complete the exchange of
undivided interests in the Cedar Hills Field with Burlington, it is unlikely
that the Company's enhanced secondary recovery operations planned for the Cedar
Hills Field would occur. In such event, the Company's ultimate recovery from its
interests in the Cedar Hills Field would be limited to reserves recovered
through primary drilling activities.
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BUSINESS AND PROPERTIES
GENERAL
Continental is engaged in the development, exploitation, exploration and
acquisition of oil and gas reserves, primarily in the Rocky Mountains and the
Mid-Continent and, to a lesser extent, in the Gulf Coast region of Texas and
Louisiana. In addition to its exploration, development and production
activities, the Company owns and operates 1,000 miles of natural gas pipelines,
five gas gathering systems and three gas processing plants in its operating
areas. The Company also engages in natural gas marketing, gas pipeline
construction and saltwater disposal. Capitalizing on its growth through the
drill-bit and its acquisition strategy, on a pro forma basis the Company has
increased its estimated proved reserves from 12.7 MMBoe in 1993 to 64.9 MMBoe in
1997, and increased its annual production from 2.0 MMBoe in 1993 to 5.2 MMBoe in
1997. At December 31, 1997, on a pro forma basis, approximately 80% of the
Company's estimated proved reserves were oil and approximately 63% of its total
estimated reserves were classified as proved developed. At June 30, 1998, the
Company had interests in 1,399 producing wells of which it operated 1,114.
The Company's Rocky Mountain activities are concentrated in the Williston
and Big Horn Basins. The Company's operations in the Williston Basin are focused
on the Cedar Hills Field, which the Company believes is, potentially, one of the
largest onshore discoveries in the lower 48 states since 1971. The Cedar Hills
Field represented approximately 45% of the PV-10 attributable to the Company's
estimated proved reserves at December 31, 1997, on a pro forma basis. In the
Williston Basin, the Company owns approximately 465,000 net leasehold acres and
has interests in 328 gross (255 net) wells, has identified 105 potential
drilling locations and conducts both primary drilling and enhanced recovery
operations. The Company recently expanded its activities into the Big Horn Basin
through the acquisition of producing and non-producing properties in the Worland
Field. The Company currently owns approximately 35,000 net leasehold acres in
the Big Horn Basin and has interests in 292 gross (127 net) producing wells
which, on a pro forma basis, represented approximately 10% of the PV-10
attributable to the Company's estimated proved reserves at December 31, 1997,
and it operates 272 of such wells. In the Big Horn Basin the Company has
identified 164 potential drilling locations which represent significant
opportunities.
The Company's Mid-Continent activities are conducted primarily in the
Anadarko Basin of western Oklahoma, southwestern Kansas and the Texas Panhandle
and, to a lesser extent, in the Arkoma Basin of southeastern Oklahoma and in
southern Illinois. At December 31, 1997 the Company's Anadarko Basin properties
represented approximately 95% of the PV-10 attributable to the Company's
estimated proved reserves in the Mid-Continent and approximately 36% of the
Company's total estimated proved reserves, on a pro forma basis. In the Anadarko
Basin the Company owns approximately 55,000 net leasehold acres, has interests
in 661 gross (408 net) producing wells and has identified 11 potential drilling
locations. The Company also owns leasehold interests and expects to expand its
exploration activities in the Arkoma Basin and Gulf Coast region of Texas and
Louisiana.
The Company was originally formed in 1967 as Shelly Dean Oil Company to
explore, develop and produce oil and gas properties in Oklahoma. In 1991, the
Company changed its name to Continental Resources, Inc. In 1993, the Company
acquired interests in the Williston Basin and expanded its operations into that
area and has since focused its operations in the Rocky Mountains.
The Company formed Continental Gas, Inc. as a gas marketing company in April
1990. Continental Gas , Inc. has developed into a company specializing in gas
marketing, pipeline construction, gas gathering systems and gas plant
operations.
45
<PAGE>
BUSINESS STRENGTHS
The Company believes that it has certain strengths that provide it with
significant competitive advantages, including the following:
PROVEN GROWTH RECORD. Continental has demonstrated consistent growth
through a balanced program of development and exploratory drilling and
acquisitions. During the five years ended December 31, 1997, the Company
increased proved reserves by 411%, production by 161% and EBITDA by 414%, on a
pro forma basis.
SUBSTANTIAL DEVELOPMENT DRILLING INVENTORY. The Company has identified over
275 potential development drilling locations based on geological and geophysical
evaluations. As of June 30, 1998, on a pro forma basis, the Company held
approximately 583,000 net acres, of which approximately 64% were classified as
undeveloped. Management believes that its current acreage holdings could support
five to seven years of drilling activities based upon oil and gas prices in
effect at June 30, 1998.
LONG-LIFE NATURE OF RESERVES. Continental's producing reserves are
primarily characterized by low rate, relatively stable, mature production that
is subject to gradual decline rates. As a result of the long-lived nature of its
properties, the Company has relatively low reinvestment requirements to maintain
reserve quantities, primary and secondary production levels and reserve values.
At December 31, 1997, on a pro forma basis, the Company's proved reserve life
index was 12.5 years.
SUCCESSFUL DRILLING RECORD. The Company has maintained a successful
drilling record. In the blanket type Red River B formation of the Williston
Basin, the Company's success rate during the three years ended December 31, 1997
was 92%, while in its other areas, the success rate was 65%, resulting in an
overall success rate of 85%. During the five years ended December 31, 1997 the
Company participated in 253 gross (175 net) wells which resulted in the addition
of 24.9 MMBoe at an average cost of $5.50 per Boe.
SIGNIFICANT OPERATIONAL CONTROL. Approximately 94% of the Company's PV-10
at December 31, 1997, on a pro forma basis, was attributable to wells operated
by the Company, giving Continental significant control over the amount and
timing of capital expenditures and production, operating and marketing
activities.
TECHNOLOGICAL LEADERSHIP. The Company has demonstrated significant
expertise in the rapidly evolving technologies of 3-D seismic evaluation and
precision horizontal drilling, and is among the few companies in North America
to successfully utilize high pressure air injection ("HPAI") enhanced recovery
technology on a large scale. Through the combination of precision horizontal
drilling and HPAI secondary recovery technology, the Company has significantly
enhanced the recoverable reserves underlying its oil and gas properties. Since
its inception, Continental has experienced a 300% to 400% increase in
recoverable reserves through use of these technologies.
EXPERIENCED AND COMMITTED MANAGEMENT. Continental's senior management team
has extensive experience in the oil and gas industry. The Chief Executive
Officer, Harold Hamm, began his career in the oil and gas industry in 1967 and
has grown Continental's revenues to $120.2 million in 1997, on a pro forma
basis. Seven senior officers have an average of 20 years of oil and gas industry
experience. Additionally, the Company's technical staff, which includes ten
petroleum engineers and ten geoscientists, has an average of over 20 years
experience in the industry.
BUSINESS STRATEGY
The Company's strategy is to increase reserves, production and cash flow.
Key elements of the Company's strategy are:
MAINTAIN A BALANCED DRILLING PROGRAM. Continental has historically grown
through a balanced program of exploratory and development drilling and
acquisitions. Commencing in 1993, approximately 70%
46
<PAGE>
of wells drilled by the Company have been development wells and the Company
expects a similar balance from its current drilling inventory. Approximately 85%
of the Company's current inventory is focused on further expansion and
development of oil projects in the Rocky Mountains, while the remainder is
focused on natural gas projects in the Mid-Continent and the Gulf Coast. The
Company currently has an inventory of 252 potential development drilling
locations. The Company's drilling budget for 1998 is $36.0 million, which is
expected to fund the drilling of 38 gross (26.6 net) wells; and for the six
months ended June 30, 1998, the Company expended $24.6 million in drilling 25
gross (16.8 net) wells.
MAXIMIZE RESERVE RECOVERY. The Company routinely uses advanced technology
such as precision horizontal drilling, 3-D seismic technology and HPAI
technology in its operations. Management believes that its expertise in
horizontal drilling and its record of over 20 years of successfully utilizing
HPAI technology provide the Company with a distinct competitive advantage for
its development and exploration program. Since its inception, Continental has
drilled 130 and participated in another 27 horizontal wells. The Company
currently operates four of the eight active HPAI projects in North America and
six traditional water-flood projects, and is evaluating three additional
waterflood and two additional HPAI projects, as well as approximately 185
workovers of existing wells. The Company intends to continue to apply HPAI
technology to its Cedar Hills Field and West Medicine Pole Hills properties to
maximize oil recoveries. Based on its experience in operating HPAI projects,
Continental believes that the use of HPAI technology coupled with precision
horizonal drilling in secondary recovery operations will increase total oil
recovery by 300% to 400% over average primary production, or by 50% over
secondary recovery utilizing traditional waterflooding.
ACQUISITIONS OF OIL AND GAS RESERVES. The Company focuses on acquisitions
that (i) complement its existing exploration program, (ii) provide opportunities
to utilize the Company's technological advantages, (iii) have the potential for
enhanced recovery activities, and/or (iv) provide new core areas for the
Company's operations.
MAINTAIN LOW COST STRUCTURE. The management team is committed to a low cost
structure in order to maximize cash flow and earnings. Continental has achieved
low operating and general and administrative costs through economies of scale
and geographic focus. The Company's finding costs are expected to decline over
time as the benefits of secondary recovery methods are realized.
EXPAND GAS GATHERING AND MARKETING. Continental's extensive gas gathering
infrastructure and its regional natural gas marketing operations are integral to
the Company's low cost structure and high revenues per unit of gas production.
The Company intends to expand its gas gathering systems to further improve the
rate of return on drilling and development activities and to increase the
throughput of natural gas from third parties. The gas marketing operation
provides a ready market for increased production, allowing the Company to
increase its marketing of third-party gas as well as its own production.
DEVELOPMENT, EXPLOITATION AND EXPLORATION ACTIVITIES
DEVELOPMENT AND EXPLOITATION. The Company's development and exploitation
activities include drilling of development wells, precision drilling of
horizontal wells, infill drilling, waterfloods, workovers, recompletions and
HPAI projects. The Company's development activities are focused primarily in the
Rocky Mountains, specifically in the Cedar Hills Field, the Medicine Pole Hills,
Buffalo, South Buffalo and West Buffalo Units in the Williston Basin and the
Worland Field in the Big Horn Basin. Approximately 85% of the Company's
development drilling inventory (252 wells) is focused on further expansion and
development of these areas. In addition, the Company is planning two HPAI oil
recovery projects and approximately 156 workovers of existing wells in the Rocky
Mountains. In the Mid-Continent, the Company is evaluating four new waterflood
projects to complement the six waterfloods it currently operates and has 35
workovers planned. All are oil projects in areas where the Company has
operational
47
<PAGE>
experience and technical expertise and benefits from economies of scale. The
following table sets forth information pertaining to the Company's proven
development inventory at June 30, 1998:
<TABLE>
<CAPTION>
NUMBER OF DEVELOPMENT PROJECTS
--------------------------------------------------------------
ENHANCED
DRILLING WORKOVERS AND RECOVERY
LOCATIONS RECOMPLETIONS PROJECTS TOTAL
------------- ----------------- --------------- -----
<S> <C> <C> <C> <C>
ROCKY MOUNTAINS:
Williston Basin......................................... 67 10 2 79
Big Horn Basin.......................................... 158 146 - 304
MID-CONTINENT:
Anadarko Basin.......................................... 11 30 3 44
Arkoma Basin............................................ 10 5 - 15
Southern Illinois....................................... - - 1 1
GULF COAST................................................ 6 2 - 8
--
--- --- ---
TOTAL................................................. 252 193 6 451
--
--
--- --- ---
--- --- ---
</TABLE>
The Company currently anticipates that it will initiate 50 to 100
development projects in 1998. Assuming that 100 projects per year are initiated,
the Company currently has more than a five year inventory of development
projects. Continental expects to spend approximately $130 million over the next
three years for development projects.
EXPLORATION ACTIVITIES. The Company's existing inventory of exploration
projects varies in risk and reward based on their depth, location and geology.
The Company intends to use advanced technology, including 3-D seismic,
horizontal drilling and improved completion techniques, to enhance a significant
portion of the Company's existing and future exploration projects. The Company
currently estimates that it will spend $3.1 million on seismic activities over
the next three years. The Company is pursuing ten higher risk/reward exploration
prospects in the Gulf Coast and Rocky Mountains. In these ten prospects, the
Company has an inventory of 43 exploratory drilling locations in various stages
of readiness.
The Gulf Coast prospects include the Jefferson Island project in Iberia
Parish, Louisiana, and the Pebble Beach project in Neuces County, Texas. The
Jefferson Island project is an underdeveloped salt dome that produces from a
series of prolific Miocene sands. To date the field has produced 22.0 MMBoe,
from approximately one quarter of the total dome. The remaining three quarters
of the dome are essentially unexplored or are underdeveloped. The Company
controls 6,283 gross (2,742 net) acres over the entire salt dome and has
identified 12 exploratory locations. The Company has an agreement with a third
party who, at its expense, acquired 35 square miles of 3-D seismic data covering
the entire salt dome, in exchange for which the third party will earn the right
to a 50% interest in the project. The 3-D data is currently being processed and
prepared for interpretation. Drilling is expected to commence in the fourth
quarter of 1998. In the Pebble Beach project, 20 square miles of 3-D seismic
data has been acquired over the project area and two wells have been drilled to
date, neither of which was commercial. Currently, there are ten additional
drilling locations in the Pebble Beach project based on 3-D seismic data.
In the Rocky Mountains, the Company has identified ten exploratory
prospects, representing 21 exploratory drilling locations. In the Lustre Field
and the NE Autumn prospect of the Williston Basin, the Company owns
approximately 90,000 net leasehold acres, and intends to combine 3-D seismic and
horizontal drilling to further develop and explore for oil on this acreage.
48
<PAGE>
The following table sets forth information pertaining to the Company's
existing exploration project inventory at June 30, 1998:
<TABLE>
<CAPTION>
NUMBER OF EXPLORATION PROJECTS
--------------------------------------
DRILLING LOCATION 3-D SEISMIC
--------------------- ---------------
<S> <C> <C>
ROCKY MOUNTAINS:
Williston Basin........................................................ 19 3
Big Horn Basin......................................................... 6 1
MID-CONTINENT............................................................ - -
GULF COAST............................................................... 22 1
-- --
TOTAL.................................................................... 47 5
-- --
-- --
</TABLE>
SPECIALIZED TECHNOLOGY
HORIZONTAL DRILLING OPERATIONS. The Company's development, exploitation and
exploration activities include extensive use of precision horizontal drilling.
Through the use of precision horizontal drilling the Company has experienced a
400% to 700% increase in initial flow rates and, when coupled with HPAI
secondary recovery operations, a 300% to 400% increase in recovered reserves.
The increased recovered reserves, combined with increased production rates
offered by horizontal drilling, permitted the Company to co-discover and develop
the Cedar Hills Field from a reservoir that was historically perceived to be
non-commercial. From inception, the Company had drilled 136 horizontal wells in
the Rocky Mountains and Mid-Continent. The Company's primary horizontal drilling
objectives are non-fractured reservoirs that decline at a slower rate than
fractured reservoirs. For example, the horizontal wells in the Cedar Hills Field
have an average productive life of approximately 25 years, based solely on
primary production.
HIGH PRESSURE AIR INJECTION. The Company has successfully utilized high
pressure air injection technology to enhance the recovery of oil from its
properties in the Medicine Pole Hills, Buffalo, West Buffalo and South Buffalo
units in the Williston Basin. The Company expects to initiate HPAI in the Cedar
Hills Field and expand its use in the western part of the Medicine Pole Hills
Unit. HPAI consists of injecting compressed air into the target reservoir
through an injection well. As the compressed air is forced deeper into the
subsurface, air pressure and temperature increase, and the combination of
pressure, fuel and high temperature develops a burn front, creating gasses which
push further into the oil bearing formation. This pressure forces the oil in the
formation to move away from the pressure and, eventually, into the Company's
horizontal and vertical collector wells. In the Williston Basin, the use of HPAI
technology in secondary recovery operations, when coupled with precision
horizontal drilling, has increased total oil recovery by 300% to 400% over
average primary production, or by 50% over secondary recovery utilizing
traditional waterflooding. The Company's experience with HPAI technology has
demonstrated that production response using HPAI technology generally occurs in
one to three years, rather than five to six years using traditional
waterflooding. The Company currently conducts four of the eight active HPAI
projects in North America, the oldest of which has been operating for over 20
years.
ACQUISITION ACTIVITIES
The Company seeks to acquire properties that have the potential to be
immediately accretive to cash flow, have long-lived, lower risk, relatively
stable production potential, and provide long-term growth in production and
reserves. The Company focuses on acquisitions that complement its existing
exploration program, provide opportunities to utilize the Company's
technological advantages, have the potential for enhanced recovery activities,
and/or provide new core areas for the Company's operations. See "--Principal Oil
and Gas Properties."
49
<PAGE>
PRINCIPAL OIL AND GAS PROPERTIES
Until 1993, the Company's oil and gas activities were focused in the
Mid-Continent. In 1993 the Company made the strategic move to increase oil
production and reserves by expanding its development and exploration activities
into the Rocky Mountains. The Company currently controls approximately 505,000
net acres in the Rocky Mountains and is ranked among the largest oil producers
in the Rocky Mountains. Continental's oil production is characterized by long
lived, stable production with high secondary and enhanced oil recovery potential
which perpetuates production and cash flow from its properties. On a pro forma
basis, approximately 80% of its estimated proved reserves at December 31, 1997
were oil. To achieve a more balanced reserve mix, the Company is focusing on
generating an increased inventory of natural gas drilling opportunities in the
Mid-Continent and Gulf Coast. Currently, 85% of the Company's drilling inventory
is focused on further expansion and development of its Rocky Mountain oil
fields, and the remaining 15% is focused on natural gas projects in the
Mid-Continent and Gulf Coast. The Company's Gulf Coast activities are conducted
onshore the Texas and Louisiana coasts. In the Gulf Coast, the Company holds
approximately 9,400 net leasehold acres and has identified 28 potential drilling
locations.
The following table provides information with respect to the Company's net
proved reserves for its principal oil and gas properties as of December 31,
1997, on a pro forma basis:
<TABLE>
<CAPTION>
OIL
OIL GAS EQUIVALENT PERCENT OF
AREA (MBBL) (MMCF) (MBOE) PV-10
- ------------------------------------------------------------- --------- --------- ----------- -----------
<S> <C> <C> <C> <C>
ROCKY MOUNTAINS:
Williston Basin............................................ 21,495 4,741 22,285 52.9%
Big Horn Basin............................................. 27,248 28,470 31,993 9.5
MID-CONTINENT:
Anadarko Basin............................................. 3,039 41,427 9,944 35.6
Arkoma Basin............................................... - 2,967 494 1.4
Southern Illinois.......................................... 177 - 177 0.4
GULF COAST................................................... 8 243 49 0.2
--------- --------- ----------- -----
TOTALS....................................................... 51,967 77,848 64,942 100.0%
--------- --------- ----------- -----
--------- --------- ----------- -----
</TABLE>
ROCKY MOUNTAINS
The Company's Rocky Mountain properties are located primarily in the
Williston Basin of North Dakota, South Dakota and Montana and in the Big Horn
Basin of Wyoming. Estimated proved reserves for its Rocky Mountains properties
at December 31, 1997, on a pro forma basis, totaled 54.3 MMBoe and represented
62.4% of the Company's PV-10. Approximately 56.3% of these estimated proved
reserves are proved developed. During the six months ended June 30, 1998, net
daily production from these properties averaged 9,699 Bbls of oil and 1,530 Mcf
of natural gas, or 9,954 Boe per day. The Company's leasehold interests include
146,832 net developed and 355,122 net undeveloped acres, which represent 25% and
61% of the Company's total leasehold, respectively. This leasehold is expected
to be developed utilizing 3-D seismic, precision horizontal drilling and HPAI,
where applicable. As of June 30, 1998, the Company's Rocky Mountain properties
included an inventory of 225 development and 25 exploratory drilling locations.
WILLISTON BASIN
CEDAR HILLS FIELD. The Cedar Hills Field was discovered in November 1994
and is still under development. During the six months ended June 30, 1998, the
Cedar Hills Field properties produced 6,923 net Bbls per day to the Company
interests and represented 45% of the PV-10 attributable to the Company's
estimated proved reserves as of December 31, 1997 on a pro forma basis. The
Cedar Hills Field
50
<PAGE>
produces oil from the Red River "B" Formation, a thin (eight feet),
non-fractured, blanket-type, dolomite reservoir found at depths of 8,000 to
9,500 feet. All wells drilled by the Company in the Red River "B" Formation were
drilled exclusively with precision horizontal drilling technology. The Cedar
Hills Field covers approximately 200 square miles and has a known oil column of
1,000 feet. Through June 30, 1998, the Company drilled or participated in 146
gross (97 net) horizontal wells, of which 139 were successfully completed, for a
95% net success rate.
The Company believes that the Red River "B" formation in the Cedar Hills
Field is well suited for enhanced secondary recovery using HPAI technology. On
four nearby HPAI projects operated by the Company, HPAI technology has increased
oil recoveries 200% to 300% over primary recovery with ultimate recoveries
reaching up to 40% of the original oil in place. The Company intends to initiate
installation of HPAI secondary recovery on certain of its Cedar Hills Field
properties upon completion of field unitization, which is expected to occur in
1999. The Company believes that HPAI could increase its total recovery from the
Cedar Hills Field by as much as 75 million net barrels. On May 15, 1998, the
Company and Burlington entered into a definitive agreement to exchange undivided
interests so that effective December 1, 1998 the Company will own working
interests ranging from 90% to 92% in approximately 65,000 gross (59,000 net)
leasehold acres in the northern half of the Cedar Hills Field. As a result of
the agreement, the Company will enhance its ability to unitize all interests in
the northern half of the Cedar Hills Field, which is necessary in order for the
Company to initiate the planned HPAI enhanced recovery operations in the Cedar
Hills Field. On August 19, 1998, the Company instituted a declaratory judgment
action against Burlington in the District Court of Garfield County, Oklahoma
(Case No. CJ-98-613-03) alleging that Burlington provided false and misleading
information regarding certain of Burlington's oil and gas properties to a third
party consultant charged with determining the relative values of oil and gas
properties owned by the Company and Burlington which served as the basis for the
exchange of interests. The Company also claims that the consultant relied on
such false and misleading information in determining the relative fair values of
the oil and gas interests. The Company seeks a declaratory judgment determining
that it is excused from further performance under its exchange agreement with
Burlington. Burlington has denied the Company's allegations and seeks specific
performance by the Company, plus monetary damages of an unspecified amount.
Burlington has removed the action to the United States District Court for the
Western District of Oklahoma (CIV. 98-1253-W). The Company has requested that
the case be remanded to the Oklahoma state court.
As of June 30, 1998, there were 12 horizontal drilling locations in
inventory, all of which are development well locations.
MEDICINE POLE HILLS, BUFFALO, WEST BUFFALO AND SOUTH BUFFALO UNITS. In
1995, the Company acquired the following interests in four production units in
the Williston Basin: Medicine Pole Hills (63%); Buffalo (86%); West Buffalo
(82%); and South Buffalo (85%). During the six months ended June 30, 1998, these
units produced 2,221 Bbls per day, net to the Company's interests, and
represented 4.6 MMBoe or 7% of the pro forma PV-10 attributable to the Company's
estimated proved reserves as of December 31, 1997. These units are HPAI enhanced
recovery projects that produce from the Red River "B" Formation and are operated
by the Company. These units were discovered and developed with conventional
vertical drilling. The oldest vertical well in these units has been producing
for 44 years, demonstrating the long lived production characteristic of the Red
River "B" Formation. There are 104 producing wells in these units and current
estimates of remaining reserve life range from four to 16 years. The Company
plans to further develop these units and enhance production by drilling
strategically placed horizontal wells. There are currently 51 development
drilling locations identified in these units.
LUSTRE AND MIDFORK FIELDS. In January 1992, the Company acquired the Lustre
and Midfork Fields which, during the six months ended June 30, 1998, produced
299 Bbls per day, net to the Company's interests and represented 0.6 MMBoe or 1%
of the pro forma PV-10 attributable to its estimated proved reserves as of
December 31, 1997. Wells in both the Lustre and Midfork Fields produce from the
Charles "C" dolomite, at depths of 5,500 to 6,000 feet. Historically, production
from the Charles "C" has a low
51
<PAGE>
daily production rate and is long lived. There are currently 37 wells producing
in the two fields, and no secondary recovery is underway in either field. The
Company currently owns 90,000 net acres in the Lustre and Midfork Fields and
plans to utilize 3-D seismic combined with horizontal drilling to further
exploit the Charles "C" reservoir, and to generate drilling opportunities for
deeper objectives underlying the Lustre and Midfork Fields as well as guide
exploration for new fields on its substantial undeveloped leasehold.
BIG HORN BASIN
WORLAND FIELD. On May 14, 1998, the Company consummated the purchase for
$86.5 million of producing and non-producing oil and gas properties and certain
other related assets in the Worland Field, effective as of June 1, 1998.
Subsequently, and effective as of June 1, 1998, the Company sold an undivided
50% interest in the Worland Field properties (excluding inventory and certain
equipment) to Harold Hamm, the Company's principal shareholder, for $42.6
million. The sale of the 50% interest in the Worland Field properties was
effected to reduce the size of the Company's exposure in one area, to reduce the
amount of future capital expenditures by the Company and to reduce the Company's
investment in oil, rather than natural gas, properties. See "Certain
Relationships and Related Transactions." The Worland Field properties cover
35,000 net leasehold acres in the Worland Field of the Big Horn Basin in
northern Wyoming, of which 22,753 net acres are held by production and 12,635
net acres are non-producing or prospective. Approximately two-thirds of the
Company's producing leases in the Worland Field are within five federal units,
the largest of which (the Cottonwood Creek Unit) has been producing for over 40
years. All of the units produce principally from the Phosphoria formation, which
is the most prolific oil producing formation in the Worland Field. Four of the
units are unitized as to all depths, with the Cottonwood Creek Field Extension
(Phosphoria) Unit being unitized only as to the Phosphoria formation. The
Company is the operator of all five of the federal units. The Company also
operates 40 of the 60 producing wells located on non-unitized acreage. The
Company's Worland Field properties include interests in 292 producing wells, 272
of which are operated by the Company.
As of December 31, 1997, the estimated net proved reserves attributable to
the Company's Worland Field properties were approximately 32.0 MMBoe, with an
estimated PV-10 of $25.4 million. Approximately 85% of these proved reserves
consist of oil, principally in the Phosphoria formation. Oil produced from the
Company's Worland Field properties is low gravity, sour (high sulphur content)
crude, resulting in a lower sales price per barrel than non-sour crude, and is
sold into a Marathon pipeline or is trucked from the lease. Gas produced from
the Worland Field properties is also sour, resulting in a sale price that is
less per Mcf than non-sour natural gas. From the effective date of the Worland
Field Acquisition through September 30, 1998, the average price of crude oil
produced by the Worland Field properties was $5.19 per Bbl less than the NYMEX
price of crude oil. The Company entered into a new contract effective October 1,
1998 through March 31, 1999 to sell crude oil produced from its Worland Field
properties at an average price of $3.19 per Bbl less than the NYMEX price.
In addition to the proved reserves, the Company has identified 158 locations
on its Worland Field properties, to further develop and exploit the undeveloped
portion of the Worland Field. Over 100 wells have been identified for acid
fracture stimulation, most of which have been classified as having proved
developed non-producing reserves. The Company believes that secondary and
tertiary recovery projects will have significant potential for the addition of
reserves. In addition, six drilling prospects have been identified on the
Company's Worland Field properties in which prospects the Company and its
principal shareholder, together, have a majority leasehold position, allowing
for further exploration for and exploitation of the Phosphoria, Tensleep,
Frontier and Muddy formations and other prospective formations for additional
reserves.
MID-CONTINENT
The Company's Mid-Continent properties are located primarily in the Anadarko
Basin of western Oklahoma, southwestern Kansas and the Texas Panhandle, and to a
lesser extent, in the Arkoma Basin of
52
<PAGE>
southeastern Oklahoma ("Arkoma Basin"), and in southern Illinois. At December
31, 1997, the Company's estimated proved reserves in the Mid-Continent totaled
10.6 MMBoe, representing 37.4% of the Company's PV-10 at such date, on a pro
forma basis, and 97% of these reserves were proved developed. At such date,
approximately 70% of the Company's estimated proved reserves in the
Mid-Continent were natural gas. Net daily production from these properties
during the first half of 1998 averaged 1,126 Bbls of oil and 14,310 Mcf of
natural gas, or 3,511 Boe to the Company's interests. The Company's
Mid-Continent leasehold position includes 64,536 net developed and 9,282 net
undeveloped acres, representing 11% and 2% of the Company's total pro forma
leasehold, respectively, at June 30, 1998.
As of June 30, 1998, the Company's Mid-Continent properties included an
inventory of 21 development drilling locations, 11 of which were in the Anadarko
Basin.
ANADARKO BASIN. The Anadarko Basin properties contained 95% of the
Company's estimated proved reserves for the Mid-Continent and 35.6% of the
Company's total PV-10 at December 31, 1997, on a pro forma basis, and at such
date, represented 53% of the Company's estimated proved reserves of natural gas.
During the six months ended June 30, 1998, net daily production from its
Anadarko Basin properties averaged 1,126 Bbls of oil and 13,253 Mcf of natural
gas, or 3,335 Boe to the Company's interest from 661 gross (407 net) producing
wells, 506 of which are operated by the Company. The Anadarko Basin wells
produce from a variety of sands and carbonates in both stratigraphic and
structural traps in the Arbuckle, Oil Creek, Viola, Mississippian, Springer,
Morrow, Red Ford, Oswego, Skinner and Tonkawa formations, at depths ranging from
6,000 to 12,000 feet. These properties are currently being re-evaluated for
further development drilling and workover potential.
OTHER MID-CONTINENT PROPERTIES. The Company's remaining Mid-Continent
properties include those located in the Arkoma Basin and in southern Illinois.
In the Arkoma Basin, the Company is focused on coal bed methane, where it owns
approximately 14,000 acres and has 43 producing wells from the Hartshorne coal
at depths of 2,500 to 3,500 feet. The Company plans to drill two pilot
horizontal tests in the coal in 1998. In Illinois, the Company participates with
another operator in two waterflood projects and up to three wells per year for
production from shallow Mississippian age sands and carbonates.
53
<PAGE>
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to oil and gas
production, prices and costs attributable to all oil and gas property interests
owned by the Company for the periods shown:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
----------------------------------------------------------------- --------------------
WORLAND PRO
FIELD PROPERTIES FORMA
1995 1996 1997 1997 1997(1) 1997 1998
--------- --------- --------- ------------------- ----------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil and condensate (MBbls)...... 1,199 2,888 3,518 628 4,146 1,615 1,983
Natural gas (MMcf).............. 5,880 6,527 5,789 610 6,399 2,881 2,933
Total (MBoe).................... 2,179 3,976 4,483 730 5,213 2,095 2,472
UNIT ECONOMICS
Average sales price per Bbl..... $ 17.11 $ 20.78 $ 18.61 $ 15.58 $ 18.14 $ 20.08 $ 13.14
Average sales price per Mcf..... 1.40 2.13 2.21 .22 2.03 2.33 1.79
Average equivalent price (per
Boe)(2)....................... 14.03 18.87 17.53 13.69 17.02 18.69 12.46
Lifting cost (per Boe)(3)....... 3.49 4.86 4.63 7.04 4.98 5.07 3.67
DD&A expense (per Boe)(3)....... 3.76 5.44 6.74 1.51 6.01 7.31 5.95
General and administrative
expense (per Boe)(4).......... 2.74 1.64 1.47 -- 1.26 1.04 1.58
--------- --------- --------- ------ ----------- --------- ---------
Gross margin.................... $ 4.04 $ 6.93 $ 4.69 $ 5.14 $ 4.77 $ 5.26 $ 1.46
--------- --------- --------- ------ ----------- --------- ---------
--------- --------- --------- ------ ----------- --------- ---------
<CAPTION>
WORLAND PRO
FIELD PROPERTIES FORMA
1998 1998(1)
--------------------- -----------
<S> <C> <C>
NET PRODUCTION DATA:
Oil and condensate (MBbls)...... 261 2,244
Natural gas (MMcf).............. 380 3,314
Total (MBoe).................... 324 2,796
UNIT ECONOMICS
Average sales price per Bbl..... $ 7.22 $ 12.45
Average sales price per Mcf..... .64 1.66
Average equivalent price (per
Boe)(2)....................... 6.56 11.95
Lifting cost (per Boe)(3)....... 3.05 3.60
DD&A expense (per Boe)(3)....... 3.16 5.62
General and administrative
expense (per Boe)(4).......... -- 1.40
----- -----------
Gross margin.................... $ .35 $ 1.83
----- -----------
----- -----------
</TABLE>
- --------------------------
(1) Pro forma to reflect the Worland Field Acquisition as if it had occurred
January 1, 1997.
(2) Calculated by dividing oil and gas revenues, as reflected on the Financial
Statements, by production volumes on a Boe basis. Oil and gas revenues
reflected in the Financial Statements are recognized as production is sold
and may differ from oil and gas revenues reflected on the Company's
production records which reflect oil and gas revenues by date of production.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations."
(3) Related to drilling and development activities.
(4) Related to drilling and development activities, net of operating overhead
income.
54
<PAGE>
PRODUCING WELLS
The following table sets forth the number of productive wells in which the
Company owned an interest as of June 30, 1998:
<TABLE>
<CAPTION>
OIL NATURAL GAS
-------------------- ----------------------
GROSS NET GROSS NET
--------- --- ----------- ---
<S> <C> <C> <C> <C>
ROCKY MOUNTAINS:
Williston Basin................................................................. 328 255 - -
Big Horn Basin(1)............................................................... 292 127 - -
MID-CONTINENT:
Anadarko Basin.................................................................. 424 298 237 109
Other........................................................................... 70 32 38 32
GULF COAST........................................................................ 6 3 4 2
--------- --- --- ---
Total......................................................................... 1,120 715 279 143
--------- --- --- ---
--------- --- --- ---
</TABLE>
- ------------------------
(1) Represents Worland Field properties acquired by the Company in the Worland
Field Acquisition.
ACREAGE
The following table sets forth the Company's developed and undeveloped gross
and net leasehold acreage as of June 30, 1998:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
-------------------- --------------------
GROSS NET GROSS NET
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
ROCKY MOUNTAINS:
Williston Basin.................................................... 164,137 124,079 454,342 340,487
Big Horn Basin(1).................................................. 47,492 22,753 25,269 12,635
MID-CONTINENT:
Anadarko Basin..................................................... 80,977 49,991 11,703 5,382
Other.............................................................. 21,539 14,545 5,026 3,900
GULF COAST........................................................... 1,355 1,235 12,217 8,202
--------- --------- --------- ---------
Total............................................................ 315,500 212,603 508,557 370,606
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
- ------------------------
(1) Represents Worland Field properties acquired by the Company in the Worland
Field Acquisition.
DRILLING ACTIVITIES
The following table sets forth the Company's drilling activity on its
properties for the periods indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1995 1996 1997
---------------------- ---------------------- ----------------------
GROSS NET GROSS NET GROSS NET
----------- --------- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C>
DEVELOPMENT WELLS:
Productive.................................... 19 14.50 49 28.43 63 42.41
Non-productive................................ 1 1.00 2 1.48 - -
-- -- --
--------- --------- ---------
Total....................................... 20 15.5 51 29.91 63 42.41
-- -- --
-- -- --
--------- --------- ---------
--------- --------- ---------
EXPLORATORY WELLS:
Productive.................................... 20 18.15 8 5.13 15 11.29
Non-productive................................ 4 3.00 5 3.17 5 1.98
-- -- --
--------- --------- ---------
Total....................................... 24 21.15 13 8.30 20 13.27
-- -- --
-- -- --
--------- --------- ---------
--------- --------- ---------
<CAPTION>
SIX MONTHS ENDED
JUNE 30, 1998
----------------------
GROSS NET
----------- ---------
<S> <C> <C>
DEVELOPMENT WELLS:
Productive.................................... 23 16.04
Non-productive................................ - -
--
---------
Total....................................... 23 16.04
--
--
---------
---------
EXPLORATORY WELLS:
Productive.................................... 2 .75
Non-productive................................ - -
--
---------
Total....................................... 2 .75
--
--
---------
---------
</TABLE>
55
<PAGE>
OIL AND GAS RESERVES
The following table summarizes the estimates of the Company's net proved
reserves and the related PV-10 of such reserves at the dates shown. Ryder Scott
Company Petroleum Engineers ("Ryder Scott") prepared the reserve and present
value data with respect to the Company's oil and gas properties which
represented 72% of the PV-10 at December 31, 1997 and Worland Field properties
which represented 77% of the PV-10 of the Worland Field properties at the same
date. The Company prepared the reserve and present value data on all other
Company and Worland Field properties.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------------------
PRO FORMA
1995 1996 1997 1997(1)
------------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
RESERVE DATA:
Proved developed reserves:
Oil (MBbls)............................................... 12,627 15,265 19,411 30,819
Natural gas (MMcf)........................................ 52,588 49,082 47,676 60,394
Total (MBoe)............................................ 21,392 23,445 27,357 40,885
Proved undeveloped reserves:
Oil (MBbls)............................................... 4,874 4,227 5,308 21,148
Natural gas (MMcf)........................................ 2,232 1,453 1,702 17,454
Total (MBoe)............................................ 5,246 4,469 5,592 24,057
Total proved reserves:
Oil (MBbls)............................................... 17,501 19,492 24,719 51,967
Natural gas (MMcf)........................................ 54,820 50,535 49,378 77,848
Total (MBoe)............................................ 26,638 27,915 32,949 64,942
PV-10(2)(3)(4).............................................. $ 206,650 $ 258,278 $ 241,625 $ 267,016
</TABLE>
- --------------------------
(1) Pro forma to reflect the Worland Field Acquisition as if it had occurred on
December 31, 1997.
(2) PV-10 represents the present value of estimated future net cash flows before
income tax discounted at 10% using prices in effect at the end of the
respective periods presented and including the effects of hedging
activities. In accordance with applicable requirements of the Commission,
estimates of the Company's proved reserves and future net cash flows are
made using oil and gas sales prices estimated to be in effect as of the date
of such reserve estimates and are held constant throughout the life of the
properties (except to the extent a contract specifically provides for
escalation). The prices used in calculating PV-10 as of December 31, 1997
were $18.06 per Bbl of oil and $2.25 per Mcf of natural gas. The average
prices used in calculating the pro forma PV-10 as of December 31, 1997 were
$14.59 per Bbl of oil and $2.07 per Mcf of natural gas. Average prices as of
September 30, 1998 were $12.95 per Bbl of oil and $1.66 per Mcf of natural
gas. These prices, if applied to estimated proved reserves of the Company as
of December 31, 1997, would result in a PV-10, on a pro forma basis, of
$208.7 million at such date, as estimated by the Company.
(3) In 1996, the Company changed its fiscal year-end from May 31 to December 31.
Because reports on a December 31 year-end basis prior to 1996 were not
available, information as of December 31, 1995 was determined from the
Company's production, drilling, acquisition and sale data as applied to its
December 31, 1996 reserve report.
(4) At December 31, 1997, the standardized measure of discounted future net cash
flows attributable to the Company's proved oil and gas reserves and those
acquired in the Worland Field Acquisition, and on a pro forma basis to give
effect to the Worland Field Acquisition, are as follows:
<TABLE>
<CAPTION>
STANDARDIZED MEASURE OF
FUTURE CASH FLOWS
------------------------
(IN THOUSANDS OF
DOLLARS)
<S> <C>
Continental Resources, Inc. And Subsidiary............................ $ 241,625
Worland Field Acquisition............................................. 25,391
--------
Pro Forma Combined Standardized Measure of Future Cash Flows.......... $ 267,016
</TABLE>
See Note 8 to the Company's Consolidated Financial Statement and Note 2 to
the Statements of Revenues and Direct Operating Expenses of Oil and Gas
Properties Included in the Purchase Agreement between Continental Resources,
Inc. and Bass Enterprises Production Co.
56
<PAGE>
Estimated quantities of proved reserves and future net cash flows therefrom
are affected by oil and gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating oil and gas
reserves and their values, including many factors beyond the control of the
producer. The reserve data set forth in this Prospectus represent only
estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates of different engineers, including those used by the Company,
may vary. In addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration activities,
prevailing oil and gas prices, operating costs and other factors, which
revisions may be material. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they are based.
In general, the volume of production from oil and gas properties declines as
reserves are depleted. Except to the extent the Company acquires properties
containing proved reserves or conducts successful exploitation and development
activities, the proved reserves of the Company will decline as reserves are
produced. The Company's future oil and gas production is, therefore, highly
dependent upon its level of success in finding or acquiring additional reserves.
See "Risk Factors--Replacement of Reserves" and "--Uncertainty of Estimates of
Oil and Gas Reserves and Future Net Cash Flows."
GAS GATHERING SYSTEMS
The Company's gas gathering systems are owned by CGI. Natural gas and
casinghead gas are purchased at the wellhead primarily under either
market-sensitive percent-of-proceeds-index contracts or keep-whole gas purchase
contracts. Under percent-of-proceeds-index contracts, CGI receives a fixed
percentage of the monthly index posted price for natural gas and a fixed
percentage of the resale price for natural gas liquids. CGI generally receives
between 20% and 30% of the posted index price for natural gas sales and from 20%
to 30% of the proceeds received from natural gas liquids sales. Under keep-whole
gas purchase contracts, CGI retains all natural gas liquids recovered by its
processing facilities and keeps the producers whole by returning to the
producers at the tailgate of its plants an amount of residue gas equal on a BTU
basis to the natural gas received at the plant inlet. The keep-whole component
of the contract permits the Company to benefit when the value of natural gas
liquids is greater as a liquid than as a portion of the residue gas stream.
OIL AND GAS MARKETING
The Company's oil and gas production is sold primarily under market
sensitive or spot price contracts. The Company sells substantially all of its
casinghead gas to purchasers under varying percentage-of-proceeds contracts. By
the terms of these contracts, the Company receives a fixed percentage of the
resale price received by the purchaser for sales of natural gas and natural gas
liquids recovered after gathering and processing the Company's gas. The Company
normally receives between 80% and 100% of the proceeds from natural gas sales
and from 80% to 100% of the proceeds from natural gas liquids sales received by
the Company's purchasers when the products are resold. The natural gas and
natural gas liquids sold by these purchasers are sold primarily based on spot
market prices. The revenues received by the Company from the sale of natural gas
liquids is included in natural gas sales. As a result of the natural gas liquids
contained in the Company's production, the Company has historically improved its
price realization on its natural gas sales as compared to Henry Hub or other
natural gas price indexes. For the year ended December 31, 1997, purchases of
the Company's natural gas production by GPM Gas Corporation, Warren NGL, Inc.,
and Oklahoma Natural Gas Company accounted for 14.7%, 12.7% and 12.6% of the
Company's total gas sales for such period, respectively. For the year ended
December 31, 1997, purchases of the Company's oil production by Koch Oil Company
and Sun Oil Company accounted
57
<PAGE>
for 74.2% and 10.0% of the Company's total oil sales for such period. Due to the
availability of other markets, the Company does not believe that the loss of
Koch Oil Company or any other crude oil or gas customer would have a material
adverse effect on the Company's results of operations.
Periodically the Company utilizes various hedging strategies to hedge the
price of a portion of its future oil and gas production. The Company does not
establish hedges in excess of its expected production. These strategies
customarily emphasize forward-sale, fixed-price contracts for physical delivery
of a specified quantity of production or swap arrangements that establish an
index-related price above which the Company pays the hedging partner and below
which the Company is paid by the hedging partner. These contracts allow the
Company to predict with greater certainty the effective oil and gas prices to be
received for its hedged production and benefit the Company when market prices
are less than the fixed prices provided in its forward-sale contracts. However,
the Company does not benefit from market prices that are higher than the fixed
prices in such contracts for its hedged production. As of June 30, 1998, no
forward-sale contracts were in place with respect to the Company's future
production of oil or natural gas. The Company plans to reduce its hedging
transactions. In August 1998, the Company began engaging in oil trading
arrangements as part of its oil marketing activities. Under these arrangements,
the Company contracts to purchase oil from one source and to sell oil to an
unrelated purchaser, usually at disparate prices. The Company realized gains on
these arrangements, determined before $.1 million of transportation costs and
related expenses, of $1.6 million for July, $1.2 million in August and $.8
million for September 1998. The Company's policy is to limit its exposure from
open positions to $1 million at any one time. In addition to its oil trading
arrangements, the Company entered into a contract effective October 1, 1998
through March 31, 1999 to sell crude oil produced from the Company's Worland
Field properties at an average price of $3.19 per Bbl less than the NYMEX price.
EMPLOYEES
As of August 31, 1998, the Company employed 196 people, 77 of which were
administrative personnel, 14 of which were geological personnel, 11 of which
were engineers and the remainder were field personnel. The Company's future
success will depend partially on its ability to attract, retain and motivate
qualified personnel. The Company is not a party to any collective bargaining
agreements and has not experienced any strikes or work stoppages. The Company
considers its relations with its employees to be satisfactory.
COMPETITION
The oil and gas industry is highly competitive. The Company competes for the
acquisition of oil and gas properties, primarily on the basis of the price to be
paid for such properties, with numerous entities including major oil companies,
other independent oil and gas concerns and individual producers and operators.
Many of these competitors are large, well established companies and have
financial and other resources substantially greater than those of the Company.
The Company's ability to acquire additional oil and gas properties and to
discover reserves in the future will depend upon its ability to evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment.
LEGAL PROCEEDINGS
From time to time, the Company is party to litigation or other legal
proceedings that it considers to be a part of the ordinary course of its
business. The Company is not involved in any legal proceedings nor is it party
to any pending or threatened claims that could reasonably be expected to have a
material adverse effect on its financial condition or results of operations.
However, the Company is engaged in litigation with Burlington with respect to
the agreement to exchange interests in the Cedar Hills Field. See "--Rocky
Mountains."
58
<PAGE>
REGULATION
GENERAL. Various aspects of the Company's oil and gas operations are
subject to extensive and continually changing regulation, as legislation
affecting the oil and gas industry is under constant review for amendment or
expansion. Numerous departments and agencies, both federal and state, are
authorized by statute to issue, and have issued, rules and regulations binding
upon the oil and gas industry and its individual members.
REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. The Federal Energy
Regulatory Commission (the "FERC") regulates the transportation and sale for
resale of natural gas in interstate commerce pursuant to the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. In the past, the federal government
has regulated the prices at which oil and gas could be sold. While sales by
producers of natural gas and all sales of crude oil, condensate and natural gas
liquids can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. The Company's sales of natural gas are
affected by the availability, terms and cost of transportation. The price and
terms for access to pipeline transportation are subject to extensive regulation
and proposed regulation designed to increase competition within the natural gas
industry, to remove various barriers and practices that historically limited
non-pipeline natural gas sellers, including producers, from effectively
competing with interstate pipelines for sales to local distribution companies
and large industrial and commercial customers and to establish the rates
interstate pipelines may charge for their services. Similarly, the Oklahoma
Corporation Commission and the Texas Railroad Commission have been reviewing
changes to their regulations governing transportation and gathering services
provided by intrastate pipelines and gatherers. While the changes being
considered by these federal and state regulators would affect the Company only
indirectly, they are intended to further enhance competition in natural gas
markets. The Company cannot predict what further action the FERC or state
regulators will take on these matters, however, the Company does not believe
that any actions taken will have an effect materially different than the effect
on other natural gas producers with which it competes.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
market prices. The price the Company receives from the sale of these products
may be affected by the cost of transporting the products to market.
ENVIRONMENTAL. Extensive federal, state and local laws regulating the
discharge of materials into the environment or otherwise relating to the
protection of the environment affect the Company's oil and gas operations.
Numerous governmental departments issue rules and regulations to implement and
enforce such laws, which are often difficult and costly to comply with and which
carry substantial civil and even criminal penalties for failure to comply. Some
laws, rules and regulations relating to protection of the environment may, in
certain circumstances, impose strict liability for environmental contamination,
rendering a person or entity liable for environmental damages and cleanup costs
without regard to negligence or fault on the part of such person or entity.
Other laws, rules and regulations may restrict the rate of oil and gas
production below the rate that would otherwise exist or even prohibit
exploration and production activities in sensitive areas. In addition, state
laws often require various forms of remedial action to prevent pollution, such
as closure of inactive pits and plugging of abandoned wells. The regulatory
burden on the oil and gas industry increases the Company's cost of doing
business and consequently affects the Company's profitability. The Company
believes that it is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on the Company's
operations. However, environmental laws and regulations have been subject to
frequent changes over the years, and the imposition of more
59
<PAGE>
stringent requirements could have a material adverse effect upon the capital
expenditures or competitive position of the Company.
The Company currently owns or leases, and has in the past owned or leased,
numerous properties that have been used for the exploration and production of
oil and gas and for other uses associated with the oil and gas industry.
Although the Company followed operating and disposal practices that it
considered appropriate under applicable laws and regulations, hydrocarbons or
other wastes may have been disposed of or released on or under the properties
owned or leased by the Company or on or under other locations where such wastes
were taken for disposal. In addition, the Company owns or leases properties that
have been operated by third parties in the past. The Company could incur
liability under the Comprehensive Environmental Response, Compensation and
Liability Act or comparable state statutes for contamination caused by wastes it
generated or for contamination existing on properties it owns or leases, even if
the contamination was caused by the waste disposal practices of the prior owners
or operators of the properties. In addition, it is not uncommon for landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the release of produced fluids or other pollutants into the
environment.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of hazardous wastes and can
require cleanup of hazardous waste disposal sites. RCRA currently excludes
drilling fluids, produced waters and certain other wastes associated with the
exploration, development or production of oil and gas from regulation as
"hazardous waste." A similar exemption is contained in many of the state
counterparts to RCRA. Disposal of such oil and gas exploration, development and
production wastes usually is regulated by state law. Other wastes handled at
exploration and production sites or used in the course of providing well
services may not fall within this exclusion. Moreover, stricter standards for
waste handling and disposal may be imposed on the oil and gas industry in the
future. From time to time legislation has been proposed in Congress that would
revoke or alter the current exclusion of exploration, development and production
wastes from the RCRA definition of "hazardous wastes" thereby potentially
subjecting such wastes to more stringent handling and disposal requirements. If
such legislation were enacted, or if changes to applicable state regulations
required the wastes to be managed as hazardous wastes, it could have a
significant impact on the operating costs of the Company, as well as the oil and
gas industry in general.
The Company's operations are also subject to the Clean Air Act (the "CAA")
and comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain pollution control requirements with respect to air emissions from
operations of the Company. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with obtaining and maintaining operating permits and approvals for
air emissions. However, the Company believes its operations will not be
materially adversely affected by any such requirements, and the requirements are
not expected to be any more burdensome to the Company than to other similarly
situated companies involved in oil and gas exploration and production activities
or well servicing activities.
The Federal Water Pollution Control Act of 1972 (the "FWPCA") imposes
restrictions and strict controls regarding the discharge of wastes, including
produced waters and other oil and gas wastes, into navigable waters. These
controls have become more stringent over the years, and it is probable that
additional restrictions will be imposed in the future. Permits must be obtained
to discharge pollutants into state and federal waters. The FWPCA provides for
civil, criminal and administrative penalties for unauthorized discharges of oil
and other hazardous substances and imposes substantial potential liability for
the costs of removal or remediation. State laws governing discharges to water
also provide varying civil, criminal and administrative penalties and impose
liabilities in the case of a discharge of petroleum or its derivatives, or other
hazardous substances, into state waters. In addition, the Environmental
Protection Agency has promulgated regulations that require many oil and gas
production sites, as well as other
60
<PAGE>
facilities, to obtain permits to discharge storm water runoff. The Company
believes that compliance with existing requirements under the FWPCA and
comparable state statutes will not have a material adverse effect on the
Company's financial condition or results of operations.
REGULATION OF OIL AND GAS EXPLORATION AND PRODUCTION. Exploration and
production operations of the Company are subject to various types of regulation
at the federal, state and local levels. Such regulations include requiring
permits and drilling bonds for the drilling of wells, regulating the location of
wells, the method of drilling and casing wells, and the surface use and
restoration of properties upon which wells are drilled. Many states also have
statutes or regulations addressing conservation matters, including provisions
for the utilization or pooling of oil and gas properties, the establishment of
maximum rates of production from oil and gas wells and the regulation of
spacing, plugging and abandonment of such wells. Some state statutes limit the
rate at which oil and gas can be produced from the Company's properties. See
"Risk Factors--Laws and Regulations; Environmental Risk."
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its properties in
accordance with standards generally accepted in the oil and gas industry. As is
customary in the oil and gas industry, the Company makes only a cursory review
of title to farmout acreage and to undeveloped oil and gas leases upon execution
of any contracts. Prior to the commencement of drilling operations, a title
examination is conducted and curative work is performed with respect to
significant defects. To the extent title opinions or other investigations
reflect title defects, the Company, rather than the seller of the undeveloped
property, is typically responsible to cure any such title defects at its
expense. If the Company were unable to remedy or cure any title defect of a
nature such that it would not be prudent to commence drilling operations on the
property, the Company could suffer a loss of its entire investment in the
property. The Company has obtained title opinions on substantially all of its
producing properties. Prior to completing an acquisition of producing oil and
gas leases, the Company performs a title review on a material portion of the
leases. The Company's oil and gas properties are subject to customary royalty
interests, liens for current taxes and other burdens that the Company believes
do not materially interfere with the use of or affect the value of such
properties.
61
<PAGE>
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth names, ages and titles of the directors and
executive officers of the Company.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ------------------------------- --- --------------------------------------------------------------------------
<S> <C> <C>
Harold Hamm(1)(2).............. 52 Chairman of the Board of Directors, President, Chief Executive Officer and
Director
Jack Stark(1)(3)............... 43 Senior Vice President--Exploration and Director
Jeff Hume(1)(4)................ 48 Senior Vice President--Drilling Operations and Director
Randy Moeder(1)(2)............. 39 Senior Vice President, General Counsel, Secretary and Director
Roger Clement(1)(3)............ 53 Senior Vice President, Chief Financial Officer, Treasurer and Director
Tom Luttrell................... 40 Senior Vice President--Land
Jeff White..................... 32 Senior Vice President--Business Development
</TABLE>
- --------------------------
(1) Member of the Executive, Compensation and Audit Committees.
(2) Term expires in 2001.
(3) Term expires in 2000.
(4) Term expires in 1999.
HAROLD HAMM, LL.M. has been President and Chief Executive Officer and a
Director of the Company since its inception in 1967. Mr. Hamm has served as
President of the Oklahoma Independent Petroleum Association Wildcatter's Club
since 1989. Mr. Hamm was the founder and is Chairman of the Oklahoma Natural Gas
Industry Task Force. Mr. Hamm has served as a member of the Interstate of Oil
and Gas Compact Commission and is a founding board member of the Oklahoma Energy
Resources Board. Mr. Hamm was named the 1992 Oklahoma Independent Petroleum
Association Member of the Year. Mr. Hamm serves on the Tax Steering Committee of
the Independent Petroleum Association of America and is a director of the Rocky
Mountain Oil and Gas Association.
JACK STARK joined the Company as Vice President of Exploration in June 1992
and was promoted to Senior Vice President in May 1998. Mr. Stark has been a
Director of the Company since September 1996. He holds a Masters degree in
Geology from Colorado State University and has 20 years of exploration
experience in the Mid-Continent, Gulf Coast and Rocky Mountain regions. Prior to
joining the Company, Mr. Stark was the exploration manager for the Western
Mid-Continent Region for Pacific Enterprises from August 1988 to June 1992. From
1978 to 1988, he held various staff and middle management positions with Cities
Service Co. and TXO Production Corp. Mr. Stark is a member of the American
Association of Petroleum Geologists, Oklahoma Independent Petroleum Association,
Rocky Mountain Association of Geologists, Houston Geological Society and
Oklahoma Geological Society.
JEFF HUME has been Vice President of Drilling Operations and a Director of
the Company since September 1996 and was promoted to Senior Vice President in
May, 1998. From May 1983 to September 1996, Mr. Hume was Vice President of
Engineering and Operations. Prior to joining the Company, Mr. Hume held various
engineering positions with Sun Oil Company, Monsanto Company and FCD Oil
Corporation. Mr. Hume is a Registered Professional Engineer and member of the
Society of Petroleum Engineers, Oklahoma Independent Petroleum Association, and
the Oklahoma and National Professional Engineering Societies.
RANDY MOEDER has been Vice President, General Counsel and a Director of the
Company since November 1990 and has served as Secretary of the Company since
February 1994 and as President of
62
<PAGE>
Continental Gas, Inc. since January 1995 and was Vice President of Continental
Gas, Inc. from November 1990 to January 1995. Mr. Moeder was promoted to Senior
Vice President of the Company in May, 1998. From January 1988 to summer 1990,
Mr. Moeder was in private law practice. From 1982 to 1988, Mr. Moeder held
various positions with Amoco Corporation. Mr. Moeder is a member of the Oklahoma
Independent Petroleum Association, the Oklahoma and American Bar Associations.
Mr. Moeder is also a Certified Public Accountant.
ROGER CLEMENT became Vice President, Chief Financial Officer and Treasurer
and a Director of the Company in March 1989 and was promoted to Senior Vice
President in May, 1998. Prior to joining the Company, Mr. Clement was a partner
in the accounting firm of Hunter and Clement in Oklahoma City, Oklahoma. Mr.
Clement is a Certified Public Accountant.
TOM LUTTRELL has been Vice President--Land of the Company since February
1997 and was promoted to Senior Vice President in May, 1998. From 1991 to
February 1997, Mr. Luttrell was Senior Landman of the Company. Prior to joining
the Company, Mr. Luttrell served as a landman for Terra Resources, Inc., Pacific
Enterprises Oil & Gas Company and Alexander Energy Corporation, all independent
oil and gas exploration companies. Mr. Luttrell is a member of the American
Association of Petroleum Landmen.
JEFF WHITE has been Vice President--Business Development of the Company
since July 1996 and was promoted to Senior Vice President--Business Development
in May, 1998. From 1993 to July 1996, Mr. White served as Special Assistant to
the Chairman of the Federal Deposit Insurance Corporation and also served as a
Financial Analyst for the Federal Deposit Insurance Corporation. From July, 1990
to December, 1992, Mr. White served as a financial/budget analyst on issues
relating to Resolution Trust Corporation funding. Prior to 1990, Mr. White
served as an analyst to the Banking Committee of the House of Representatives.
COMPOSITION OF BOARD OF DIRECTORS
The Company's Board of Directors presently consists of five directors.
Directors and executive officers of the Company are elected to serve until they
resign or are removed, or are otherwise disqualified to serve, or until their
successors are elected and qualified. Directors of the Company are elected for
one-year terms at the annual meeting of stockholders. Officers of the Company
are appointed at the Board's first meeting after each annual meeting of
stockholders.
DIRECTOR COMPENSATION
Directors receive no additional compensation for services rendered as
directors but are reimbursed for any out-of-pocket expenses incurred in
attending meetings.
EXECUTIVE COMPENSATION
The following table sets forth the cash and non-cash compensation during
1997 earned by the Company's chief executive officer and its other four most
highly compensated executive officers as of December 31, 1997 (the "Named
Executive Officers").
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SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
SECURITIES
ANNUAL COMPENSATION UNDERLYING
--------------------------- OTHER ANNUAL OPTION AWARDS ALL OTHER
NAME AND PRINCIPAL POSITION SALARY($) BONUS($) COMPENSATION($)(1) (# OF SHARES) COMPENSATION($)(2)
- ----------------------------- ------------- ------------ ------------------- --------------- ------------------
<S> <C> <C> <C> <C> <C>
Harold Hamm.................. $ 187,506.00 $ -- $ -- -- $ 857.12
Chairman of the Board,
President, and Chief
Executive Officer
Jack Stark................... 116,550.32 10,249.50 -- -- 9,815.92
Senior Vice President--
Exploration
Jeff Hume.................... 113,350.64 10,249.50 -- -- 11,162.12
Senior Vice President--
Operations
Randy Moeder................. 90,743.18 10,436.86 -- -- 18,666.78
Senior Vice President,
General Counsel and
Secretary
Roger Clement................ 89,968.00 9,718.83 -- -- 3,118.72
Senior Vice President,
Chief Financial Officer
and Treasurer
</TABLE>
- ------------------------
(1) Represents the value of perquisites and other personal benefits in excess of
10% of annual salary and bonus for the year ended December 31, 1997, the
Company paid no other annual compensation to its Named Executive Officers.
(2) Represents contributions made by the Company to the accounts of the
executive officer under the Company's profit sharing plan and under the
Company's nonqualified compensation plan.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
Continental does not have a separate compensation committee of its board of
directors. The board of directors sets the compensation for its executive
officers and Harold Hamm, Chairman of the Board and President, is a director and
participates in these deliberations concerning executive officer compensation.
Each of the directors of Continental also serve on the board of directors of
subsidiaries of Continential. As such, each of the directors participates in the
deliberations concerning executive officers' compensation for Continential and
its subsidiaries.
EMPLOYMENT AGREEMENTS
The Company does not have any employment agreeements with its named
Executive Officers.
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Set forth below is a description of transactions entered into between the
Company and certain of its officers, directors, employees and stockholders since
January 1, 1995. Certain of these transactions will continue in the future and
may result in conflicts of interest between the Company and such individuals,
and there can be no assurance that conflicts of interest will always be resolved
in favor of the Company.
OIL AND GAS OPERATIONS. In its capacity as operator of certain oil and gas
properties, the Company obtains oilfield services from related companies,
including Hamm & Phillips Service Company, Stride Well Service Company, Oil Tool
Rentals, Inc. and Catworks, Inc. These services include leasehold acquisition,
well location, site construction and other well site services, saltwater
trucking, use of rigs for completion and workover of oil and gas wells and the
rental of oil field tools and equipment. Harold Hamm is the chief executive
officer and principal shareholder of each of these related companies. The
aggregate amounts paid by Continental to these related companies during 1995,
1996, 1997 and during the six months ended June 30, 1998 were $5.9 million, $5.9
million, $11.9 million, and $6.9 million, respectively. The total amount paid to
these affiliated companies, a portion of which is billed to other interest
owners, was approximately $11.9 million in 1997. The services discussed above
were provided at costs and upon terms that management believes are no less
favorable to the Company than could have been obtained from unrelated parties.
In addition, Harold Hamm and certain companies controlled by him own interests
in wells operated by the Company. At December 31, 1997 and June 30, 1998, the
Company owed such persons an aggregate of $200,000 and $100,000, respectively,
representing their shares of oil and gas production sold by the Company.
SHAREHOLDER LOANS AND ADVANCES. In 1997 and 1998, the Company obtained
loans and advances from Harold Hamm and certain of his affiliates. Such loans
and advances were unsecured and were repaid from time to time in varying
amounts, with interest at an annual rate of 8.25%. The maximum aggregate amount
of such loans and advances outstanding at any time during 1997 and during the
six months ended June 30, 1998 was $22.0 million and $23.0 million,
respectively. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Liquidity and Capital Resources."
OFFICE LEASE. The Company leases office space under operating leases
directly or indirectly from Harold Hamm and Continental Management Company,
L.L.C., a Company owned in part by Harold Hamm. In 1997, the Company paid rents
associated with these leases of approximately $294,000. The Company believes
that the terms of its lease are no less favorable to the Company than those
which would be obtained from unaffiliated parties.
PARTICIPATION IN WELLS. Certain officers and directors of the Company have
participated and may participate in the future in wells drilled by the Company.
In 1997, Harold Hamm participated in Company wells on terms similar to those
available to unrelated third parties and was billed an aggregate of $515,000,
for his share of drilling, completion, equipping and operating costs. At
December 31, 1997, the aggregate unpaid balance owed to the Company by such
officers and directors was $4,565, none of which was past due.
WORLAND FIELD. Effective June 1, 1998, the Company sold an undivided 50%
interest in the 70,000 net leasehold acres it acquired in the Worland Field
Acquisition to its principal shareholder, Harold Hamm. The Worland Field sale
did not include inventory and certain items of equipment which the Company had
acquired in the Worland Field Acquisition. The $42.6 million purchase price paid
by Harold Hamm equals the Company's cost basis in such leasehold acres. Harold
Hamm paid $19.3 million of the purchase price in cash and the balance of $23.3
million by the cancellation of indebtedness owed by Harold Hamm to the Company.
Harold Hamm is subject to the applicable unit agreements in place with respect
to his interests in the Worland Field. Harold Hamm intends to sell some or all
of the interests acquired from the Company, although no arrangements,
understandings or agreements for any such sale currently exist.
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PRINCIPAL SHAREHOLDERS
Harold Hamm, Chairman of the Board, President and Chief Executive Officer
and a Director of the Company beneficially owns 44,496 shares (90.7%) of the
Company's outstanding common stock. The remaining 4,545 shares (9.3%) of the
outstanding common stock is beneficially owned by the Harold Hamm Delta Trust,
an irrevocable trust over which Harold Hamm has no voting or investment power.
DESCRIPTION OF CREDIT FACILITY
The following summary of the Credit Facility does not purport to be complete
and is subject to, and qualified in its entirety by reference to, the Credit
Facility. Bank One, Oklahoma, N.A., as agent for the lenders under the Credit
Facility ("Agent"), has consented to the terms of the Indenture and the issuance
of the Notes.
At October 31, 1998, $3.0 million was outstanding under the Credit Facility.
The Credit Facility is payable in full on May 14, 2001. All amounts outstanding
under the Credit Facility are secured by a first lien on substantially all of
the Company's proved oil and gas reserves, wells, systems, plants, related
personal property and contract rights.
INTEREST AND FEES. Amounts advanced under the Credit Facility bear interest
determined with reference to a sliding scale that takes into account the ratio
of the aggregate amount outstanding to the Borrowing Base (as defined in the
Credit Facility). The applicable rate may, at the Company's option, be based
either on the LIBOR rate or the Agent's prime rate. The rates range from the
LIBOR rate plus a margin of 100 to 175 basis points, or the Agent's prime rate
with no margin. The Company pays a non-use fee of 0.1875% to 0.25% per annum on
the amount by which the Borrowing Base exceeds the aggregate amount outstanding,
and an agency fee equal to $50,000 per annum.
BORROWING BASE. The amount of credit available at any time under the Credit
Facility is the lesser of the commitment amount or the Borrowing Base. The
commitment amount, initially, was $175.0 million. Upon completion of the
Offering and application of the net proceeds therefrom, the commitment amount
and the Borrowing Base was reduced to $75.0 million. The Borrowing Base is
redetermined semi-annually by the banks and may be redetermined more frequently
at the request of the Company, the Agent or banks holding 66 2/3% of the
outstanding balance under the Credit Facility. To the extent the amount
outstanding under the Credit Facility exceeds the Borrowing Base, the Company
must either reduce the amount outstanding or furnish additional collateral. At
June 30, 1998, the Borrowing Base was $175.0 million, which was more than the
amount outstanding under the Credit Facility at that date. The next scheduled
Borrowing Base redetermination date will be December 1, 1998.
COVENANTS. The Credit Facility contains customary affirmative and
restrictive covenants which, among other things, require periodic financial and
reserve reporting, require that the Company not allow the ratio of its
indebtedness to tangible net worth to exceed 3.25 to 1 as of the end of any
fiscal quarter, require that the Company not allow its minimum debt service
coverage ratio to be less than 1.2 to 1 as of the end of any fiscal quarter for
the immediately preceding four quarters, maintain a current ratio of at least
1.0 to 1 at the end of any fiscal quarter, and limit the Company and its
Restricted Subsidiaries with respect to indebtedness, liabilities, liens,
dividends, loans, lines of business, transactions with affiliates, changes in
management, investments, amendments to organizational documents, purchases and
sales of assets and speculative trading activities, unless the requisite number
of banks otherwise consent.
EVENTS OF DEFAULT. The Credit Facility contains customary events of
default, including, among other things and subject to applicable grace periods,
payment defaults, material misrepresentations, covenant defaults, certain
bankruptcy events, and judgment defaults. It also is an event of default under
the Credit Facility if any indebtedness of the Company or the Restricted
Subsidiaries in excess of $250,000, including the Notes, is accelerated or if a
change in management occurs.
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DESCRIPTION OF NOTES
GENERAL
The Old Notes were issued pursuant to the Indenture among the Company, the
Subsidiary Guarantors and United States Trust Company of New York, as trustee
(the "Trustee"). The New Notes will be issued under the Indenture, which will be
subject to the Trust Indenture Act of 1939, as amended (the "Trust Indenture
Act"). As used herein the term "Notes" includes the Old Notes and the New Notes.
The terms of the Notes include those stated in the Indenture and those made part
of the Indenture by reference to the Trust Indenture Act. The Notes are subject
to all such terms, and Holders of the Notes are referred to the Indenture and
the Trust Indenture Act for a statement thereof. The following summary of
certain provisions of the Indenture does not purport to be complete and is
qualified in its entirety by reference to the Indenture, including the
definitions therein of certain terms used below. The definitions of certain
terms used in the following summary are set forth below under "--Certain
Definitions."
The Notes will be general unsecured obligations of the Company and will be
subordinated in right of payment to Senior Debt. The Notes will be guaranteed on
a senior subordinated basis by each Restricted Subsidiary of the Company and any
future Restricted Subsidiary of the Company. The obligations of the Subsidiary
Guarantors under the Subsidiary Guarantees will be general unsecured obligations
of each of the Subsidiary Guarantors and will be subordinated in right of
payment to all obligations of the Subsidiary Guarantors in respect of Guarantor
Senior Debt. See "--Subsidiary Guarantees" and "Risk Factors-- Subordination of
Notes and Guarantees."
For purposes of this section, the term "Company" means Continental
Resources, Inc. As of the date of the Indenture, all of the Company's
Subsidiaries will be Restricted Subsidiaries. Under certain circumstances,
however, the Company will be able to designate current and future Subsidiaries
as Unrestricted Subsidiaries. Unrestricted Subsidiaries will not be subject to
many of the restrictive covenants set forth in the Indenture. See "--Certain
Covenants."
TERMS OF THE NOTES
The Notes are limited in aggregate principal amount to $150 million and will
mature on August 1, 2008. Interest on the Notes will accrue at the rate of
10 1/4% per annum and will be payable semi-annually in arrears on February 1 and
August 1 of each year, commencing February 1, 1999, to Holders of the Notes of
record on the immediately preceding January 15 and July 15. Interest on the
Notes will accrue from the most recent date on which interest has been paid or,
if no interest has been paid, from the date of original issuance.
Interest will be computed on the basis of a 360-day year comprised of twelve
30-day months. Principal, premium, if any, and interest on the Notes will be
payable at the office or agency of the Company maintained for such purpose
within the City and State of New York or, at the option of the Company, payment
of interest may be made by check mailed to the Holders of the Notes at their
respective addresses set forth in the applicable register of Holders of the
Notes. Until otherwise designated by the Company, the Company's office or agency
in New York will be the office of the Trustee maintained for such purpose. The
Notes will be fully registered as to principal and interest in minimum
denominations of $1,000 and integral multiples of $1,000 in excess thereof.
OPTIONAL REDEMPTION
Except as otherwise described below, the Notes will not be redeemable at the
Company's option prior to August 1, 2003. Thereafter, the Notes will be subject
to redemption at the option of the Company, in whole or in part, upon not less
than 30 nor more than 60 days' notice, at the redemption prices (expressed as
percentages of principal amount) set forth below plus accrued and unpaid
interest thereon to the
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applicable redemption date, if redeemed during the twelve-month period beginning
on August 1 of the years indicated below:
<TABLE>
<CAPTION>
YEAR PERCENTAGE
- ---------------------------------------------------------------------------------- -----------
<S> <C>
2003.............................................................................. 105.125%
2004.............................................................................. 103.417%
2005.............................................................................. 101.708%
2006 and thereafter............................................................... 100.000%
</TABLE>
Prior to August 1, 2001, the Company may, at its option, on any one or more
occasions, redeem up to 35% of the original aggregate principal amount of the
Notes at a redemption price equal to 110.25% of the principal amount thereof,
plus accrued and unpaid interest, if any, thereon to the redemption date, with
all or a portion of the net proceeds of public sales of common stock of the
Company; PROVIDED that at least 65% of the original aggregate principal amount
of the Notes remains outstanding immediately after the occurrence of such
redemption; and PROVIDED, FURTHER, that such redemption shall occur within 60
days of the date of the closing of the related sale of common stock of the
Company.
At any time on or prior to August 1, 2003, the Notes may also be redeemed as
a whole at the option of the Company upon the occurrence of a Change of Control
(but in no event more than 90 days after the occurrence of such Change of
Control) at a redemption price equal to 100% of the principal amount thereof,
plus the Applicable Premium as of, and accrued but unpaid interest, if any, to,
the date of redemption (subject to the right of Holders of record on the
relevant record date to receive interest due on the relevant interest payment
date).
SELECTION AND NOTICE
In the case of any partial redemption, selection of the Notes for redemption
will be made by the Trustee in compliance with the requirements of the principal
national securities exchange, if any, on which the Notes are listed, or, if such
other Notes are not so listed, on a pro rata basis, by lot or by such method as
such Trustee shall deem fair and appropriate; PROVIDED that no Note of $1,000 or
less shall be redeemed in part. Notices of redemption shall be mailed by first
class mail at least 30 but not more than 60 days before the redemption date to
each Holder of the Notes to be redeemed at its registered address. If any Note
is to be redeemed in part only, the notice of redemption that relates to such
Note shall state the portion of the principal amount thereof to be redeemed. A
new Note in principal amount equal to the unredeemed portion thereof will be
issued in the name of the Holder thereof upon cancellation of the original Note.
On and after the redemption date, interest will cease to accrue on the Notes or
portions of them called for redemption unless the Company defaults in payment of
the redemption price.
RANKING AND SUBORDINATION
The payment of principal of, premium, if any, and interest on the Notes and
any other payment obligations of the Company in respect of the Notes (including
any obligation to repurchase the Notes) will be subordinated in right of
payment, as set forth in the Indenture, to the prior payment in full in cash of
all Senior Debt, whether outstanding on the date of the Indenture or thereafter
incurred.
Upon any payment or distribution of property or securities to creditors of
the Company in a liquidation or dissolution of the Company or in a bankruptcy,
reorganization, insolvency, receivership or similar proceeding relating to the
Company or its property, or in an assignment for the benefit of creditors or any
marshalling of the Company's assets and liabilities, the holders of Senior Debt
will be entitled to receive payment in full of all Obligations due in respect of
such Senior Debt (including interest after the commencement of any such
proceeding at the rate specified in the applicable Senior Debt, whether or not a
claim for such interest would be allowed in a proceeding) before the Holders of
the Notes will be entitled to receive any payment with respect to the Notes, and
until all Obligations with respect to Senior Debt are
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<PAGE>
paid in full, any distribution to which the Holders of the Notes would be
entitled shall be made to the holders of Senior Debt (except that Holders of the
Notes may receive payments made from the trust described under "--Legal
Defeasance and Covenant Defeasance").
The Company also may not make any payment (whether by redemption, purchase,
retirement, defeasance or otherwise) upon or in respect of the Notes (except
from the trust described under "--Legal Defeasance and Covenant Defeasance") if
(i) a default in the payment of the principal of, premium, if any, or interest
on Designated Senior Debt occurs ("payment default") or (ii) any other default
occurs and is continuing with respect to Designated Senior Debt that permits, or
with the giving of notice or passage of time or both (unless cured or waived)
will permit, holders of the Designated Senior Debt as to which such default
relates to accelerate its maturity ("nonpayment default") and (solely with
respect to this clause (ii)) the Trustee receives a notice of such default (a
"Payment Blockage Notice") from the Company or the holders (or their
representative) of any Designated Senior Debt. Cash payments on the Notes shall
be resumed (a) in the case of a payment default, upon the date on which such
default is cured or waived and (b) in case of a nonpayment default, the earlier
of the date on which such nonpayment default is cured or waived or 179 days
after the date on which the applicable Payment Blockage Notice is received,
unless the maturity of any Designated Senior Debt has been accelerated or a
default of the type described in clause (ix) under the caption "Events of
Default and Remedies" has occurred and is continuing. No new period of payment
blockage may be commenced unless and until 360 days have elapsed since the date
of commencement of the payment blockage period resulting from the immediately
prior Payment Blockage Notice. No nonpayment default in respect of Designated
Senior Debt that existed or was continuing on the date of delivery of any
Payment Blockage Notice to the Trustee shall be, or be made, the basis for a
subsequent Payment Blockage Notice unless such default shall have been cured or
waived for a period of no less than 90 days.
The Indenture further requires that the Company promptly notify holders of
Senior Debt if payment of the Notes is accelerated because of an Event of
Default.
As a result of the subordination provisions described above, in the event of
a liquidation or insolvency of the Company, Holders of the Notes may recover
less ratably than creditors of the Company who are holders of Senior Debt. As of
March 31, 1998, on a pro forma basis, after giving effect to the Worland Field
Acquisition and the related financings and the application of the net proceeds
from the Offering, (i) the principal amount of Senior Debt outstanding would
have been $3.9 million (exclusive of $75 million of unused commitments under the
Credit Facility), (ii) there would have been no Senior Subordinated Debt of the
Company outstanding (exclusive of the Notes) and (iii) the Subsidiary Guarantors
would have had no Indebtedness outstanding other than guarantees of the Credit
Facility and the Subsidiary Guarantees. The Indenture will limit, subject to
certain financial tests, the amount of additional Indebtedness, including Senior
Debt, that the Company and its Subsidiaries can incur. See "--Certain
Covenants-- Incurrence of Indebtedness and Issuance of Disqualified Stock."
SUBSIDIARY GUARANTEES
The Company's payment obligations under the Notes will be jointly, severally
and unconditionally guaranteed by the Company's two wholly owned subsidiaries,
Continental Gas, Inc. and Continental Crude Co., each of which is a Subsidiary
Guarantor, and by any future Restricted Subsidiary of the Company. The
Subsidiary Guarantees will be subordinated to Guarantor Senior Debt of the
Subsidiary Guarantors to the same extent and in the same manner as the Notes are
subordinated to the Senior Debt. As of March 31, 1998, on a pro forma basis
after giving effect to the Worland Field Acquisition and the relating financing
and the Offering, there would have been no Guarantor Senior Debt of Subsidiary
Guarantors outstanding other than the Subsidiary Guarantees and guarantees of
borrowings under the Credit Facility. Although the Indenture contains
limitations on the amount of additional Indebtedness that the Company's
Restricted Subsidiaries may incur, under certain circumstances the amount of
such Indebtedness could be
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<PAGE>
substantial and, in any case, such Indebtedness may be Guarantor Senior Debt.
See "--Certain Covenants--Incurrence of Indebtedness and Issuance of
Disqualified Stock" and "--Ranking and Subordination".
The obligations of each Subsidiary Guarantor will be limited to the maximum
amount as will, after giving effect to all other contingent and fixed
liabilities of such Subsidiary Guarantor (including, without limitation, any
guarantees in respect of Indebtedness under the Credit Facility) and after
giving effect to any collections from or payments made by or on behalf of any
other Subsidiary Guarantor in respect of the obligations of such other
Subsidiary Guarantor under its Subsidiary Guarantee or pursuant to its
contribution obligations under the Indenture, result in the obligations of such
Subsidiary Guarantor under its Subsidiary Guarantee not constituting a
fraudulent conveyance or fraudulent transfer under federal or state law.
Each Subsidiary Guarantor may consolidate with or merge into or sell its
assets to the Company or another Subsidiary Guarantor without limitation. Each
Subsidiary Guarantor may consolidate with or merge into or sell all or
substantially all its assets to a corporation, partnership or trust other than
the Company or another Subsidiary Guarantor (whether or not affiliated with the
Subsidiary Guarantor). Upon the sale or disposition of a Subsidiary Guarantor
(by merger, consolidation, the sale of its Capital Stock or the sale of all or
substantially all of its assets) to a Person (whether or not an Affiliate of the
Subsidiary Guarantor) which is not a Subsidiary of the Company, which sale or
disposition is otherwise in compliance with the Indenture (including the
covenant described under "--Repurchase at the Option of Holders--Asset Sales"),
such Subsidiary Guarantor will be deemed released from all its obligations under
the Indenture and its Subsidiary Guarantee and such Subsidiary Guarantee will
terminate; PROVIDED, HOWEVER, that any such termination will occur only to the
extent that all obligations in respect of Indebtedness of such Subsidiary
Guarantor under the Credit Facility and all of its guarantees of, and under all
of its pledges of assets or other security interests which secure, any other
Indebtedness of the Company will also terminate upon such release, sale or
transfer.
Any Subsidiary Guarantor that is designated an Unrestricted Subsidiary in
accordance with the terms of the Indenture shall, upon such designation, be
released and relieved of its obligations under its Subsidiary Guarantee and any
Unrestricted Subsidiary whose designation as such is revoked and any newly
formed or newly acquired Subsidiary that becomes a Restricted Subsidiary will be
required to execute a Subsidiary Guarantee in accordance with the terms of the
Indenture.
MANDATORY REDEMPTION
Except as set forth below under "--Repurchase at the Option of Holders," the
Company is not required to make mandatory redemption or sinking fund payments
with respect to the Notes.
REPURCHASE AT THE OPTION OF HOLDERS
CHANGE OF CONTROL
Upon the occurrence of a Change of Control, each Holder of the Notes will,
unless the Company shall have elected to redeem the Notes prior to August 1,
2003 upon a Change of Control as permitted by the third paragraph of "--Optional
Redemption," have the right to require the Company to repurchase all or any part
(equal to $1,000 or an integral multiple thereof) of such Holder's Notes
pursuant to the offer described below (the "Change of Control Offer") at an
offer price in cash equal to 101% of the aggregate principal amount of the Notes
plus accrued and unpaid interest, if any, thereon to the date of purchase (the
"Change of Control Payment"). Within 30 days following any Change of Control,
the Company will mail a notice to each Holder describing the transaction or
transactions that constitute the Change of Control and offer to repurchase the
Notes pursuant to the procedures required by the Indenture and described in such
notice on a date no earlier than 30 days nor later than 60 days from the date
such notice is mailed (the "Change of Control Payment Date").
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On the Change of Control Payment Date, the Company will, to the extent
lawful, (i) accept for payment all Notes or portions thereof properly tendered
pursuant to the Change of Control Offer, (ii) deposit with the Paying Agent an
amount equal to the Change of Control Payment in respect of all the Notes or
portions thereof so tendered and (iii) deliver or cause to be delivered to the
Trustee the relevant Notes so accepted together with an Officers' Certificate
stating the aggregate principal amount of such Notes or portions thereof being
purchased by the Company. The Paying Agent will promptly mail to each Holder of
the Notes so tendered the Change of Control Payment for such Notes, and the
Trustee will promptly authenticate and mail (or cause to be transferred by book
entry) to each tendering Holder a new Note equal in principal amount to any
unpurchased portion of the Notes surrendered, if any; PROVIDED that each such
new Note will be in a principal amount of $1,000 or an integral multiple
thereof. The Indenture will provide that, prior to complying with the provisions
of this covenant, but in any event within 30 days following a Change of Control,
the Company will either repay all outstanding Senior Debt or obtain the
requisite consents, if any, under all agreements governing outstanding Senior
Debt to permit the repurchase of the Notes required by this covenant. The
Company will publicly announce the results of the Change of Control Offer on or
as soon as practicable after the Change of Control Payment Date.
Except as described above with respect to a Change of Control, the Indenture
will not contain provisions that permit the Holders of the Notes to require that
the Company repurchase or redeem the Notes in the event of a takeover,
recapitalization or similar transaction.
The Company will not be required to make a Change of Control Offer if a
third party makes the Change of Control Offer in the manner, at the times and
otherwise in compliance with the requirements set forth in the Indenture
applicable to a Change of Control Offer made by the Company and purchases all
Notes validly tendered and not withdrawn under such Change of Control Offer.
The definition of Change of Control includes a phrase relating to the sale,
lease, transfer, conveyance or other disposition of "all or substantially all"
of the assets of the Company and its Subsidiaries taken as a whole. Although
there is a developing body of case law interpreting the phrase "substantially
all," there is no precise established definition of the phrase under applicable
law. Accordingly, the ability of a Holder of the Notes to require the Company to
repurchase such Notes as a result of a sale, lease, transfer, conveyance or
other disposition of less than all of the assets of the Company and its
Subsidiaries taken as a whole to another Person or group may be uncertain.
In the event that the Company makes an offer to purchase the Notes pursuant
to the provisions of this "--Change of Control" covenant, the Company intends to
comply with any applicable securities laws and regulations, including any
applicable requirements of Section 14(e) of, and Rule 14e-1 under, the
Securities Exchange Act of 1934, as amended (the "Exchange Act").
ASSET SALES
The Indenture provides that the Company will not, and will not permit any of
its Restricted Subsidiaries to, engage in an Asset Sale unless (i) the Company
or the Restricted Subsidiary, as the case may be, receives consideration at the
time of such Asset Sale at least equal to the fair market value (as determined
in good faith by a resolution of the Board of Directors set forth in an
Officers' Certificate delivered to the Trustee, which determination shall be
conclusive evidence of compliance with this provision) of the assets or Equity
Interests issued or sold or otherwise disposed of and (ii) at least 85% of the
consideration therefor received by the Company or such Restricted Subsidiary
from such Asset Sale is in the form of cash, Cash Equivalents, properties and
capital assets to be used by the Company or any Restricted Subsidiary in the Oil
and Gas Business or oil and gas properties owned or held by another Person which
are to be used in the Oil and Gas Business of the Company or its Restricted
Subsidiaries, or any combination thereof (collectively the "Cash
Consideration"); PROVIDED that the amount of (x) any liabilities (as shown on
the Company's or such Restricted Subsidiary's most recent balance sheet) of the
Company or any Restricted Subsidiary (other than contingent liabilities and
liabilities that are by their terms subordinated to the Notes or any guarantee
thereof) that are assumed by the transferee of any such assets pursuant to a
customary novation agreement that releases the Company or such Restricted
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Subsidiary from further liability and (y) any non-cash consideration received by
the Company or any such Restricted Subsidiary from such transferee that are
converted by the Company or such Restricted Subsidiary into cash within 180 days
of closing such Asset Sale, shall be deemed to be cash for purposes of this
provision (to the extent of the cash received); PROVIDED, HOWEVER, that the
Company and its Restricted Subsidiaries may make Asset Sales with a fair market
value not exceeding $10 million in the aggregate in each fiscal year free from
any of the restrictions, requirements or other provisions under this "--Asset
Sales" section.
Within 360 days after the receipt of any Net Proceeds from an Asset Sale,
the Company may apply such Net Proceeds, at its 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 other Oil and Gas
Businesses or (d) to make capital expenditures in respect of the Company's or
its Restricted Subsidiaries' Oil and Gas Business or to purchase long-term
assets that are used or useful in the Oil and Gas Business. Pending the final
application of any such Net Proceeds, the Company may temporarily reduce Senior
Debt that is revolving debt or otherwise invest such Net Proceeds in any manner
that is not prohibited by the Indenture. Any Net Proceeds from Asset Sales that
are not applied as provided in the first sentence of this paragraph will (after
the expiration of the periods specified in this paragraph) be deemed to
constitute "Excess Proceeds."
When the aggregate amount of Excess Proceeds exceeds $15 million, the
Company will be required to make an offer to all Holders of the Notes and, to
the extent required by the terms thereof, to all holders or lenders of Pari
Passu Indebtedness (an "Asset Sale Offer") to purchase the maximum principal
amount of the Notes and any such Pari Passu Indebtedness to which the Asset Sale
Offer applies that may be purchased out of the Excess Proceeds, at an offer
price in cash equal to 100% of the principal amount thereof plus accrued and
unpaid interest thereon to the date of purchase, in accordance with the
procedures set forth in the Indenture or the agreements governing the Pari Passu
Indebtedness, as applicable. To the extent that the aggregate principal amount
of the Notes and Pari Passu Indebtedness (or accreted value, as the case may be)
tendered pursuant to an Asset Sale Offer is less than the Excess Proceeds, the
Company may use any remaining Excess Proceeds for general corporate purposes. If
the aggregate principal amount of the Notes surrendered by Holders thereof and
other Pari Passu Indebtedness surrendered by holders or lenders thereof,
collectively, exceeds the amount of Excess Proceeds, the Trustee shall select
the Notes and Pari Passu Indebtedness to be purchased on a pro rata basis, based
on the aggregate principal amount thereof (or accreted value, as the case may
be) surrendered in such Asset Sale Offer. Upon completion of such Asset Sale
Offer, the amount of Excess Proceeds shall be reset at zero.
In the event that the Company makes an offer to purchase the Notes pursuant
to the provisions of this "--Asset Sales" covenant, the Company intends to
comply with any applicable securities laws and regulations, including any
applicable requirements of Section 14(e) of, and Rule 14e-1 under, the Exchange
Act.
The Credit Facility may prohibit the Company from purchasing any Notes and
also provides that certain change of control events with respect to the Company
would constitute a default thereunder. Any future credit agreements or other
agreements relating to Senior Debt to which the Company becomes a party may
contain similar restrictions and provisions. In the event a Change of Control or
Asset Sale Offer occurs at a time when the Company is prohibited from purchasing
the Notes by the terms of the Credit Facility or other agreements relating to
other Senior Debt, the Company could seek the consent of its lenders to the
purchase or could attempt to refinance the borrowings that contain such
prohibition. If the Company does not obtain such a consent or refinance such
borrowings, the Company may remain prohibited from purchasing the Notes. In such
case, the Company's failure to purchase tendered Notes would constitute an Event
of Default under the Indenture which would, in turn, constitute a default under
the Credit Facility. In such circumstances, the subordination provisions in the
Indenture would likely restrict payments to the Holders of the Notes.
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CERTAIN COVENANTS
RESTRICTED PAYMENTS
The Indenture provides that the Company will not, and will not permit any of
its Restricted Subsidiaries to, directly or indirectly: (i) declare or pay any
dividend or make any other payment or distribution on account of the Equity
Interests of the Company or any Restricted Subsidiary (including, without
limitation, any payment in connection with any merger or consolidation involving
the Company) to the direct or indirect holders of Equity Interests of the
Company or any Restricted Subsidiary in their capacity as such (other than
dividends or distributions payable in Equity Interests of the Company or a
Restricted Subsidiary (other than Disqualified Stock) and other than dividends
or distributions payable to the Company or a Restricted Subsidiary so long as,
in the case of any dividend or distribution payable on or in respect of any
class or series of securities issued by a Subsidiary other than a Wholly Owned
Restricted Subsidiary, the Company or a Restricted Subsidiary receives at least
its pro rata share of such dividend or distribution in accordance with its
Equity Interests in such class or series of securities); (ii) purchase, redeem
or otherwise acquire or retire for value any Equity Interests of the Company or
any Subsidiary of the Company that is not a Wholly Owned Restricted Subsidiary
of the Company; (iii) make any principal payment on, or purchase, redeem,
defease or otherwise acquire or retire for value any Indebtedness that is
subordinated to the Notes, except at final maturity or as a mandatory or sinking
fund repayment; or (iv) make any Restricted Investment (all such payments and
other actions set forth in clauses (i) through (iv) above being collectively
referred to as "Restricted Payments"), unless, at the time of and after giving
effect to such Restricted Payment:
(a) no Default or Event of Default shall have occurred and be continuing
or would occur as a consequence thereof; and
(b) the Company would, at the time of such Restricted Payment and after
giving pro forma effect thereto as if such Restricted Payment had been made
at the beginning of the applicable four-quarter period, have been permitted
to incur at least $1.00 of additional Indebtedness pursuant to the Fixed
Charge Coverage Ratio test set forth in the first paragraph of the covenant
described below under the caption "--Incurrence of Indebtedness and Issuance
of Disqualified Stock"; and
(c) such Restricted Payment, together with the aggregate of all other
Restricted Payments made by the Company and its Restricted Subsidiaries
after the date of the Indenture (excluding Restricted Payments permitted by
clauses (1), (3), (4) and (6) of the next succeeding paragraph), is less
than the sum of (i) 50% of the Consolidated Net Income of the Company for
the period (taken as one accounting period) from the beginning of the first
fiscal quarter commencing after the date of the Indenture to the end of the
Company's most recently ended fiscal quarter for which internal financial
statements are available at the time of such Restricted Payment (or, if such
Consolidated Net Income for such period is a deficit, less 100% of such
deficit), PLUS (ii) 100% of the aggregate net cash proceeds received by the
Company from the issue or sale since the date of the Indenture of Equity
Interests of the Company or of debt securities of the Company that have been
converted into or exchanged for such Equity Interests (other than Equity
Interests (or convertible debt securities) sold to a Subsidiary of the
Company and other than Disqualified Stock or debt securities that have been
converted into Disqualified Stock), PLUS (iii) to the extent that any
Restricted Investment that was made after the date of the Indenture is sold
for cash or otherwise liquidated or repaid for cash or the receipt of
properties used in the Oil and Gas Business, the lesser of (A) the net cash
proceeds of such sale, liquidation or repayment or the fair market value of
property received in exchange therefor and (B) the amount of such Restricted
Investment, PROVIDED, however, that the foregoing provisions of this
paragraph (c) will not prohibit Restricted Payments in an aggregate amount
not to exceed $15 million.
The foregoing provisions will not prohibit (1) the payment of any dividend
within 60 days after the date of declaration thereof, if at said date of
declaration such payment would have complied with the provisions of the
Indenture; (2) the redemption, repurchase, retirement or other acquisition of
any Equity
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Interests of the Company in exchange for, or out of the proceeds of, the
substantially concurrent sale (other than to a Subsidiary of the Company) of
other Equity Interests of the Company (other than a sale of Disqualified Stock);
PROVIDED that the amount of any such net cash proceeds that are utilized for any
such redemption, repurchase, retirement or other acquisition shall be excluded
from clause (c)(ii) of the preceding paragraph; (3) the defeasance, redemption
or repurchase of subordinated Indebtedness with the net cash proceeds from an
incurrence of subordinated Permitted Refinancing Debt or the substantially
concurrent sale (other than to a Subsidiary of the Company) of Equity Interests
(other than Disqualified Stock) of the Company; PROVIDED that the amount of any
such net cash proceeds that are utilized for any such redemption, repurchase,
retirement or other acquisition shall be excluded from clause (c)(ii) of the
preceding paragraph; (4) the repurchase, redemption or other acquisition or
retirement for value of any Equity Interests of the Company or any Subsidiary of
the Company held by any of the Company's (or any of its Subsidiaries') employees
pursuant to any management equity subscription agreement or stock option
agreement in effect as of the date of the Indenture; PROVIDED that the aggregate
price paid for all such repurchased, redeemed, acquired or retired Equity
Interests shall not exceed $2 million in any twelve-month period; and PROVIDED
FURTHER that no Default or Event of Default shall have occurred and be
continuing immediately after such transaction; (5) repurchases of Equity
Interests deemed to occur upon exercise of stock options if such Equity
Interests represent a portion of the exercise price of such options; (6) the
making of loans by the Company or any of its Restricted Subsidiaries to officers
or directors of the Company; PROVIDED that the aggregate outstanding amount of
such loans shall not exceed, at any time, $2 million plus any such loans
outstanding on the date of the Indenture; and (7) during the period the Company
is subject to Subchapter S of the Internal Revenue Code of 1986, as amended (the
"Code"), and after such period to the extent relating to the liability for such
period, the making of payments or distributions or the payment of dividends in
amounts equal to the amounts required for the Company's stockholders to pay
Federal, state and local income taxes to the extent such income taxes are
attributable to the taxable income of the Company.
The amount of all Restricted Payments (other than cash) shall be the fair
market value (as determined in good faith by a resolution of the Board of
Directors set forth in an Officers' Certificate delivered to the Trustee) on the
date of the Restricted Payment of the asset(s) proposed to be transferred by the
Company or the applicable Restricted Subsidiary, as the case may be, pursuant to
the Restricted Payment. In computing Consolidated Net Income of the Company
under paragraph (c) above, (1) the Company shall use audited financial
statements for the portions of the relevant period for which audited financial
statements are available on the date of determination and unaudited financial
statements and other current financial data based on the books and records of
the Company for the remaining portion of such period and (2) the Company shall
be permitted to rely in good faith on the financial statements and other
financial data derived from the books and records of the Company that are
available on the date of determination.
DESIGNATION OF UNRESTRICTED SUBSIDIARIES
The Board of Directors of the Company may designate any Restricted
Subsidiary to be an Unrestricted Subsidiary if such designation would not cause
a Default. For purposes of making such determination, all outstanding
Investments by the Company and its Restricted Subsidiaries (except to the extent
repaid in cash) in the Subsidiary so designated will be deemed to be Restricted
Payments at the time of such designation and will reduce the amount available
for Restricted Payments under clause (c) of the first paragraph of the covenant
"Restricted Payments." All such outstanding Investments will be deemed to
constitute Investments in an amount equal to the greater of the fair market
value or the book value of such Investments at the time of such designation.
Such designation will only be permitted if such Restricted Payment would be
permitted at such time and if such Restricted Subsidiary otherwise meets the
definition of an Unrestricted Subsidiary.
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INCURRENCE OF INDEBTEDNESS AND ISSUANCE OF DISQUALIFIED STOCK
The Indenture provides that the Company will not, and will not permit any of
its Restricted Subsidiaries to, directly or indirectly, create, incur, issue,
assume, guarantee or otherwise become directly or indirectly liable,
contingently or otherwise, with respect to (collectively, "incur") any
Indebtedness or issue any Disqualified Stock and the Company will not permit any
of its Restricted Subsidiaries to issue any shares of Disqualified Stock to any
Person other than the Company or a Wholly-Owned Restricted Subsidiary of the
Company; PROVIDED, HOWEVER, that the Company and any Subsidiary Guarantor may
incur Indebtedness or issue shares of Disqualified Stock if:
(i) the Fixed Charge Coverage Ratio for the Company's most recently
ended four full fiscal quarters for which internal financial statements are
available immediately preceding the date on which such additional
Indebtedness is incurred or such Disqualified Stock is issued would have
been at least 2.5 to 1, determined on a pro forma basis as set forth in the
definition of Fixed Charge Coverage Ratio; and
(ii) no Default or Event of Default shall have occurred and be
continuing at the time such additional Indebtedness is incurred or such
Disqualified Stock is issued or would occur as a consequence of the
incurrence of the additional Indebtedness or the issuance of the
Disqualified Stock.
Notwithstanding the foregoing, the Indenture does not prohibit any of the
following (collectively, "Permitted Indebtedness"): (a) the Indebtedness
evidenced by the Notes; (b) the incurrence by the Company or any of its
Restricted Subsidiaries of Indebtedness pursuant to Credit Facilities, so long
as the aggregate principal amount of all Indebtedness outstanding under all
Credit Facilities does not, at any one time, exceed the greater of (i) $175
million and (ii) the Borrowing Base, provided that the Company may incur more
than $175 million of Indebtedness pursuant to Credit Facilities only if the
Fixed Charge Coverage Ratio for the Company's most recently ended four full
fiscal quarters for which internal financial statements are available would have
been at least 2.0 to 1, determined on a pro forma basis as set forth in the
definition of Fixed Charge Coverage Ratio; (c) the guarantee by any Subsidiary
Guarantor of any Indebtedness that is permitted by the Indenture to be incurred
by the Company; (d) all Indebtedness of the Company and its Restricted
Subsidiaries in existence as of the date of the Indenture; (e) intercompany
Indebtedness between or among the Company and any of its Wholly Owned Restricted
Subsidiaries; PROVIDED, HOWEVER, that if the Company is the obligor on such
Indebtedness, (A) any subsequent issuance or transfer of Equity Interests that
results in any such Indebtedness being held by a Person other than the Company
or a Wholly Owned Restricted Subsidiary and (B) any sale or other transfer of
any such Indebtedness to a Person that is not either the Company or a Wholly
Owned Restricted Subsidiary shall be deemed, in each case, to constitute an
incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as
the case may be; (f) Indebtedness in connection with one or more standby letters
of credit, guarantees, performance bonds or other reimbursement obligations, in
each case, issued in the ordinary course of business and not in connection with
the borrowing of money or the obtaining of advances or credit (other than
advances or credit on open account, includible in current liabilities, for goods
and services in the ordinary course of business and on terms and conditions
which are customary in the Oil and Gas Business, and other than the extension of
credit represented by such letter of credit, guarantee or performance bond
itself), not to exceed in the aggregate at any given time 5% of Total Assets;
(g) Indebtedness under Interest Rate Hedging Agreements entered into for the
purpose of limiting interest rate risks, PROVIDED that the obligations under
such agreements are related to payment obligations on Indebtedness otherwise
permitted by the terms of this covenant and that the aggregate notional
principal amount of such agreements does not exceed 105% of the principal amount
of the Indebtedness to which such agreements relate; (h) Indebtedness under Oil
and Gas Hedging Contracts, PROVIDED that such contracts were entered into in the
ordinary course of business for the purpose of limiting risks that arise in the
ordinary course of business of the Company and its Restricted Subsidiaries; (i)
the incurrence by the Company and its Restricted Subsidiaries of Indebtedness
not otherwise permitted to be incurred pursuant
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to this paragraph, PROVIDED that the aggregate principal amount of all
Indebtedness incurred pursuant to this clause (i), together with all Permitted
Refinancing Debt incurred pursuant to clause (j) of this paragraph in respect of
Indebtedness previously incurred pursuant to this clause (i), does not exceed
$20 million at any one time outstanding; (j) Permitted Refinancing Debt incurred
in exchange for, or the net proceeds of which are used to refinance, extend,
renew, replace, defease or refund, Indebtedness that was permitted by the
Indenture to be incurred (including Indebtedness previously incurred pursuant to
this clause (j), but excluding Indebtedness under clauses (b), (e), (f), (g),
(h), (k), (l) and (m)); (k) accounts payable or other obligations of the Company
or any Restricted Subsidiary to trade creditors created or assumed by the
Company or such Restricted Subsidiary in the ordinary course of business in
connection with the obtaining of goods or services; (l) Indebtedness consisting
of obligations in respect of purchase price adjustments, guarantees or
indemnities in connection with the acquisition or disposition of assets; (m)
production imbalances occurring in the ordinary course of business that do not,
at any one time outstanding, exceed 2% of the Total Assets of the Company; (n)
rents and royalties due others incurred in the ordinary course of the Oil and
Gas Business; and (o) Indebtedness of a Subsidiary Guarantor in respect of the
Subsidiary Guarantee of such Subsidiary Guarantor.
The Indenture provides that the Company will not permit any Unrestricted
Subsidiary to incur any Indebtedness other than Non-Recourse Debt; PROVIDED,
HOWEVER, if any such Indebtedness ceases to be Non-Recourse Debt, such event
shall be deemed to constitute an incurrence of Indebtedness by the Company.
NO LAYERING
The Indenture provides that (i) the Company will not incur, create, issue,
assume, guarantee or otherwise become liable for any Indebtedness that is
subordinate or junior in right of payment to any Senior Debt and senior in any
respect in right of payment to the Notes and (ii) the Subsidiary Guarantors will
not directly or indirectly incur, create, issue, assume, guarantee or otherwise
become liable for any Indebtedness that is subordinate or junior in right of
payment to Guarantor Senior Debt and senior in any respect in right of payment
to the Subsidiary Guarantees, PROVIDED, HOWEVER, that the foregoing limitations
will not apply to distinctions between categories of Indebtedness that exist by
reason of any Liens arising or created in accordance with the provisions of the
Indenture in respect of some but not all such Indebtedness.
LIENS
The Indenture provides that the Company will not, and will not permit any of
its Restricted Subsidiaries to, create, incur, assume or otherwise cause or
suffer to exist or become effective any Lien securing Indebtedness of any kind
(other than Permitted Liens) upon any of its property or assets, now owned or
hereafter acquired, unless all payments under the Notes are secured by such Lien
prior to, or on an equal and ratable basis with, the Indebtedness so secured for
so long as such Indebtedness is secured by such Lien.
SALE AND LEASEBACK TRANSACTIONS
The Indenture provides that the Company will not, and will not permit any of
its Restricted Subsidiaries to, enter into any sale and leaseback transaction;
PROVIDED that the Company or its Restricted Subsidiaries may enter into a sale
and leaseback transaction if (i) the Company could have incurred Indebtedness in
an amount equal to the Attributable Debt relating to such sale and leaseback
transaction pursuant to the test set forth in the first paragraph of the
covenant described above under the caption "Incurrence of Indebtedness and
Issuance of Disqualified Stock" or (ii) the gross cash proceeds of such sale and
leaseback transaction are at least equal to the fair market value (as determined
in good faith by a resolution the Board of Directors set forth in an Officers'
Certificate delivered to the Trustee) of the property that is the subject of
such sale and leaseback transaction and the transfer of assets in such sale
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and leaseback transaction is permitted by, and the Company applies the net
proceeds of such transaction in compliance with, the covenant described above
under the caption "Repurchase at the Option of Holders-- Asset Sales."
DIVIDEND AND OTHER PAYMENT RESTRICTIONS AFFECTING RESTRICTED SUBSIDIARIES
The Indenture provides that the Company will not, and will not permit any of
its Restricted Subsidiaries to, directly or indirectly, create or otherwise
cause or suffer to exist or become effective any encumbrance or restriction on
the ability of any Restricted Subsidiary to (i)(x) pay dividends or make any
other distributions to the Company or any of the Restricted Subsidiaries of the
Company (1) on its Capital Stock or (2) with respect to any other interest or
participation in, or measured by, its profits, or (y) pay any Indebtedness owed
to the Company or any Restricted Subsidiaries of the Company, (ii) make loans or
advances to the Company or any Restricted Subsidiaries of the Company or (iii)
transfer any of its properties or assets to the Company or any Restricted
Subsidiaries of the Company, except for such encumbrances or restrictions
existing under or by reason of (a) the Credit Facility as in effect as of the
date of the Indenture and any amendments, modifications, restatements, renewals,
increases, supplements, refundings, replacements or refinancings thereof or any
other Credit Facility, PROVIDED that such amendments, modifications,
restatements, renewals, increases, supplements, refundings, replacements,
refinancings or other Credit Facilities are no more restrictive with respect to
such dividend and other payment restrictions than those contained in the Credit
Facility as in effect on the date of the Indenture, (b) the Indenture and the
Notes, (c) applicable law, (d) any instrument governing Indebtedness or Capital
Stock of a Person acquired by the Company or any of its Restricted Subsidiaries
as in effect at the time of such acquisition (except, in the case of
Indebtedness, to the extent such Indebtedness was incurred in connection with or
in contemplation of such acquisition), which encumbrance or restriction is not
applicable to any Person, or the properties or assets of any Person, other than
the Person and its Subsidiaries, or the property or assets of the Person and its
Subsidiaries, so acquired, PROVIDED that, such Indebtedness or Capital Stock was
permitted by the terms of the Indenture to be incurred, (e) customary
non-assignment provisions in leases entered into in the ordinary course of
business, (f) purchase money obligations for property acquired in the ordinary
course of business that impose restrictions of the nature described in clause
(iii) above on the property so acquired, (g) Permitted Refinancing Debt,
PROVIDED that the restrictions contained in the agreements governing such
Permitted Refinancing Debt are no more restrictive than those contained in the
agreements governing the Indebtedness being refinanced, (h) any other security
agreement, instrument or document relating to Senior Debt hereafter in effect,
provided that such encumbrances or restrictions are customary in connection with
such documents and that the terms and conditions of such encumbrances or
restrictions are no more restrictive than those encumbrances or restrictions
imposed in connection with the Credit Facility, (i) Permitted Liens, (j)
customary provisions in joint venture agreements and other similar agreements
relating to the distribution of revenues from such joint venture or other
business venture, or (k) any agreement relating to a sale and leaseback
transaction or capital lease, but only on the property subject to such
transaction or lease and only to the extent that such restrictions or
encumbrances are customary with respect to a sale and leaseback transaction or
capital lease.
LIMITATION ON THE SALE OR ISSUANCE OF CAPITAL STOCK OF RESTRICTED
SUBSIDIARIES
The Indenture provides that the Company will not sell or otherwise dispose
of any shares of Capital Stock of a Restricted Subsidiary, and shall not permit
any Restricted Subsidiary, directly or indirectly, to issue or sell or otherwise
dispose of any shares of its Capital Stock except (i) to the Company or a Wholly
Owned Restricted Subsidiary, (ii) if, immediately after giving effect to such
issuance, sale or other disposition, such Restricted Subsidiary remains a
Restricted Subsidiary, (iii) shares of nonvoting Capital Stock of Restricted
Subsidiaries may be issued or sold to employees or directors of the Company or
any Subsidiary, or (iv) if all shares of Capital Stock of such Restricted
Subsidiary are sold or otherwise disposed. In connection with any sale or
disposition of Capital Stock of a Restricted Subsidiary, the
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Company will be required to comply with the covenant described under the caption
"Repurchase at the Option of Holders--Asset Sales" above.
MERGER, CONSOLIDATION, OR SALE OF ASSETS
The Indenture provides that the Company may not consolidate or merge with or
into (whether or not the Company is the surviving corporation), or sell, assign,
transfer, lease, convey or otherwise dispose of all or substantially all of its
properties or assets, in one or more related transactions, to another Person,
and the Company may not permit any of its Restricted Subsidiaries to enter into
any such transaction or series of transactions if such transaction or series of
transactions would, in the aggregate, result in a sale, assignment, transfer,
lease, conveyance, or other disposition of all or substantially all of the
properties or assets of the Company to another Person unless (i) the Company is
the surviving corporation or the Person formed by or surviving any such
consolidation or merger (if other than the Company) or to which such sale,
assignment, transfer, lease, conveyance or other disposition shall have been
made (the "Surviving Entity") is a corporation organized or existing under the
laws of the United States, any state thereof or the District of Columbia; (ii)
the Surviving Entity (if the Company is not the continuing obligor under the
Indenture) assumes all the obligations of the Company under the Notes and the
Indenture pursuant to a supplemental indenture in a form reasonably satisfactory
to the Trustee; (iii) immediately before and after giving effect to such
transaction or series of transactions no Default or Event of Default exists;
(iv) immediately after giving effect to such transaction or series of
transactions on a pro forma basis (and treating any Indebtedness not previously
an obligation of the Company and its Restricted Subsidiaries which becomes the
obligation of the Company or any of its Restricted Subsidiaries as a result of
such transaction as having been incurred at the time of such transaction or
series of transactions), the Consolidated Net Worth of the Company or the
Surviving Entity (if the Company is not the continuing obligor under the
Indenture) is equal to or greater than the Consolidated Net Worth of the Company
immediately prior to such transaction or series of transactions; and (v) the
Company or the Surviving Entity (if the Company is not the continuing obligor
under the Indenture) will, at the time of such transaction or series of
transactions and after giving pro forma effect thereto as if such transaction or
series of transactions had occurred at the beginning of the applicable
four-quarter period, be permitted to incur at least $1.00 of additional
Indebtedness pursuant to the test set forth in the first paragraph of the
covenant described above under the caption "--Incurrence of Indebtedness and
Issuance of Disqualified Stock." Each Subsidiary Guarantor, if any, unless it is
the other party to the transactions described above, shall have confirmed by
supplemental indenture that its Subsidiary Guarantee shall apply to such
Person's obligations under the Indenture and the Notes. Notwithstanding the
restrictions described in the foregoing clauses (iv) and (v), any Restricted
Subsidiary may consolidate with, merge into or transfer all or part of its
properties and assets to the Company, and any Wholly Owned Restricted Subsidiary
may consolidate with, merge into or transfer all or part of its properties and
assets to another Wholly Owned Restricted Subsidiary.
TRANSACTIONS WITH AFFILIATES
The Indenture provides that the Company will not, and will not permit any of
its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or
otherwise dispose of any of its properties or assets to, or purchase any
property or assets from, or enter into or make or amend any contract, agreement,
understanding, loan, advance or guarantee with, or for the benefit of, any of
its Affiliates (each of the foregoing, an "Affiliate Transaction"), unless (i)
such Affiliate Transaction is on terms that are no less favorable to the Company
or the relevant Restricted Subsidiary than those that would have been obtained
in a comparable transaction by the Company or such Restricted Subsidiary with an
unrelated Person and (ii) the Company delivers to the Trustee (a) with respect
to any Affiliate Transaction or series of related Affiliate Transactions
involving aggregate consideration in excess of $1 million but less than or equal
to $5 million, an Officer's Certificate certifying that such Affiliate
Transaction complies with clause (i) above, (b) with respect to any Affiliate
Transaction or series of related Affiliate Transactions involving
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aggregate consideration in excess of $5 million but less than or equal to $10
million, a resolution of the Board of Directors set forth in an Officer's
Certificate certifying that such Affiliate Transaction complies with clause (i)
above and that such Affiliate Transaction has been approved in good faith by a
majority of the members of the Board of Directors who have no financial interest
in such Affiliate Transaction, which resolution shall be conclusive evidence of
compliance with this provision, and (c) with respect to any Affiliate
Transaction or series of related Affiliate Transactions involving aggregate
consideration in excess of $10 million, an Officer's Certificate as described in
clause (b) above and an opinion as to the fairness to the Company or such
Subsidiary of such Affiliate Transaction from a financial point of view issued
by an accounting, appraisal, engineering or investment banking firm of national
standing (for purposes of this clause (c) such opinion and the resolution
described in clause (b) above shall be conclusive evidence of compliance with
this provision); PROVIDED that the following shall not be deemed Affiliate
Transactions: (1) reasonable fees and compensation paid to (including issuances
and grants of securities and stock options), and employment agreements and stock
option and ownership plans for the benefit of, officers, directors, employees or
consultants of the Company or any Restricted Subsidiary of the Company as
determined in good faith by the Company's Board of Directors or senior
management, (2) transactions contemplated by any employment agreement or other
compensation plan or arrangement entered into by the Company or any of its
Subsidiaries in the ordinary course of business and consistent with past
practice of the Company or such Subsidiary, (3) transactions between or among
the Company and/or its Restricted Subsidiaries, (4) Restricted Payments and
Permitted Investments that are permitted by the provisions of the Indenture
described above under the caption "--Restricted Payments" and the definition of
Permitted Investments, (5) indemnification payments made to officers, directors
and employees of the Company or its Subsidiaries pursuant to charter, by-law,
statutory or contractual provisions, (6) any contracts, agreements and
understandings existing as of the date of the Indenture, and (7) oil and gas
leasehold acquisition, drilling, well servicing and leasehold operations
services provided by or to such Affiliate in the ordinary course of the Oil and
Gas Business on terms that are no less favorable to the Company or the relevant
Restricted Subsidiary than those that would have been obtained in a comparable
transaction by the Company or such Restricted Subsidiary with an unrelated
Person.
ADDITIONAL SUBSIDIARY GUARANTEES
The Indenture provides that if the Company or any of its Restricted
Subsidiaries shall acquire or create another Restricted Subsidiary after the
date of the Indenture, then such newly acquired or created Restricted Subsidiary
will be required to execute a Subsidiary Guarantee in accordance with the terms
of the Indenture.
BUSINESS ACTIVITIES
The Company will not, and will not permit any Restricted Subsidiary to,
engage in any material respect in any business other than the Oil and Gas
Business.
COMMISSION REPORTS
Notwithstanding that the Company is not subject to the reporting
requirements of Section 13 or 15(d) of the Exchange Act, the Company will file
with the Commission and, within 15 days after such filing, provide the Trustee
and Holders with the annual reports and the information, documents and other
reports which are specified in Sections 13 and 15(d) of the Exchange Act. In the
event that the Company is not permitted to file such reports, documents and
information with the Commission, the Company will provide substantially similar
information to the Trustee and the Holders as if the Company were subject to the
reporting requirements of Section 13 or 15(d) of the Exchange Act within 15 days
of the date the Company would have been obligated to file such reports with the
Commission, were the Company permitted to file such reports with the Commission.
The Company also will comply with the other provisions of Section 314(a) of the
Trust Indenture Act.
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EVENTS OF DEFAULT AND REMEDIES
The Indenture provides that each of the following constitutes an Event of
Default: (i) a default for 30 consecutive days in the payment when due of
interest on the Notes (whether or not prohibited by the subordination provisions
of the Indenture); (ii) a default in payment when due of the principal of or
premium, if any, on the Notes (whether or not prohibited by the subordination
provisions of the Indenture); (iii) the failure by the Company or a Subsidiary
Guarantor to comply with its obligations under "Certain Covenants--Merger,
Consolidation or Sale of Assets" above; (iv) the failure by the Company for 30
days after notice from the Trustee or the Holders of at least 25% in aggregate
principal amount of the Notes then outstanding to comply with the provisions
described under the captions "Repurchase at the Option of Holders" and "Certain
Covenants" other than the provisions described under "--Merger, Consolidation or
Sale of Assets"; (v) failure by the Company for 60 consecutive days after notice
from the Trustee or the Holders of at least 25% in aggregate principal amount of
the Notes then outstanding to comply with any of its other agreements in the
Indenture or the Notes; (vi) except as permitted by the Indenture, any
Subsidiary Guarantee shall be held in any judicial proceeding to be
unenforceable or invalid or shall cease for any reason to be in full force and
effect or a Subsidiary Guarantor, or any Person acting on behalf of such
Subsidiary Guarantor, shall deny or disaffirm its obligations under its
Subsidiary Guarantee; (vii) a default under any mortgage, indenture or
instrument under which there may be issued or by which there may be secured or
evidenced any Indebtedness for money borrowed by the Company or any of its
Restricted Subsidiaries (or the payment of which is guaranteed by the Company or
any of its Restricted Subsidiaries) whether such Indebtedness or guarantee now
exists, or is created after the date of the Indenture, which default (a) is
caused by a failure to pay principal of such Indebtedness prior to the
expiration of the grace period provided in such Indebtedness on the date of such
default (a "Payment Default") or (b) results in the acceleration of such
Indebtedness prior to its express maturity and, in each case, the principal
amount of any such Indebtedness, together with the principal amount of any other
such Indebtedness under which there is then existing a Payment Default or the
maturity of which has been so accelerated, aggregates $10 million or more;
(viii) the failure by the Company or any of its Restricted Subsidiaries to pay
final, non-appealable judgments aggregating in excess of $10 million, which
judgments remain unpaid or discharged for a period of 60 days; and (ix) certain
events of bankruptcy or insolvency with respect to the Company or any of its
Restricted Subsidiaries.
If any Event of Default occurs and is continuing, the Trustee or the Holders
of at least 25% in aggregate principal amount of the Notes then outstanding may
declare the principal of and accrued but unpaid interest on such Notes to be due
and payable immediately. Notwithstanding the foregoing, in the case of an Event
of Default arising from certain events of bankruptcy or insolvency, with respect
to the Company or any Restricted Subsidiary, all outstanding Notes will become
due and payable without further action or notice. Holders of the Notes may not
enforce the Indenture or the Notes except as provided in the Indenture. Subject
to certain limitations, Holders of a majority in principal amount of the Notes
then outstanding may direct the Trustee in its exercise of any trust or power.
The Trustee may withhold from Holders of the Notes notice of any continuing
Default or Event of Default (except a Default or Event of Default relating to
the payment of principal or interest) if it determines that withholding notice
is in their interest.
The Holders of a majority in aggregate principal amount of the Notes then
outstanding by notice to the Trustee may on behalf of the Holders of all of the
Notes waive any existing Default or Event of Default and its consequences under
the Indenture except a continuing Default or Event of Default in the payment of
interest or premium on, or the principal of, the Notes.
The Company is required to deliver to the Trustee annually a statement
regarding compliance with the Indenture, and the Company is required, within
five business days of becoming aware of any Default or Event of Default, to
deliver to the Trustee a statement specifying such Default or Event of Default.
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LEGAL DEFEASANCE AND COVENANT DEFEASANCE
The Company may, at its option and at any time, elect to have all of its
obligations discharged with respect to the outstanding Notes and have each
Subsidiary Guarantor's, if any, obligation discharged with respect to its
Subsidiary Guarantee ("Legal Defeasance") except for (i) the rights of Holders
of such outstanding Notes to receive payments in respect of the principal of,
premium, if any, or interest on such Notes when such payments are due from the
trust referred to below, (ii) the Company's obligations with respect to such
Notes concerning issuing temporary Notes, registration of such Notes, mutilated,
destroyed, lost or stolen Notes and the maintenance of an office or agency for
payments, (iii) the rights, powers, trusts, duties and immunities of the
Trustee, and the Company's obligations in connection therewith and (iv) the
Legal Defeasance provisions of the Indenture. In addition, the Company may, at
its option and at any time, elect to have the obligations of the Company
released with respect to certain covenants that are described in the Indenture
("Covenant Defeasance") and thereafter any omission to comply with such
obligations shall not constitute a Default or Event of Default. In the event
Covenant Defeasance occurs, certain events (not including non-payment,
bankruptcy, receivership, rehabilitation and insolvency events) described under
"Events of Default and Remedies" will no longer constitute an Event of Default.
In order to exercise either Legal Defeasance or Covenant Defeasance, (i) the
Company must irrevocably deposit with the Trustee, in trust, for the benefit of
the Holders of the Notes, cash in U.S. dollars, non-callable Government
Securities, or a combination thereof, in such amounts as will be sufficient, in
the opinion of a nationally recognized firm of independent public accountants,
to pay the principal of, premium, if any, and interest on the outstanding Notes
on the stated maturity or on the applicable redemption date, as the case may be,
and the Company must specify whether the Notes are being defeased to maturity or
to a particular redemption date; (ii) in the case of Legal Defeasance, the
Company shall have delivered to the Trustee an opinion of counsel in the United
States reasonably acceptable to such Trustee confirming that (A) the Company has
received from, or there has been published by, the Internal Revenue Service a
ruling or (B) since the date of the Indenture, there has been a change in the
applicable federal income tax law, in either case to the effect that, and based
thereon such opinion of counsel shall confirm that, the Holders of the
outstanding Notes will not recognize income, gain or loss for federal income tax
purposes as a result of such Legal Defeasance and will be subject to federal
income tax on the same amounts, in the same manner and at the same times as
would have been the case if such Legal Defeasance had not occurred; (iii) in the
case of Covenant Defeasance, the Company shall have delivered to the Trustee an
opinion of counsel in the United States reasonably acceptable to such Trustee
confirming that the Holders of the outstanding Notes will not recognize income,
gain or loss for federal income tax purposes as a result of such Covenant
Defeasance and will be subject to federal income tax on the same amounts, in the
same manner and at the same times as would have been the case if such Covenant
Defeasance had not occurred; (iv) no Default or Event of Default shall have
occurred and be continuing on the date of such deposit (other than a Default or
Event of Default resulting from the borrowing of funds to be applied to such
deposit) or insofar as Events of Default from bankruptcy or insolvency events
are concerned, at any time in the period ending on the 91st day after the date
of deposit; (v) such Legal Defeasance or Covenant Defeasance will not result in
a breach or violation of, or constitute a default under, any material agreement
or instrument (other than the Indenture) to which the Company or any of its
Subsidiaries is a party or by which the Company or any of its Subsidiaries is
bound; (vi) the Company must have delivered to the Trustee an opinion of counsel
to the effect that after the 91st day following the deposit, the trust funds
will not be subject to the effect of any applicable bankruptcy, insolvency,
reorganization or similar laws affecting creditors' rights generally; (vii) the
Company must deliver to the Trustee an Officers' Certificate stating that the
deposit was not made by the Company with the intent of preferring the Holders of
the Notes over the other creditors of the Company, or with the intent of
defeating, hindering, delaying or defrauding creditors of the Company or others;
and (viii) the Company must deliver to the Trustee an Officers' Certificate and
an opinion of counsel, each stating that
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all conditions precedent provided for relating to the Legal Defeasance or the
Covenant Defeasance have been complied with.
TRANSFER AND EXCHANGE
A Holder may, subject to certain restrictions, transfer or exchange Notes in
accordance with the Indenture. The Registrar and the Trustee may require a
Holder, among other things, to furnish appropriate endorsements and transfer
documents and the Company may require a Holder to pay any taxes and fees
required by law or permitted by the Indenture. The Company is not required to
transfer or exchange any Note selected for redemption. Also, the Company is not
required to transfer or exchange any Note for a period of 15 days before a
selection of the Notes to be redeemed.
The registered Holder of a Note will be treated as the owner of it for all
purposes.
AMENDMENT, SUPPLEMENT AND WAIVER
Except as provided in the next two succeeding paragraphs, the Indenture, the
Notes or the Subsidiary Guarantees may be amended or supplemented with the
consent of the Holders of at least a majority in principal amount of the Notes
then outstanding (including, without limitation, consents obtained in connection
with a purchase of, or tender offer or exchange offer for, the Notes), and any
existing default or compliance with any provision of the Indenture or the Notes
or the Subsidiary Guarantees may be waived with the consent of the Holders of a
majority in principal amount of the then outstanding Notes (including consents
obtained in connection with a tender offer or exchange offer for the Notes).
Without the consent of each Holder affected, an amendment or waiver may not
(with respect to any Notes held by a non-consenting Holder): (i) reduce the
principal amount of the Notes whose Holders must consent to an amendment,
supplement or waiver, (ii) reduce the principal of or change the fixed maturity
of any Note or alter the provisions with respect to the redemption of the Notes
as described above under "Optional Redemption" or "Repurchase at the Option of
Holders", (iii) reduce the rate of or change the time for payment of interest on
any Note, (iv) waive a Default or Event of Default in the payment of principal
of or premium, if any, or interest on the Notes (except a rescission of
acceleration of the Notes by the Holders of at least a majority in principal
amount of such Notes and a waiver of the payment default that resulted from such
acceleration), (v) make any Note payable in money other than that stated in the
Notes, (vi) make any change in the provisions of the Indenture relating to
waivers of past Defaults or the rights of Holders of the Notes to receive
payments of principal of or premium, if any, or interest on the Notes, (vii)
make any change in the foregoing amendment and waiver provisions or (viii)
except as provided under the third paragraph of "Subsidiary Guarantees" or
"Legal Defeasance and Covenant Defeasance," release a Subsidiary Guarantor, if
any, from its obligations under its Subsidiary Guarantee, if any, or make any
change in a Subsidiary Guaranty, if any, that would adversely affect the
Holders. In addition, any amendment to the provisions of Article 10 of the
Indenture (which relates to subordination) will require the consent of the
Holders of at least 66 2/3% in principal amount of the Notes then outstanding if
such amendment would adversely affect the rights of Holders of such Notes.
However, no amendment may be made to the subordination provisions of the
Indenture that adversely affects the rights of any holder of Senior Debt then
outstanding unless the holders of such Senior Debt (or any group or
representative thereof authorized to give a consent) consents to such change.
Notwithstanding the foregoing, without the consent of any Holder of the
Notes the Company and the Trustee may amend or supplement the Indenture or the
Notes to cure any ambiguity, defect or inconsistency, to provide for
uncertificated Notes in addition to or in place of certificated Notes (provided,
however, that the uncertificated Notes are issued in registered form for
purposes of section 163(f) of the Code, or in a manner such that the
uncertificated Notes are described in Section 163(f)(2)(B) of the Code), to
provide for the assumption of the Company's obligations to Holders of the Notes
in the case of a merger or consolidation, to make any change that would provide
any additional rights or benefits to the
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Holders of the Notes or that does not adversely affect the legal rights under
the Indenture of any such Holder, to add Guarantees with respect to the Notes or
to secure the Notes, or to comply with requirements of the Commission in order
to effect or maintain the qualification of the Indenture under the Trust
Indenture Act.
CONCERNING THE TRUSTEE
The Indenture contains certain limitations on the rights of the Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases, or to realize on certain property received in respect of any such
claim as security or otherwise. The Trustee will be permitted to engage in other
transactions; however, if it acquires any conflicting interest, it must
eliminate such conflict within 90 days, apply to the Commission for permission
to continue or resign.
The Holders of a majority in principal amount of the then outstanding Notes
will have the right to direct the time, method and place of conducting any
proceeding for exercising any remedy available to the Trustee, subject to
certain exceptions. The Indenture provides that in case an Event of Default
shall occur (which shall not be cured), the Trustee will be required, in the
exercise of its power, to use the degree of care of a prudent man in the conduct
of his own affairs. Subject to such provisions, the Trustee will be under no
obligation to exercise any of its rights or powers under the Indenture at the
request of any Holder of the Notes, unless such Holder shall have offered to
such Trustee security and indemnity satisfactory to it against any loss,
liability or expense.
GOVERNING LAW
The Indenture, the Notes and the Subsidiary Guarantees provide that they
will be governed by the laws of the State of New York.
CERTAIN DEFINITIONS
Set forth below are certain defined terms used in the Indenture. Reference
is made to the Indenture for a full definition of all such terms, as well as any
other capitalized terms used herein for which no definition is provided.
"ACQUIRED DEBT" means, with respect to any specified Person, (i)
Indebtedness of any other Person existing at the time such other Person is
merged with or into or becomes a Subsidiary of such specified Person, including,
without limitation, Indebtedness incurred in connection with, or in
contemplation of, such other Person merging with or into or becoming a
Subsidiary of such specified Person, and (ii) Indebtedness secured by a Lien
encumbering any asset acquired by such specified Person.
"AFFILIATE" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with such specified Person. For purposes of this definition, "control"
(including, with correlative meanings, the terms "controlling," "controlled by"
and "under common control with"), as used with respect to any Person, shall mean
the possession, directly or indirectly, of the power to direct or cause the
direction of the management or policies of such Person, whether through the
ownership of voting securities, by agreement or otherwise.
"APPLICABLE PREMIUM" means, with respect to a Note at the redemption date,
the greater of (i) 1% of the principal amount of such Note and (ii) the excess
of (A) the present value at such time of (1) the redemption price of such Note
at August 1, 2003 (such redemption price being described under "--Optional
Redemption"), PLUS (2) all required interest payments (excluding accrued but
unpaid interest) due on such Note through August 1, 2003, computed using a
discount rate equal to the Treasury Rate plus 50 basis points, over (B) the
then-outstanding principal amount of such Note.
"ASSET SALE" means (i) the sale, lease, conveyance or other disposition by
the Company or any of its Restricted Subsidiaries (but excluding the creation of
a Lien) of any assets including, without limitation, by
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way of a sale and leaseback (provided that the sale, lease, conveyance or other
disposition of all or substantially all of the assets of the Company and its
Subsidiaries taken as a whole will be governed by the provisions of the
Indenture described above under the caption "--Repurchase at the Option of
Holders-- Change of Control" and/or the provisions described above under the
caption "--Certain Covenants-- Merger, Consolidation, or Sale of Assets" and not
by the provisions described above under "--Repurchase at the Option of
Holders--Asset Sales"), and (ii) the issue or sale by the Company or any of its
Restricted Subsidiaries of Equity Interests of any of the Company's Subsidiaries
(including the sale by the Company or a Restricted Subsidiary of Equity
Interests in an Unrestricted Subsidiary), in the case of either clause (i) or
(ii), whether in a single transaction or a series of related transactions (a)
that have a fair market value in excess of $5 million or (b) for Net Proceeds in
excess of $5 million. Notwithstanding the foregoing, the following shall not be
deemed to be Asset Sales: (i) a transfer of assets by the Company to a
Restricted Subsidiary of the Company or by a Restricted Subsidiary of the
Company to the Company or to another Restricted Subsidiary of the Company, (ii)
an issuance of Equity Interests by a Wholly Owned Restricted Subsidiary of the
Company to the Company or to another Wholly Owned Restricted Subsidiary of the
Company, (iii) the making of a Restricted Payment or Permitted Investment that
is permitted by the covenant described above under the caption "--Certain
Covenants--Restricted Payments"; provided that the sale, lease, conveyance or
other disposition by the Company or any of its Restricted Subsidiaries of an
Investment shall be deemed an Asset Sale, (iv) the abandonment, farm-out, lease
or sublease of undeveloped oil and gas properties in the ordinary course of
business, (v) the trade or exchange by the Company or any Restricted Subsidiary
of the Company of any oil and gas property or interest therein owned or held by
the Company or such Restricted Subsidiary for any oil and gas property or
interest therein owned or held by another Person, including any cash or Cash
Equivalents necessary in order to achieve an exchange of equivalent value;
provided that any such cash or Cash Equivalents received by the Company or such
Restricted Subsidiary will be subject to the provisions described in the second
and third paragraphs under "Repurchase at the Option of Holders--Asset Sales,"
which the Board of Directors of the Company determines in good faith by
resolution to be of approximately equivalent value, (vi) the sale or transfer of
hydrocarbons or other mineral products in the ordinary course of business, (vii)
the sale of oil and gas properties in connection with tax credit transactions
complying with Section 29 or any successor or analogous provisions of the
Internal Revenue Code or (viii) the sale or transfer of surplus or obsolete
equipment in the ordinary course of business.
"ATTRIBUTABLE DEBT" in respect of a sale and leaseback transaction means, at
the time of determination, the present value (discounted at the rate of interest
implicit in such transaction, determined in accordance with GAAP) of the
obligation of the lessee for net rental payments during the remaining term of
the lease included in such sale and leaseback transaction (including any period
for which such lease has been extended or may, at the option of the lessor, be
extended).
"BORROWING BASE" means, as of any date, the aggregate amount of borrowing
availability as of such date under all Credit Facilities that determines
availability on the basis of a borrowing base or other asset-based calculation.
"CAPITAL LEASE OBLIGATION" means, at the time any determination thereof is
to be made, the amount of the liability in respect of a capital lease that would
at such time be required to be capitalized on a balance sheet in accordance with
GAAP.
"CAPITAL STOCK" means (i) in the case of a corporation, corporate stock,
(ii) in the case of an association or business entity, any and all shares,
interests, participations, rights or other equivalents (however designated) of
corporate stock, (iii) in the case of a partnership, partnership interests
(whether general or limited), (iv) in the case of a limited liability company or
similar entity, any membership or similar interests therein and (v) any other
interest or participation that confers on a Person the right to receive a share
of the profits and losses of, or distributions of assets of, the issuing Person.
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"CASH EQUIVALENTS" means (i) United States dollars, (ii) securities issued
or directly and fully guaranteed or insured by the United States government or
any agency or instrumentality thereof having maturities of not more than twelve
months from the date of acquisition, (iii) certificates of deposit and
eurodollar time deposits with maturities of twelve months or less from the date
of acquisition, bankers' acceptances with maturities not exceeding twelve months
and overnight bank deposits, in each case with any lender party to any of the
Credit Facilities or with any domestic commercial bank having capital and
surplus in excess of $500 million and a Thompson Bank Watch Rating of "B" or
better, (iv) repurchase obligations with a term of not more than seven days for
underlying securities of the types described in clauses (ii) and (iii) above
entered into with any financial institution meeting the qualifications specified
in clause (iii) above, (v) commercial paper having a rating of at least P1 from
Moody's Investors Service, Inc. (or its successor) and a rating of at least A1
from Standard & Poor's Rating Group (or its successor) and (vi) investments in
money market or other mutual funds substantially all of whose assets comprise
securities of types described in clauses (ii) through (v) above.
"CHANGE OF CONTROL" means the occurrence of any of the following:
(i) prior to the first public offering of Voting Stock of the Company,
either (x) Permitted Holders cease to be the "beneficial owner(s)" (as
defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or
indirectly, of more than 50% of the total voting power of the Voting Stock
of the Company, or (y) Permitted Holders cease to be entitled by voting
power, contract or otherwise to elect or cause the election of directors of
the Company having a majority of the total voting power of the Board or
Directors, in each case, whether as a result of issuance of securities of
the Company, any merger, consolidation, liquidation or dissolution of the
Company, any direct or indirect transfer of securities by any Permitted
Holder or otherwise (for purposes of this clause (i) and clause (ii) below,
Permitted Holders shall be deemed to beneficially own any Voting Stock of an
entity (the "specified entity") held by any other entity (the "parent
entity") so long as the Permitted Holders beneficially own, directly or
indirectly, a majority of the Voting Stock of the parent entity;
(ii) following the first public offering of Voting Stock of the Company,
any "Person" (as such term is used in Sections 13(d) and 14(d) of the
Exchange Act), other than one or more Permitted Holders, is or becomes the
beneficial owner (as defined in clause (i) above, except that a Person shall
be deemed to have "beneficial ownership" of all shares that any such Person
has the right to acquire within one year), directly or indirectly, of more
than 50% of the Voting Stock of the Company; PROVIDED that the Permitted
Holders beneficially own (as defined in clause (i) above), directly or
indirectly, in the aggregate a lesser percentage of the Voting Stock of the
Company than such other Person and do not have the right or ability by
voting power, contract or otherwise to elect or designate for election a
majority of the Board of Directors;
(iii) the sale, lease, transfer, conveyance or other disposition (other
than by way of merger or consolidation), in one or a series of related
transactions, of all or substantially all of the assets of the Company and
its Subsidiaries taken as a whole to any "Person" or group of related
Persons (a "Group"); (as such term is used in Sections 13(d) and 14(d) of
the Exchange Act);
(iv) the adoption of a plan relating to the liquidation or dissolution
of the Company; and
(v) during any period of two consecutive years, individuals who at the
beginning of such period constituted the Board of Directors (together with
any new directors whose election by such Board of Directors or whose
nomination for election by the shareholders of the Company was approved by a
vote of a majority of the directors of the Company then still in office who
were either directors at the beginning of such period or whose election or
nomination for election was previously so approved) cease for any reason to
constitute a majority of the Board of Directors then in office.
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"COMMISSION" means the Securities and Exchange Commission.
"CONSOLIDATED CASH FLOW" means, with respect to any Person for any period,
the Consolidated Net Income of such Person and its Restricted Subsidiaries for
such period increased by (i) an amount equal to any extraordinary or
non-recurring loss, and any net loss realized in connection with an Asset Sale
(together with any related provision for taxes) to the extent such losses were
included in computing such Consolidated Net Income, PLUS (ii) provision for
taxes based on income or profits of such Person and its Restricted Subsidiaries
for such period, to the extent that such provision for taxes was included in
computing such Consolidated Net Income, PLUS (iii) consolidated interest expense
of such Person and its Restricted Subsidiaries for such period, whether paid or
accrued (including, without limitation, amortization of original issue discount,
non-cash interest payments, the interest component of any deferred payment
obligations, the interest component of all payments associated with Capital
Lease Obligations, imputed interest with respect to Attributable Debt,
commissions, discounts and other fees and charges incurred in respect of letters
of credit or bankers' acceptance financings, and net payments (if any) pursuant
to Interest Rate Hedging Agreements), to the extent that any such expense was
included in computing such Consolidated Net Income, PLUS (iv) depreciation,
depletion and amortization expenses (including amortization of goodwill and
other intangibles) for such Person and its Restricted Subsidiaries for such
period to the extent that such depreciation, depletion and amortization expenses
were included in computing such Consolidated Net Income, PLUS (v) exploration
expenses for such Person and its Restricted Subsidiaries for such period to the
extent such exploration expenses were included in computing such Consolidated
Net Income, PLUS (vi) costs incurred in connection with acquisitions that would
be eligible for capitalization treatment under GAAP, but have been expensed at
the time of incurrence, PLUS (vii) other non-cash charges (excluding any such
non-cash charge to the extent that it represents an accrual of or reserve for
cash charges in any future period or amortization of a prepaid cash expense that
was paid in a prior period) of such Person and its Restricted Subsidiaries for
such period, including, without limitation, any ceiling limitation writedowns
and non-cash losses or charges to net income resulting from the net change in
value of such Person's mark-to-market portfolio of Oil and Gas Commodity Price
Risk Management Contracts, to the extent that such other non-cash charges were
included in computing such Consolidated Net Income, in each case, on a
consolidated basis and determined in accordance with GAAP. Notwithstanding the
foregoing, the provision for taxes on the income or profits of, and the
depreciation, depletion and amortization and other non-cash charges and expenses
of, a Restricted Subsidiary of the relevant Person shall be added to
Consolidated Net Income to compute Consolidated Cash Flow only to the extent
(and in the same proportion) that the Net Income of such Restricted Subsidiary
was included in calculating the Consolidated Net Income of such Person and only
if a corresponding amount would be permitted at the date of determination to be
dividended to such Person by such Restricted Subsidiary without prior
governmental approval (that has not been obtained), and without direct or
indirect restriction pursuant to the terms of its charter and all agreements,
instruments, judgments, decrees, orders, statutes, rules and governmental
regulations applicable to that Restricted Subsidiary or its stockholders.
"CONSOLIDATED NET INCOME" means, with respect to any Person for any period,
the aggregate of the Net Income of such Person and its Restricted Subsidiaries
for such period, on a consolidated basis, determined in accordance with GAAP;
PROVIDED that (i) the Net Income (but not loss) of any Person that is not a
Restricted Subsidiary or that is accounted for by the equity method of
accounting shall be included only to the extent of the amount of dividends or
distributions paid in cash to the referent Person or a Wholly Owned Restricted
Subsidiary thereof, (ii) the Net Income of any Restricted Subsidiary shall be
excluded to the extent that the declaration or payment of dividends or similar
distributions by that Restricted Subsidiary of that Net Income is not at the
date of determination permitted without any prior governmental approval (that
has not been obtained) or, directly or indirectly, by operation of the terms of
its charter or any agreement, instrument, judgment, decree, order, statute, rule
or governmental regulation applicable to that Restricted Subsidiary or its
stockholders, (iii) the Net Income of any Person acquired in a pooling of
interests transaction for any period prior to the date of such acquisition shall
be excluded and (iv) the cumulative effect of a change in accounting principles
shall be excluded; provided, however, that for
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purposes of a determination pursuant to the provisions of the covenant described
above under the caption "--Certain Covenants--Restricted Payments", there will
be deducted from the Net Income of the Company and its Restricted Subsidiaries
for such period an amount equal to payments, distributions and dividends paid by
the Company pursuant to clause (7) of the second paragraph of such covenant.
"CONSOLIDATED NET WORTH" means the total of the amounts shown on the balance
sheet of the Company and its consolidated Restricted Subsidiaries, determined on
a consolidated basis in accordance with GAAP, as of the end of the most recent
fiscal quarter of the Company ending prior to the taking of any action for the
purpose of which the determination is being made and for which financial
statements are available (but in no event ending more than 135 days prior to the
taking of such action), as (i) the par or stated value of all outstanding
Capital Stock of the Company, plus (ii) paid-in capital or capital surplus
relating to such Capital Stock plus (iii) any retained earnings or earned
surplus less (A) any accumulated deficit (in each case excluding any minority
interest) and (B) any amounts attributable to Disqualified Stock.
"CREDIT FACILITY" means that certain Credit Agreement, dated as of May 14,
1998, among the Company, Bank One, Oklahoma, N.A., as Agent and lender and the
other parties thereto, including any related notes, guarantees, security or
pledge agreements, collateral documents, instruments and agreements executed by
the Company or any Subsidiary of the Company in connection therewith, and in
each case as amended, restated, modified, renewed, increased, supplemented,
refunded, replaced or refinanced, in whole or in part, from time to time,
whether or not with the same or other lenders or agents and whether provided
under the original Credit Facility or any other credit agreement or indenture.
"CREDIT FACILITIES" means, with respect to the Company, one or more debt
facilities (including, without limitation, the Credit Facility) or commercial
paper facilities with banks or other institutional lenders providing for
revolving credit loans, term loans, production payments, receivables financing
(including through the sale of receivables to such lenders or to special purpose
entities formed to borrow from such lenders against such receivables) or letters
of credit, in each case, as amended, restated, modified, renewed, increased,
supplemented, refunded, replaced or refinanced in whole or in part from time to
time. Indebtedness under Credit Facilities outstanding on the date on which the
Notes are first issued and authenticated under the Indenture (after giving
effect to the use of proceeds thereof) shall be deemed to have been incurred on
such date in reliance on the exception provided by clause (b) of the definition
of Permitted Indebtedness.
"DEFAULT" means any event that is or with the passage of time or the giving
of notice or both would be an Event of Default.
"DESIGNATED SENIOR DEBT" means (i) the Credit Facility and (ii) any other
Senior Debt permitted under the Indenture which, at the date of determination,
has an aggregate principal amount outstanding of, or under which, at the date of
determination, the holders thereof are committed to lend up to, at least $10
million and is specifically designated by the Company in the instrument
evidencing or governing such Senior Debt as "Designated Senior Debt" for
purposes of the Indenture.
"DISQUALIFIED STOCK" means any Capital Stock that, by its terms (or by the
terms of any security into which it is convertible or for which it is
exchangeable) or upon the happening of any event, matures or is mandatorily
redeemable, pursuant to a sinking fund obligation or otherwise, is convertible
or is exchangeable for Indebtedness or Disqualified Stock or redeemable at the
option of the holder thereof, in whole or in part, in each case on or prior to
the date that is 91 days after (x) the date on which the Notes mature or (y) the
date on which there are no Notes outstanding.
"EQUITY INTERESTS" means Capital Stock and all warrants, options or other
rights to acquire Capital Stock (but excluding any debt security that is
convertible into, or exchangeable for, Capital Stock).
"FIXED CHARGES" means, with respect to any Person for any period, the sum,
without duplication, of (i) the consolidated interest expense of such Person and
its Restricted Subsidiaries for such period, whether paid or accrued (including,
without limitation, amortization of original issue discount, non-cash
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interest payments, the interest component of any deferred payment obligations,
the interest component of all payments associated with Capital Lease
Obligations, imputed interest with respect to Attributable Debt, commissions,
discounts and other fees and charges incurred in respect of letter of credit or
bankers' acceptance financings, and net payments (if any) pursuant to Interest
Rate Hedging Agreements), (ii) the consolidated interest expense of such Person
and its Restricted Subsidiaries that was capitalized during such period, (iii)
any interest expense on Indebtedness of another Person that is guaranteed by
such Person or any of its Restricted Subsidiaries or secured by a Lien on assets
of such Person or any of its Restricted Subsidiaries (whether or not such
guarantee or Lien is called upon) and (iv) the product of (a) all cash dividend
payments (and non-cash dividend payments in the case of a Person that is a
Restricted Subsidiary, unless paid in Equity Interests that are not Disqualified
Stock) on any series of preferred stock of such Person or any of its Restricted
Subsidiaries, times (b) a fraction, the numerator of which is one and the
denominator of which is one minus the then current combined federal, state and
local statutory tax rate of such Person, expressed as a decimal, in each case,
on a consolidated basis and in accordance with GAAP. When calculating the amount
of Fixed Charges, any interest expense attributable to any Person shall be
included in such calculation to the same extent the Net Income of such Person
was included in the calculation of Consolidated Net Income in connection with
calculating the Fixed Charge Coverage Ratio.
"FIXED CHARGE COVERAGE RATIO" means with respect to any Person for any
period, the ratio of the Consolidated Cash Flow of such Person for such period
to the Fixed Charges of such Person for such period. In the event that the
Company or any of its Restricted Subsidiaries incurs, assumes, guarantees or
redeems any Indebtedness (other than revolving credit borrowings) or issues or
redeems preferred stock subsequent to the commencement of the period for which
the Fixed Charge Coverage Ratio is being calculated but prior to the date on
which the calculation of the Fixed Charge Coverage Ratio is made (the
"Calculation Date"), then the Fixed Charge Coverage Ratio shall be calculated
giving pro forma effect to such incurrence, assumption, guarantee or redemption
of Indebtedness, or such issuance or redemption of preferred stock, as if the
same had occurred at the beginning of the applicable four-quarter reference
period. In addition, for purposes of making the computation referred to above,
(i) acquisitions that have been made by the referent Person or any of its
Restricted Subsidiaries, including through mergers or consolidations and
including any related financing transactions, during the four-quarter reference
period or subsequent to such reference period and on or prior to the Calculation
Date (including, without limitation, any acquisition to occur on the Calculation
Date) shall be deemed to have occurred on the first day of the four-quarter
reference period and any cost savings or expense reductions attributable at the
time of such computation or to be attributable in the future to such
acquisition, shall be included in such computation, to the extent that such
adjustments would be permitted under Article 11 of Regulation S-X and
Consolidated Cash Flow for such reference period shall be calculated without
giving effect to clause (iii) of the proviso set forth in the definition of
Consolidated Net Income, (ii) the net proceeds of Indebtedness incurred or
Disqualified Stock issued by the referent Person pursuant to the first paragraph
of the covenant described under the caption "Certain Covenants--Incurrence of
Indebtedness and Issuance of Disqualified Stock" during the four-quarter
reference period or subsequent to such reference period and on or prior to the
Calculation Date shall be deemed to have been received by the referent Person or
any of its Restricted Subsidiaries on the first day of the four-quarter
reference period and applied to its intended use on such date, (iii) the
Consolidated Cash Flow attributable to discontinued operations, as determined in
accordance with GAAP, and operations or businesses disposed of prior to the
Calculation Date, shall be excluded, and (iv) the Fixed Charges attributable to
discontinued operations, as determined in accordance with GAAP, and operations
or businesses disposed of prior to the Calculation Date, shall be excluded, but
only to the extent that the obligations giving rise to such Fixed Charges will
not be obligations of the referent Person or any of its Restricted Subsidiaries
following the Calculation Date.
"GAAP" means generally accepted accounting principles set forth in the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants and statements and pronouncements of
the Financial Accounting Standards Board or in such other statements
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by such other entity as have been approved by a significant segment of the
accounting profession, which are in effect on the Issuance Date.
"GUARANTEE" means a guarantee (other than by endorsement of negotiable
instruments for collection in the ordinary course of business), direct or
indirect, in any manner (including, without limitation, letters of credit and
reimbursement agreements in respect thereof), of all or any part of any
Indebtedness.
"GUARANTOR SENIOR DEBT" means any Indebtedness of a Subsidiary Guarantor
permitted to be incurred under the terms of the Indenture, unless the instrument
under which such Indebtedness is incurred expressly provides that it is on a
parity with or subordinated in right of payment to the Subsidiary Guarantee of
such Subsidiary Guarantor, including interest accruing subsequent to the filing
of, or which would have accrued but for the filing of, a petition of bankruptcy,
whether or not such interest is an allowable claim in such bankruptcy
proceeding. Notwithstanding anything to the contrary in the foregoing sentence,
Guarantor Senior Debt will not include (a) any liability for federal, state,
local or other taxes owed or owing by any Subsidiary Guarantor, (b) any
obligation of a Subsidiary Guarantor to the Company or to any other Restricted
Subsidiary of the Company, (c) any accounts payable or trade liabilities of a
Subsidiary Guarantor arising in the ordinary course of business (including
instruments evidencing such liabilities), (d) any Indebtedness of a Subsidiary
Guarantor that is incurred in violation of the Indenture, (e) Indebtedness of a
Subsidiary Guarantor which, when incurred and without respect to any election
under Section 1111(b) of Title 11, United States Code, is without recourse to
such Subsidiary Guarantor, and (f) Indebtedness evidenced by a Subsidiary
Guarantee.
"INDEBTEDNESS" means, with respect to any Person, without duplication, (a)
any indebtedness of such Person, whether or not contingent, (i) in respect of
borrowed money, (ii) evidenced by bonds, notes, debentures or similar
instruments, (iii) evidenced by letters of credit (or reimbursement agreements
in respect thereof) or banker's acceptances, (iv) representing Capital Lease
Obligations, (v) representing the balance deferred and unpaid of the purchase
price of any property, except any such balance that constitutes an accrued
expense or trade payable, (vi) representing any obligations in respect of
Interest Rate Hedging Agreements or Oil and Gas Hedging Contracts, and (vii) in
respect of any production payment, (b) all indebtedness of others secured by a
Lien on any asset of such Person (whether or not such indebtedness is assumed by
such Person), (c) obligations of such Person in respect of production
imbalances, (d) Acquired Debt of such Person, (e) Attributable Debt of such
Person, and (f) to the extent not otherwise included in the foregoing, the
guarantee by such Person of any Indebtedness of any other Person.
The amount of Indebtedness of any Person at any date will be the outstanding
balance at such date of all unconditional obligations as described above and the
maximum liability, on the occurrence of the contingency giving rise to the
obligation, of any contingent obligations described above. The amount of
Indebtedness at any date in respect of (i) Credit Facilities shall be the
outstanding principal amount thereof at such date plus any outstanding letters
of credit (or reimbursement obligations in respect thereof) issued thereunder at
such date and (ii) Interest Rate Hedging Agreements or Oil and Gas Hedging
Contracts at such date shall be an amount equal to the net termination value of
such agreement or arrangement giving rise to such obligation that would be
payable at such time.
"INTEREST RATE HEDGING AGREEMENTS" means, with respect to any Person, the
obligations of such Person under (i) interest rate swap agreements, interest
rate cap agreements and interest rate collar agreements and (ii) other
agreements or arrangements designed to protect such Person against fluctuations
in interest rates.
"INVESTMENTS" means, with respect to any Person, all investments by such
Person in other Persons (including Affiliates) in the forms of direct or
indirect loans (including guarantees of Indebtedness or other obligations but
excluding trade credit and other ordinary course advances customarily made in
the Oil and Gas Business), advances (excluding commission, travel and similar
advances to officers and employees made in the ordinary course of business),
capital contributions, purchases or other acquisitions for
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consideration of Indebtedness, Equity Interests or other securities, together
with all items that are or would be classified as investments on a balance sheet
prepared in accordance with GAAP; PROVIDED that the following shall not
constitute Investments: (i) an acquisition of assets, Equity Interests or other
securities by the Company for consideration consisting of common equity
securities of the Company, (ii) Interest Rate Hedging Agreements entered into in
accordance with the limitations set forth in clause (g) of the second paragraph
of the covenant described under the caption "--Certain Covenants-- Incurrence of
Indebtedness and Issuance of Disqualified Stock," (iii) Oil and Gas Hedging
Agreements entered into in accordance with the limitations set forth in clause
(h) of the second paragraph of the covenant described under the caption
"--Certain Covenants--Incurrence of Indebtedness and Issuance of Disqualified
Stock", (iv) endorsements of negotiable instruments and documents in the
ordinary course of
business, (v) extensions of trade credit on commercially reasonable terms in
accordance with normal trade practices, and (vi) Cash Equivalents, bonds, notes,
debentures or other securities received in compliance with covenants described
under the caption "--Repurchase at the Option of Holders--Asset Sales." If the
Company or any Restricted Subsidiary of the Company sells or otherwise disposes
of any Equity Interests of any direct or indirect Restricted Subsidiary of the
Company such that, after giving effect to any such sale or disposition, such
entity is no longer a Subsidiary of the Company, the Company shall be deemed to
have made an Investment on the date of any such sale or disposition equal to the
fair market value of the Equity Interests of such Subsidiary not sold or
disposed of.
"LIEN" means, with respect to any asset, any mortgage, lien, pledge, charge,
security interest or encumbrance of any kind in respect of such asset, whether
or not filed, recorded or otherwise perfected under applicable law (including
any conditional sale or other title retention agreement, any lease in the nature
thereof, any option or other agreement to sell or give a security interest in
and any filing of or agreement to give any financing statement under the Uniform
Commercial Code (or equivalent statutes) of any jurisdiction).
"NET INCOME" means, with respect to any Person, the net income (loss) of
such Person, determined in accordance with GAAP and before any reduction in
respect of preferred stock dividends, excluding, however, (i) any gain or loss,
together with any related provision for taxes on such gain or loss, realized in
connection with (a) any Asset Sale (including, without limitation, dispositions
pursuant to sale and leaseback transactions) or (b) the disposition of any
securities by such Person or any of its Restricted Subsidiaries or the
extinguishment of any Indebtedness of such Person or any of its Restricted
Subsidiaries and (ii) any extraordinary or nonrecurring gain or loss, together
with any related provision for taxes on such extraordinary or nonrecurring gain
or loss.
"NET PROCEEDS" means the aggregate cash proceeds received by the Company or
any of its Restricted Subsidiaries in respect of any Asset Sale (including,
without limitation, any cash received upon the sale or other disposition of any
non-cash consideration received in any Asset Sale, but excluding cash amounts
placed in escrow, until such amounts are released to the Company), net of the
direct costs relating to such Asset Sale (including, without limitation, legal,
accounting, investment banking and other professional fees and expenses, and
sales commissions) and any relocation expenses incurred as a result thereof,
taxes paid or payable as a result thereof (after taking into account any
available tax credits or deductions and any tax sharing arrangements), amounts
required to be applied to the repayment of Indebtedness (other than Indebtedness
under any Senior Debt) secured by a Lien on the asset or assets that were the
subject of such Asset Sale and any reserve for adjustment in respect of the sale
price of such asset or assets established in accordance with GAAP and any
reserve established for future liabilities.
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"NON-RECOURSE DEBT" means Indebtedness (i) as to which neither the Company
nor any of its Restricted Subsidiaries (a) provides any guarantee or credit
support of any kind (including any undertaking, guarantee, indemnity, agreement
or instrument that would constitute Indebtedness), or (b) is directly or
indirectly liable (as guarantor or otherwise); and (ii) no default with respect
to which (including any rights that the holders thereof may have to take
enforcement action against an Unrestricted Subsidiary) would permit (upon
notice, lapse of time, or both) any holder of any other Indebtedness of the
Company or any of its Restricted Subsidiaries to declare a default on such other
Indebtedness or cause the payment thereof to be accelerated or payable prior to
its stated maturity; and (iii) the explicit terms of which provide that there is
no recourse against any of the assets of the Company or its Restricted
Subsidiaries.
"OBLIGATIONS" means any principal, interest, penalties, fees,
indemnifications, reimbursements, damages and other liabilities payable under
the documentation governing any Indebtedness.
"OIL AND GAS BUSINESS" means (i) the acquisition, exploration, exploitation,
development, operation and disposition of interests in oil, gas and other
hydrocarbon properties, (ii) the gathering, marketing, distribution, treating,
processing, storage, selling and transporting of any production from such
interests or properties of the Company and its Subsidiaries and the marketing of
oil and gas obtained from unrelated Persons, (iii) any business relating to
exploration for or development, production, treatment, processing, storage,
transportation, gathering or marketing of oil, gas and other minerals and
products produced in association therewith, (iv) any business relating to
oilfield sales and service and (v) any activity that is ancillary to or
necessary or appropriate for the activities described in clauses (i) through
(iv) of this definition.
"OIL AND GAS HEDGING CONTRACTS" means any oil and gas purchase or commodity
price risk management hedging agreement, and other agreement or arrangement,
entered into in the ordinary course of business, in each case, that is designed
to provide protection against oil and gas price fluctuations.
"PARI PASSU INDEBTEDNESS" means Indebtedness that ranks PARI PASSU in right
of payment to the Notes.
"PERMITTED HOLDERS" means (i) any stockholder of the Company on the Issue
Date; (ii) family members or relatives of the persons described in clause (i);
(iii) any trusts created for the benefit of the persons described in clauses (i)
or (ii); (iv) in the event of the incompetence or death of any of the persons
described in clauses (i) or (ii), such person's estate, executor, administrator,
committee or other personal representatives or beneficiaries; and (v) any
Permitted Holder Subsidiary.
"PERMITTED HOLDER SUBSIDIARY" means, with respect to any Permitted Holder,
(i) any corporation more than 50% of the outstanding voting stock of which is
owned, directly or indirectly, by one or more Permitted Holders, or by one or
more other Permitted Holder Subsidiaries of such Permitted Holders, or by one or
more Permitted Holders and one or more other Permitted Holder Subsidiaries of
such Permitted Holders, (ii) any general partnership, limited liability company,
joint venture or similar entity more than 50% of the outstanding partnership,
membership or similar interest of which is owned directly or indirectly, by one
or more Permitted Holders, or by one or more other Permitted Holder Subsidiaries
of such Permitted Holders, or by one or more Permitted Holders and one or more
other Permitted Holder Subsidiaries of such Permitted Holders and (iii) any
limited partnership of which one or more Permitted Holders or any Permitted
Holder Subsidiary of such Permitted Holders is a general partner.
"PERMITTED INDEBTEDNESS" has the meaning given in the covenant described
under the caption "--Certain Covenants--Incurrence of Indebtedness and Issuance
of Disqualified Stock."
"PERMITTED INVESTMENTS" means (a) any Investment in the Company or in a
Restricted Subsidiary of the Company; (b) any Investment in Cash Equivalents;
(c) any Investment by the Company or any Restricted Subsidiary of the Company in
a Person if, as a result of such Investment and any related transactions that at
the time of such Investment are contractually mandated to occur, (i) such Person
becomes a Restricted Subsidiary of the Company or (ii) such Person is merged,
consolidated or amalgamated with or into, or transfers or conveys all or
substantially all of its assets to, or is liquidated into, the Company or a
Restricted
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Subsidiary of the Company; (d) any Investment made as a result of the receipt of
non-cash portion of the Cash Consideration from an Asset Sale that was made
pursuant to and in compliance with the covenant described above under the
caption "--Repurchase at the Option of Holders--Asset Sales" or not constituting
an Asset Sale by reason of the 5 million threshold contained in the definition
thereof; (e) any Investment by the Company in any Person engaged in the Oil and
Gas Business or assets used in the Oil and Gas Business in exchange for Equity
Interests in the Company (other than Disqualified Stock), (f) shares of Capital
Stock received in connection with any good faith settlement of a bankruptcy
proceeding involving a trade creditor, (g) Interest Rate Hedging Agreements or
Oil and Gas Hedging Contracts; (h) loans and advances to employees in the
ordinary course of business for bona fide business purposes; (i) operating
agreements, joint ventures, partnership agreements, working interests, royalty
interests, mineral leases, processing agreements, farm-out or farm-in
agreements, contracts for the sale, transportation or exchange of oil and
natural gas, unitization agreements, pooling arrangements, area of mutual
interest agreements, production sharing agreements or other similar or customary
agreements, transactions, properties, interests or arrangements, and Investments
and expenditures in connection therewith or pursuant thereto, in each case made
or entered into in the ordinary course of the Oil and Gas Business, excluding
however, Investments in corporations other than any Investment received pursuant
to the Asset Sale provision; and (j) any other Investments in any Person or
Persons not otherwise permitted to be made pursuant to clauses (a)-(i) above,
when taken together with all other Investments made pursuant to this clause (j)
that are at the time outstanding, having an aggregate amount (such amount to be
calculated on a cost basis) not to exceed the greater of (i) $15 million and
(ii) 5% of Total Assets, as calculated at the time of such Investment.
"PERMITTED LIENS" means
(i) Liens securing Indebtedness of a Subsidiary or Liens securing Senior
Debt that is outstanding on the date of issuance of the Notes and Liens
securing Senior Debt that is permitted by the terms of the Indenture to be
incurred;
(ii) Liens in favor of the Company or any Restricted Subsidiary;
(iii) Liens on property existing at the time of acquisition thereof by
the Company or any Subsidiary of the Company and Liens on property or assets
of a Subsidiary existing at the time it became a Subsidiary, provided that
such Lien was not created in contemplation of the acquisition of the
property, and provided further that no such Lien shall extend to any assets
other than the acquired property or the property of the acquired Subsidiary;
(iv) Liens incurred on deposits made in the ordinary course of business
in connection with workers' compensation, unemployment insurance or other
kinds of social security, or to secure the payment or performance of
tenders, statutory or regulatory obligations, surety or appeal bonds,
performance bonds or other obligations of a like nature incurred in the
ordinary course of business (including lessee or operator obligations under
statutes, governmental regulations or instruments related to the ownership,
exploration and production of oil, gas and minerals on state or federal
lands or waters);
(v) Liens existing on the date of the Indenture;
(vi) Liens for taxes, assessments or governmental charges or claims that
are not yet delinquent or that are being contested in good faith by
appropriate proceedings promptly instituted and diligently concluded,
PROVIDED that any reserve or other appropriate provision as shall be
required in conformity with GAAP shall have been made therefor;
(vii) statutory liens of landlords, mechanics, suppliers, vendors,
warehousemen, carriers or other like Liens arising in the ordinary course of
business;
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(viii) judgment Liens not giving rise to an Event of Default so long as
any appropriate legal proceeding that may have been duly initiated for the
review of such judgment shall not have been finally terminated or the period
within which such proceeding may be initiated shall not have expired;
(ix) Liens on, or related to, properties or assets to secure all or part
of the costs incurred in the ordinary course of the Oil and Gas Business for
the exploration, exploitation, drilling, development, production, gathering,
processing, transportation, marketing, storage or operation thereof;
(x) Liens on pipeline or pipeline facilities that arise under operation
of law;
(xi) Liens arising under operating agreements, joint venture agreements,
partnership agreements, oil and gas leases, farm-out or farm-in agreements,
division orders, contracts for the sale, transportation or exchange of oil
or natural gas, unitization and pooling declarations and agreements, area of
mutual interest agreements and other agreements that are customary in the
Oil and Gas Business;
(xii) Liens reserved in oil and gas mineral leases for bonus or rental
payments and for compliance with the terms of such leases;
(xiii) Liens securing the Notes;
(xiv) Liens constituting survey exceptions, encumbrances, easements, and
reservations of, and rights to others for, rights-of-way, zoning and other
restrictions as to the use of real properties, and minor defects of title
which, in the case of any of the foregoing, do not secure the payment of
borrowed money, and in the aggregate do not materially adversely affect the
value of the assets of the Company and its Restricted Subsidiaries, taken as
a whole, or materially impair the use of such properties for the purposes
for which such properties are held by the Company or such subsidiaries;
(xv) any interest or title of a lessor under any Capital Lease Obligation
or operating lease;
(xvi) Liens resulting from the deposit of funds or evidences of
Indebtedness in trust for the purpose of defeasing Indebtedness of the
Company or any of the Restricted Subsidiaries;
(xvii) Liens securing obligations under Interest Rate Hedging Agreements
or Oil and Gas Commodity Price Risk Management Contracts;
(xviii) Liens upon specific items of inventory or other goods and proceeds
of the Company or any Restricted Subsidiary securing the Company's or such
Restricted Subsidiary's, as the case may be, obligations in respect of
bankers' acceptances issued or created for the account of the Company or
such Restricted Subsidiary, as the case may be, to facilitate the purchase,
shipment or storage of such inventory or other goods;
(xix) Liens securing reimbursement obligations with respect to commercial
letters of credit which encumber documents and other property relating to
such letters of credit and products and proceeds thereof;
(xx) Liens encumbering property or assets under construction arising from
progress or partial payments by a customer of the Company or its Restricted
Subsidiaries relating to such property or assets;
(xxi) Liens encumbering deposits made to secure Obligations arising from
statutory, regulatory, contractual or warranty requirements of the Company
or any of its Restricted Subsidiaries, including rights of offset and
set-off;
(xxii) Liens securing Purchase Money Debt; provided however that the
related Purchase Money Debt shall not be secured by any property or assets
of the Company or any Restricted Subsidiary other than the property and
assets acquired by the Company with the proceeds of such Purchase Money
Debt;
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(xxiii) Liens on the Capital Stock of Unrestricted Subsidiaries;
(xxiv) Liens to secure any Permitted Refinancing Debt, provided that the
Indebtedness so exchanged, extended, refinanced, renewed, replaced, defeased
or refunded was secured by Liens permitted pursuant to clause (iii) or (v)
of this definition, provided however, that (a) such new Liens shall be
limited to all or part of the same property that secured the original Lien,
plus improvements on the property and (b) the Permitted Refinancing Debt
secured by such Lien at such time is not increased to any amount greater
than the sum of (x) the outstanding principal amount or, if greater, the
committed amount of the Indebtedness secured by Liens described under clause
(iii) or (v) of this definition at the time the original Lien became a Lien
permitted in accordance with the Indenture and (y) an amount necessary to
pay any fees and expenses, including premiums, related to such exchange,
extension, refinancing, renewal, replacement, defeasement or refunding;
(xxv) Liens securing Attributable Debt under any sale and leaseback
transaction permitted by the terms of the Indenture, but only on the
property subject to such sale and leaseback transaction; and
(xxvi) Liens not otherwise permitted by clauses (i) through (xxv) that are
incurred in the ordinary course of business of the Company or any Subsidiary
with respect to obligations that do not exceed $5 million at any one time
outstanding.
"PERMITTED REFINANCING DEBT" means any Indebtedness of the Company or any of
its Restricted Subsidiaries issued in exchange for, or the net proceeds of which
are used to extend, refinance, renew, replace, defease or refund other
Indebtedness (other than Indebtedness incurred under a Credit Facility) of the
Company or any of its Restricted Subsidiaries; PROVIDED that: (i) the principal
amount of such Permitted Refinancing Debt does not exceed the principal amount
of the Indebtedness so extended, refinanced, renewed, replaced, defeased or
refunded (plus the amount of reasonable expenses incurred in connection
therewith (other than increases resulting from the capitalization of interest or
fees)); (ii) such Permitted Refinancing Debt has a final maturity date on or
later than the final maturity date of, and has a Weighted Average Life to
Maturity equal to or greater than the Weighted Average Life to Maturity of, the
Indebtedness being extended, refinanced, renewed, replaced, defeased or
refunded; (iii) if the Indebtedness being extended, refinanced, renewed,
replaced, defeased or refunded is subordinated in right of payment to the Notes
or the Subsidiary Guarantees, as the case may be, such Permitted Refinancing
Debt has a final maturity date later than the final maturity date of, and is
subordinated in right of payment to, the Notes or the Subsidiary Guarantees, as
the case may be, on terms at least as favorable taken as a whole to the Holders
of the Notes, or the Subsidiary Guarantees, as the case may be, as those
contained in the documentation governing the Indebtedness being extended,
refinanced, renewed, replaced, defeased or refunded; and (iv) such Indebtedness
is incurred either by the Company or by the Restricted Subsidiary who is the
obligor on the Indebtedness being extended, refinanced, renewed, replaced,
defeased or refunded.
"PERSON" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization, government
or any agency or political subdivision thereof or any other entity.
"PURCHASE MONEY DEBT" means Indebtedness incurred in connection with the
purchase by the Company or any of its Subsidiaries of any equipment, real or
personal property, or any other asset, other than Equity Interests of any Person
(i) as to which the obligee expressly waives the provisions of Section 1111 (b)
of Title 11, United States Code; (ii) as to which neither the Company nor any of
its Restricted Subsidiaries (a) provides any guarantee or credit support of any
kind (including any undertaking, guarantee, indemnity, agreement or instrument
that would constitute Indebtedness), or (b) is directly or indirectly liable (as
guarantor or otherwise) other than the pledge of the equipment, real or personal
property or other assets acquired with the proceeds of such Indebtedness; (iii)
no default with respect to which (including any rights that the holders thereof
may have to take enforcement actions against an Unrestricted Subsidiary) would
permit (upon notice, lapse of time, or both) any holder of any other
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Indebtedness of the Company or any of its Restricted Subsidiaries to declare a
default on such other Indebtedness or cause the payment thereof to be
accelerated or payable prior to its stated maturity; and (iv) the explicit terms
of which provide that there is no recourse against any of the assets of the
Company or its Restricted Subsidiaries, other than recourse against the
equipment, real or personal property or other assets acquired with the proceeds
of such Indebtedness.
"RESTRICTED INVESTMENT" means an Investment other than a Permitted
Investment.
"RESTRICTED SUBSIDIARY" means any direct or indirect Subsidiary of the
Company that is not an Unrestricted Subsidiary.
"SENIOR DEBT" means (i) Indebtedness of the Company or any Subsidiary of the
Company under or in respect of any Credit Facility, whether for principal,
interest (including interest accruing after the filing of a petition initiating
any proceeding pursuant to any bankruptcy law, whether or not the claim for such
interest is allowed as a claim in such proceeding), reimbursement obligations,
fees, commissions, expenses, indemnities or other amounts, and (ii) any other
Indebtedness permitted under the terms of the Indenture, unless the instrument
under which such Indebtedness is incurred expressly provides that it is on a
parity with or subordinated in right of payment to the Notes. Notwithstanding
anything to the contrary in the foregoing sentence, Senior Debt will not include
(w) any liability for federal, state, local or other taxes owed or owing by the
Company, (x) any Indebtedness of the Company to any of its Subsidiaries or other
Affiliates, (y) any trade payables or (z) any Indebtedness that is incurred in
violation of the Indenture (other than Indebtedness under (i) the Credit
Facility or (ii) any other Credit Facility that is incurred on the basis of a
representation by the Company to the applicable lenders that it is permitted to
incur such Indebtedness under the Indenture).
"SUBSIDIARY" means, with respect to any Person, (i) any corporation,
association or other business entity of which more than 50% of the total voting
power of shares of Capital Stock, entitled (without regard to the occurrence of
any contingency) to vote in the election of directors, managers or trustees
thereof is at the time owned or controlled, directly or indirectly, by such
Person or one or more of the other Subsidiaries of that Person (or a combination
thereof) and (ii) any partnership (a) the sole general partner or the managing
general partner of which is such Person or a Subsidiary of such Person or (b)
the only general partners of which are such Person or one or more Subsidiaries
of such Person (or any combination thereof).
"SUBSIDIARY GUARANTEE" means any guarantee of any Subsidiary of the Company
under the Indenture and the Notes in accordance with the provisions of the
Indenture.
"SUBSIDIARY GUARANTORS" means each Restricted Subsidiary of the Company
existing on the date of the Indenture (such Subsidiaries being Continental Gas,
Inc. and Continental Crude Co.), and any future Restricted Subsidiary of the
Company that executes a Subsidiary Guarantee in accordance with the provisions
of the Indenture, and, in each case, their respective successors and assigns.
"TOTAL ASSETS" means, with respect to any Person, the total consolidated
assets of such Person and its Restricted Subsidiaries, as shown on the most
recent balance sheet of such Person.
"TREASURY RATE" means the yield to maturity at the time of computation of
United States Treasury securities with a constant maturity (as compiled and
published in the most recent Federal Reserve Statistical Release H.15(519) which
has become publicly available at least two Business Days prior to the redemption
date (or, if such Statistical Release is no longer published, any publicly
available source or similar market data)) most nearly equal to the period from
the redemption date to August 1, 2003; PROVIDED that if the period from the
redemption date to August 1, 2003 is not equal to the constant maturity of a
United States Treasury security for which a weekly average yield is given, the
Treasury Rate shall be obtained by linear interpolation (calculated to the
nearest one-twelfth of a year) from the weekly average yields of United States
Treasury securities for which such yields are given, except that if the period
from
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the redemption date to August 1, 2003 is less than one year, the weekly average
yield on actually traded United States Treasury securities adjusted to a
constant maturity of one year shall be used.
"UNRESTRICTED SUBSIDIARY" means (i) any Subsidiary of the Company which at
the time of determination shall be an Unrestricted Subsidiary (as designated by
the Board of Directors of the Company, as provided below) and (ii) any
Subsidiary of an Unrestricted Subsidiary. The Board of Directors of the Company
may designate any Subsidiary of the Company (including any newly acquired or
newly formed Subsidiary or a Person becoming a Subsidiary through merger or
consolidation or Investment therein) to be an Unrestricted Subsidiary only if
(a) such Subsidiary does not own any Capital Stock of, or own or hold any Lien
on any property of, any other Subsidiary of the Company which is not a
Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted
Subsidiary; (b) all the Indebtedness of such Subsidiary shall, at the date of
designation, and will at all times thereafter, consist of Non-Recourse Debt; (c)
the Company certifies that such designation complies with the limitations of the
"Restricted Payments" covenant; (d) such Subsidiary, either alone or in the
aggregate with all other Unrestricted Subsidiaries, does not operate, directly
or indirectly, all or substantially all of the business of the Company and its
Subsidiaries; (e) such Subsidiary does not, directly or indirectly, own any
Indebtedness of or Equity Interest in, and has no investments in, the Company or
any Restricted Subsidiary; (f) such Subsidiary is a Person with respect to which
neither the Company nor any of its Restricted Subsidiaries has any direct or
indirect obligation to maintain or preserve such Person's financial condition or
to cause such Person to achieve any specified levels of operating results; and
(g) on the date such Subsidiary is designated an Unrestricted Subsidiary, such
Subsidiary is not a party to any agreement, contract, arrangement or
understanding with the Company or any Restricted Subsidiary with terms
substantially less favorable to the Company or such Restricted Subsidiary than
those that might have been obtained from Persons who are not Affiliates of the
Company. Any such designation by the Board of Directors of the Company shall be
evidenced to the Trustee by filing with the Trustee a resolution of the Board of
Directors of the Company giving effect to such designation and an Officers'
Certificate certifying that such designation complied with the foregoing
conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the
foregoing requirements as an Unrestricted Subsidiary, if shall thereafter cease
to be an Unrestricted Subsidiary for purposes of the Indenture and any
Indebtedness of such Subsidiary shall be deemed to be incurred as of such date.
The Board of Directors of the Company may designate any Unrestricted Subsidiary
to be a Restricted Subsidiary; PROVIDED, that (i) immediately after giving
effect to such designation, no Default or Event of Default shall have occurred
and be continuing or would occur as a consequence thereof and the Company could
incur at least $1.00 of additional Indebtedness (excluding Permitted
Indebtedness) pursuant to the first paragraph of the "Incurrence of Indebtedness
and Issuance of Disqualified Stock" covenant on a pro forma basis taking into
account such designation and (ii) such Subsidiary executes a Subsidiary
Guarantee pursuant to the terms of the Indenture.
"VOTING STOCK" of an entity means all classes of Capital Stock of such
entity then outstanding and normally entitled to vote in the election of
directors or all interests in such entity with the ability to control the
management or actions of such entity.
"WEIGHTED AVERAGE LIFE TO MATURITY" means, when applied to any Indebtedness
at any date, the number of years obtained by dividing (i) the sum of the
products obtained by multiplying (a) the amount of each then remaining
installment, sinking fund, serial maturity or other required payments of
principal, including payment at final maturity, in respect thereof, by (b) the
number of years (calculated to the nearest one-twelfth) that will elapse between
such date and the making of such payment, by (ii) the then outstanding principal
amount of such Indebtedness.
"WHOLLY OWNED RESTRICTED SUBSIDIARY" of any Person means a Restricted
Subsidiary of such Person all of the outstanding Capital Stock or other
ownership interests of which (other than directors' qualifying shares) shall at
the time be owned, directly or indirectly, by such Person or by one or more
Wholly Owned Restricted Subsidiaries of such Person.
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BOOK-ENTRY; DELIVERY AND FORM
The certificates representing the New Notes will initially be represented by
one or more permanent global Notes in definitive, fully registered form without
interest coupons (each a "Restricted Global Note"; and together with the
Regulation S Global Note, the "Global Notes") and will be deposited with the
Trustee as custodian for, and registered in the name of a nominee of, DTC. Old
Notes sold in offshore transactions in reliance on Regulation S under the
Securities Act were initially represented by one or more temporary global Notes
in definitive, fully registered form without interest coupons (each a "Temporary
Regulation S Global Note") and were deposited with the Trustee as custodian for,
and registered in the name of a nominee of, DTC for the accounts of Euroclear
and Cedel Bank. The Temporary Regulation S Global Note is exchangeable for one
or more permanent global Notes (each a "Permanent Regulation S Global Note"; and
together with the Temporary Regulation S Global Notes, the "Regulation S Global
Note") on or after the 40th day following July 24, 1998 upon certification that
the beneficial interests in such global Note are owned by non-U.S. persons.
Prior to the 40th day after the Closing Date, beneficial interests in the
Temporary Regulation S Global Note may only be held through Euroclear or Cedel
Bank.
Ownership of beneficial interests in a Global Note are limited to persons
who have accounts with DTC ("participants") or persons who hold interests
through participants. Ownership of beneficial interests in a Global Note will be
shown on, and the transfer of that ownership will be effected only through,
records maintained by DTC or its nominee (with respect to interests of
participants) and the records of participants (with respect to interests of
persons other than participants). Qualified institutional buyers may hold their
interests in a Restricted Global Note directly through DTC if they are
participants in such system, or indirectly through organizations which are
participants in such system.
Investors may hold their interests in a Regulation S Global Note directly
through Cedel Bank or Euroclear, if they are participants in such systems, or
indirectly through organizations that are participants in such systems. Cedel
Bank and Euroclear will hold interests in the Regulation S Global Notes on
behalf of their participants through DTC.
So long as DTC, or its nominee, is the registered owner or holder of a
Global Note, DTC or such nominee, as the case may be, will be considered the
sole owner or holder of the Notes represented by such Global Note for all
purposes under the Indenture and the Notes. No beneficial owner of an interest
in a Global Note will be able to transfer that interest except in accordance
with DTC's applicable procedures, in addition to those provided for under the
Indenture and, if applicable, those of Euroclear and Cedel Bank.
Payments of the principal of, and interest on, a Global Note will be made to
DTC or its nominee, as the case may be, as the registered owner thereof. Neither
the Company, the Trustee nor any Paying Agent will have any responsibility or
liability for any aspect of the records relating to or payments made on account
of beneficial ownership interests in a Global Note or for maintaining,
supervising or reviewing any records relating to such beneficial ownership
interests.
The Company expects that DTC or its nominee, upon receipt of any payment of
principal or interest in respect of a Global Note, will credit participants'
accounts with payments in amounts proportionate to their respective beneficial
interests in the principal amount of such Global Note as shown on the records of
DTC or its nominee. The Company also expects that payments by participants to
owners of beneficial interests in such Global Note held through such
participants will be governed by standing instructions and customary practices,
as is now the case with securities held for the accounts of customers registered
in the names of nominees for such customers. Such payments will be the
responsibility of such participants.
Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules and will be settled in same-day funds. Transfers
between participants in Euroclear and Cedel Bank will be effected in the
ordinary way in accordance with their respective rules and operating procedures.
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The Company expects that DTC will take any action permitted to be taken by a
holder of Notes (including the presentation of Notes for exchange as described
below) only at the direction of one or more participants to whose account the
DTC interests in a Global Note are credited and only in respect of such portion
of the aggregate principal amount of Notes as to which such participant or
participants has or have given such direction. However, if there is an Event of
Default under the Notes, DTC will exchange the applicable Global Note for
Certificated Notes, which it will distribute to its participants and which may
be legended as set forth under the heading "Transfer Restrictions."
The Company understands that DTC is a limited purpose trust company
organized under the laws of the State of New York, a "banking organization"
within the meaning of New York Banking Law, a member of the Federal Reserve
System, a "clearing corporation" within the meaning of the Uniform Commercial
Code and a "Clearing Agency" registered pursuant to the provisions of Section
17A of the Exchange Act. DTC was created to hold securities for its participants
and facilitate the clearance and settlement of securities transactions between
participants through electronic book-entry changes in accounts of its
participants, thereby eliminating the need for physical movement of certificates
and certain other organizations. Indirect access to the DTC system is available
to others such as banks, brokers, dealers and trust companies that clear through
or maintain a custodial relationship with a participant, either directly or
indirectly ("indirect participants").
Although DTC, Euroclear and Cedel Bank are expected to follow the foregoing
procedures in order to facilitate transfers of interests in a Global Note among
participants of DTC, Euroclear and Cedel Bank, they are under no obligation to
perform or continue to perform such procedures, and such procedures may be
discontinued at any time. Neither the Company nor the Trustee will have any
responsibility for the performance by DTC, Euroclear or Cedel Bank or their
respective participants or indirect participants of their respective obligations
under the rules and procedures governing their operations.
If DTC is at any time unwilling or unable to continue as a depositary for
the Global Notes and a successor depositary is not appointed by the Company
within 90 days, the Company will issue Certificated Notes, which may bear the
legend referred to under "Transfer Restrictions," in exchange for the Global
Notes. Holders of an interest in a Global Note may receive Certificated Notes,
which may bear the legend referred to under "Transfer Restrictions," in
accordance with DTC's rules and procedures in addition to those provided for
under the Indenture.
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MATERIAL UNITED STATES TAX CONSEQUENCES
The following summary describes the material United States federal income
and estate tax consequences resulting from the purchase, ownership, and
disposition of Notes as of the date hereof. It deals only with Notes held as
"capital assets" within the meaning of Section 1221 of the Code by initial
purchasers who purchased Notes at the initial issue price. Further, this
discussion does not address the situation of persons who may be subject to
special tax rules, including, by way of illustration and not limitation, rules
applicable to dealers in securities or currencies, financial institutions,
tax-exempt entities, life insurance companies, persons who hold Notes as a
hedge, as part of a constructive sale, or as a position in a "straddle" for
income tax purposes, or to persons who have a "functional currency" other than
the U.S. Dollar. As used herein, a "United States Holder" means a beneficial
owner who is a citizen or resident of the United States, a corporation, limited
liability company or partnership (unless the Treasury regulations provide
otherwise) created or organized in or under the laws of the United States or any
political subdivision thereof, an estate the income of which is subject to U.S.
federal income taxation regardless of its source, or a trust which is subject to
the supervision of a court within the United States and the control of one or
more U.S. persons as described in Section 7701(a)(30) of the Code. As used
herein, the term "Non-United States Holder" means any person or entity that is
not a United States Holder. An individual may, subject to certain exceptions, be
deemed to be a resident (as opposed to a non-resident alien) of the United
States by virtue of being present in the United States on at least 31 days in
the calendar year and for an aggregate of at least 183 days during a three year
period ending in the current calendar year, determined by counting each day
present in the U.S. during the current calendar year as a full day, each day
present in the U.S. during the immediately preceding calendar year as one-third
of a day, and each day present in the U.S. during the second preceding year as
one-sixth of a day.
The discussion set forth below is based upon the provisions of the Code, the
Treasury Regulations, and administrative and judicial decisions thereunder as of
the date hereof, and such authorities may be repealed, revoked or modified with
possible retroactive effect so as to result in federal income tax consequences
different from those discussed below. This summary does not purport to cover all
possible tax consequences associated with the purchase, ownership, and
disposition of Notes, such as any applicable foreign, state, local, or other tax
laws, nor to address all relevant estate or gift tax considerations. PERSONS
CONSIDERING THE PURCHASE, OWNERSHIP, OR DISPOSITION OF NOTES SHOULD CONSULT
THEIR OWN TAX ADVISORS CONCERNING THE FEDERAL INCOME TAX CONSEQUENCES IN LIGHT
OF THEIR PARTICULAR SITUATIONS AS WELL AS ANY CONSEQUENCES ARISING UNDER THE
LAWS OF ANY OTHER TAXING JURISDICTION.
TAX CONSEQUENCES TO UNITED STATES HOLDERS
INTEREST ON THE NOTES
The Notes were not issued with original issue discount ("OID"). Except as
described below, interest on a Note will be taxable to a United States Holder as
ordinary income from domestic cources at the time it is paid or accrued in
accordance with the United States Holder's regular method of accounting for
United States tax purposes.
SALE, RETIREMENT, OR OTHER DISPOSITION OF NOTES
Upon the sale, retirement, or other disposition of a Note (including any
sale to the Company in connection with the Company's option to purchase the
Note), a holder will recognize gain or loss equal to the difference between the
amount realized on the sale, retirement, or other disposition and the holder's
tax basis in the Note. Such gain or loss will be capital gain or loss and will
be long-term capital gain or loss if, at the time of the sale, retirement, or
other disposition, the Note has been held for more than one year. The Taxpayer
Relief Act of 1997 includes substantial changes to the federal taxation of
capital gains recognized by certain noncorporate taxpayers, such as individuals,
including a 20% maximum tax rate for
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certain gains from the sale of capital assets held for more than 18 months. The
deductibility of capital losses is subject to certain limitations. A holder's
tax basis in a Note will, in general, equal the cost of the Note to the holder.
TAX CONSEQUENCES TO NON-UNITED STATES HOLDERS
INTEREST ON NOTES
Subject to the discussion below concerning backup withholding, no
withholding of United States federal income tax will be required with respect to
the payment by the Company or any paying agent of principal or interest on a
Note owned by a Non-United States Holder, provided that the beneficial owner (i)
does not actually or constructively own 10% or more of the total combined voting
power of all classes of stock of the Company entitled to vote within the meaning
of Section 871(h)(3) of the Code and the regulations thereunder, (ii) is not a
controlled foreign corporation related, directly or indirectly, to the Company
through stock ownership, (iii) is not a bank whose receipt of interest on a Note
is described in Section 881(c)(3)(A) of the Code and (iv) satisfies the
statement requirement (described generally below) set forth in Section 871(h)
and Section 881(c) of the Code and the regulations thereunder.
To satisfy the requirement referred to in clause (iv) above, the beneficial
owner of such Note, or a financial institution holding the Note on behalf of
such owner, must provide, in accordance with specified procedures, the Company
or its paying agent with a statement to the effect that the beneficial owner is
not a U.S. person. These requirements will be met if (1) the beneficial owner
provides his name and address, and certifies, under penalties of perjury, that
he is not a U.S. person (which certification may be made on an IRS Form W-8 (or
successor form)) or (2) a financial institution holding the Note on behalf of
the beneficial owner certifies, under penalties of perjury, that such statement
has been received by it and furnishes a paying agent with a copy thereof. Under
finalized Treasury Regulations, the statement requirement referred to in clause
(iv) above may also be satisfied with other documentary evidence for interest
paid after December 31, 1999 with respect to an offshore account or through
certain foreign intermediaries.
In the event any of the above requirements are not satisfied, the Company
will nonetheless not withhold federal income tax on interest paid to a
Non-United States Holder if it receives IRS Form 4224 (or successor form) from
the Non-United States Holder, establishing that such income is effectively
connected with the conduct of a trade or business in the United States, unless
the Company has knowledge to the contrary. Interest paid to a Non-United States
Holder (other than a partnership) which is effectively connected with the
conduct by the holder of a trade or business in the United States is generally
taxed at the graduated rates that are applicable to United States persons. In
the case of a Non-United States Holder that is a corporation, such effectively
connected income may also be subject to the United States federal branch profits
tax (which is generally imposed on a foreign corporation on the deemed
repatriation from the United States of effectively connected earnings and
profits) at a 30% rate (unless the rate is reduced or eliminated by an
applicable income tax treaty and the holder is a qualified resident of the
treaty country). In the case of a partnership that has foreign partners (i.e.,
persons who would be Non-United States Holders if they held the Notes directly),
such effectively connected income allocable to the foreign partner would
generally be subject to United Stated federal withholding tax (regardless of
whether such income is, in fact, distributed to such foreign partner) at a 35%
rate if the foreign partner is a corporation, or at a 39.6% rate if the foreign
partner is not a corporation. Any foreign partner of such a partnership would be
entitled to a credit against his United States federal income tax for his share
of the withholding tax paid by the partnership.
If a Non-United States Holder cannot satisfy the requirements of any of the
above-described exceptions to withholding, payments of interest made to a
Non-United States Holder will be subject to a 30% withholding tax unless the
beneficial owner of the Note provides the Company or its paying agent, as
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the case may be, with a properly executed IRS Form 1001 (or successor form)
claiming an exemption from or reduced rate of withholding under the benefit of
an applicable tax treaty.
Under the Final Regulations, Non-United States Holders will generally be
required to provide IRS Form W-8 in lieu of IRS Form 4224 or IRS Form 1001,
although alternative documentation may be applicable in certain situations.
SALE, EXCHANGE, REDEMPTION OR OTHER DISPOSITION OF NOTES
A Non-United States Holder will generally not be subject to United States
federal income tax with respect to gain recognized on a sale, exchange,
redemption or other disposition of Notes unless (i) the gain is effectively
connected with a trade or business of the Non-United States Holder in the United
States, (ii) in the case of a Non-United States Holder who is an individual and
holds the Notes as a capital asset, such holder is present in the United States
for 183 or more days in the taxable year of the sale or other disposition and
certain other conditions are met, or (iii) the Non-United States Holder is
subject to tax pursuant to certain provisions of the Code applicable to United
States expatriates. Subject to the discussion below concerning backup
withholding, no withholding of United States federal income tax will be required
with respect to any gain or income realized by a Non-United States Holder upon
the sale, exchange, retirement or other disposition of a Note.
Gains derived by a Non-United States Holder (other than a partnership) from
the sale or other disposition of Notes that are effectively connected with the
conduct by the Holder of a trade or business in the United States are generally
taxed at the graduated rates that are applicable to United States persons. In
the case of a Non-United States Holder that is a corporation, such effectively
connected income may also be subject to the United States branch profits tax. In
the case of a partnership that has foreign partners (i.e., persons who would be
Non-United States Holders if they held the Notes directly) withholding will be
made at a 35% rate if the foreign partner is a corporation, or at 39.6% rate if
the foreign partner is not a corporation. Any foreign partner of such a
partnership would be entitled to a credit against his United States federal
income tax for his share of the withholding tax paid by the partnership. If an
individual Non-United States Holder falls under clause (ii) of the immediately
preceding paragraph of this discussion, he will be subject to a flat 30% tax on
the gain derived from the sale or other disposition, which may be offset by
United States capital losses recognized within the same taxable year as such
sale or other disposition (notwithstanding the fact that he is not considered a
resident of the United States).
FEDERAL ESTATE TAX
A Note beneficially owned by an individual who at the time of death is a
Non-United States Holder will not be subject to United States federal estate tax
as a result of such individual's death, provided that such individual does not
actually or constructively own 10% or more of the total combined voting power of
all classes of stock of the Company entitled to vote within the meaning of
Section 871(h)(3) of the Code and provided that the interest payments with
respect to such Note would not have been, if received at the time of such
individual's death, effectively connected with the conduct of a United States
trade or business by such individual.
INFORMATION REPORTING AND BACKUP WITHHOLDING
In general, information reporting requirements will apply to certain
payments of principal and interest on the Notes and to the proceeds of sale of a
Note made to United States Holders other than certain exempt recipients (such as
corporations). A 31% backup withholding tax will apply to such payments if the
United States Holder fails to provide a taxpayer identification number or
certification of foreign or other exempt status or fails to report in full
dividend and interest income.
No information reporting or backup withholding will be required with respect
to payments made by the Company or any paying agent to Non-United States Holders
if a statement described in clause
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(iv) under "Tax Consequences to Non-United States Holders--Interest on Notes"
has been received and the payor does not have actual knowledge that the
beneficial owner is a United States person.
Information reporting and backup withholding will not apply if payments of
interest on a Note are made outside the United States to an account maintained
at an office or branch of a United States or foreign bank or other financial
institution, provided certain procedures are in place, and are observed, between
the Company and the foreign bank or financial institution.
Payments on the sale, exchange or other disposition of a Note made to or
through a foreign office of a broker generally will not be subject to backup
withholding. However, payments made by a broker that is a United States person,
a controlled foreign corporation for United States federal income tax purposes,
a foreign person 50 percent or more of whose gross income is effectively
connected with a United States trade or business for a specified three year
period, or (with respect to payments after December 31, 1999) a foreign
partnership with certain connections to the United States, will be subject to
information reporting unless the broker has in its records documentary evidence
that the beneficial owner is not a United States person and certain other
conditions are met, or the beneficial owner otherwise establishes an exemption.
Backup withholding may apply to any payment that such broker is required to
report if the broker has actual knowledge that the payee is a United States
person. Payments to or through the United States office of a custodian, nominee
or agent or the payment by the United States office of a broker of the proceeds
of a sale will be subject to information reporting and backup withholding unless
the Holder certifies, under penalties of perjury, that it is not a United States
person or otherwise establishes an exemption.
For payments made after December 31, 1999, with respect to Notes held by
foreign partnerships, Treasury regulations require that the certification
described in (iv) under "Tax Consequences to Non-United States Holders--Interest
on Notes" above be provided by the partners, rather than by the foreign
partnership, and that the partnership provide certain information, including a
United States taxpayer identification number. A look-through rule will apply in
the case of tiered partnerships.
Non-United States Holders should consult their tax advisors regarding the
application of information reporting and backup withholding in their particular
situations, the availability of an exemption therefrom, and the procedures for
obtaining such an exemption, if available. Any amounts withheld under the backup
withholding rules will be allowed as a refund or credit against the Non-United
States Holder's U.S. federal income tax liability and may entitle such Holder to
a refund, provided the required information is furnished to the IRS.
EFFECT OF EXCHANGE
The exchange of Old Notes for New Notes in the Exchange Offer should not
constitute a taxable event to holders. Consequently, no gain or loss will be
recognized by a holder upon receipt of an Exchange Note, the holding period of
the New Note will include the holding period of the Old Note exchanged therefor,
and the basis of the New Note will be the same as the basis of the Note
immediately before the exchange. In any event, persons considering the exchange
of Old Notes for New Notes should consult their own tax advisors concerning the
United States federal income tax consequences in light of their particular
situations as well as any consequences arising under the laws of any other
taxing jurisdiction.
102
<PAGE>
PLAN OF DISTRIBUTION
There has previously been only a limited secondary market and no public
market for the Old Notes. The Company does not intend to apply for the listing
of the Notes on a national securities exchange or for their quotation through
The Nasdaq Stock Market. The Notes are eligible for trading in the PORTAL
market. The Company has been advised by the Initial Purchaser that the Initial
Purchaser currently intends to make a market in the Notes; however, the Initial
Purchaser is not obligated to do so and any market making may be discontinued by
any Placement Agent at any time. In addition, such market making activity may be
limited during the Exchange Offer. Therefore, there can be no assurance that an
active market for the Old Notes or the New Notes will develop. If a trading
market does not develop or is not maintained, holders of Notes may experience
difficulty in reselling Notes. If a trading market develops for the Notes,
future trading prices of such securities will depend on many factors, including,
among other things, prevailing interest rates, the Company's results of
operations and the market for similar securities. Depending on such factors,
such securities may trade at a discount from their offering price.
BROKER-DEALERS WHO DID NOT ACQUIRE OLD NOTES AS A RESULT OF MARKET MAKING
ACTIVITIES OR TRADING ACTIVITIES MAY NOT PARTICIPATE IN THE EXCHANGE OFFER.
With respect to resale of New Notes, based on an interpretation by the staff
of the Commission set forth in no-action letters issued to third parties, the
Company believes that a holder (other than a person that is an affiliate of the
Company within the meaning of Rule 405 under the Securities Act or a "broker" or
"dealer" registered under the Exchange Act) who exchanges Old Notes for New
Notes in the ordinary course of business and who is not participating, does not
intend to participate, and has no arrangement or understanding with any person
to participate, in the distribution of the New Notes, will be allowed to resell
the New Notes to the public without further registration under the Securities
Act and without delivering to the purchasers of the New Notes a prospectus that
satisfies the requirements of Section 10 thereof. However, if any holder
acquires New Notes in the Exchange Offer for the purpose of distributing or
participating in a distribution of the New Notes, such holder cannot rely on the
position of the staff of the Commission enunciated in EXXON CAPITAL HOLDINGS
CORPORATION (available May 13, 1988) or similar no-action letters or any similar
interpretive letters and must comply with the registration and prospectus
delivery requirements of the Securities Act in connection with a secondary
resale transaction, unless an exemption from registration is otherwise
available.
As contemplated by the no-action letters mentioned above and the
Registration Rights Agreement, each holder accepting the Exchange Offer is
required to represent to the Company in the Letter of Transmittal that (i) the
New Notes are to be acquired by the holder in the ordinary course of business,
(ii) the holder is not engaging and does not intend to engage in the
distribution of the New Notes, and (iii) the holder acknowledges that, if such
holder participates in the Exchange Offer for the purpose of distributing the
New Notes, such holder must comply with the registration and prospectus delivery
requirements of the Securities Act and cannot rely on the above no-action
letters.
Any broker or dealer registered under the Exchange Act (each a
"Broker-Dealer") who holds Old Notes that were acquired for its own account as a
result of market-making activities or other trading activities (other than Old
Notes acquired directly from the Company or an affiliate of the Company) may
exchange such Old Notes for New Notes pursuant to the Exchange Offer; however,
such Broker-Dealer may be deemed an underwriter within the meaning of the
Securities Act and, therefore, must deliver a prospectus meeting the
requirements of the Securities Act in connection with any resales of the New
Notes received by it in the Exchange Offer, which prospectus delivery
requirement may be satisfied by the delivery by such Broker-Dealer of this
Prospectus. The Company has agreed to cause the Exchange Offer Registration
Statement, of which this Prospectus is a part, to remain continuously effective
for a period of 180 days, if required, from the Exchange Date, and to make this
Prospectus, as amended or supplemented, available to any such Broker-Dealer for
use in connection with resales. Any Broker-Dealer participating in
103
<PAGE>
the Exchange Offer will be required to acknowledge that it will deliver a
prospectus meeting the requirements of the Securities Act in connection with any
resales of New Notes received by it in the Exchange Offer. The delivery by a
Broker-Dealer of a prospectus in connection with resales of New Notes shall not
be deemed to be an admission by such Broker-Dealer that it is an underwriter
within the meaning of the Securities Act. The Company will not receive any
proceeds from any sale of New Notes by a Broker-Dealer.
New Notes received by Broker-Dealers for their own account pursuant to the
Exchange Offer may be sold from time to time in one or more transactions in the
over-the-counter market, in negotiated transactions, through the writing of
options on the New Notes or a combination of such methods of resale, at market
prices prevailing at the time of resale, at prices related to such prevailing
market prices or negotiated prices. Any such resale may be made directly to
purchasers or to or through brokers or dealers who may receive compensation in
the form of commissions or concessions from any such Broker-Dealer and/or the
purchasers of any such New Notes.
LEGAL MATTERS
Certain legal matters with respect to the validity of the Notes are being
passed upon for the Company by McAfee & Taft A Professional Corporation,
Oklahoma City, Oklahoma.
EXPERTS
The Financial Statements of the Company and of the oil and gas properties
included in the Worland Field Acquisition included in this Prospectus, to the
extent and for the periods indicated in their reports, have been audited by
Arthur Andersen LLP, independent public accountants, and are included herein in
reliance upon the authority of said firm as experts in giving said reports.
Certain information relating to the estimated proved reserves of oil and
natural gas and the related estimates of future net cash flows and present
values thereof as of December 31, 1997, included in this Prospectus and in the
notes to the financial statements of the Company have been prepared by Ryder
Scott Company Petroleum Engineers, Denver, Colorado.
104
<PAGE>
GLOSSARY OF TERMS
The definitions set forth below shall apply to the indicated terms as used
in this Prospectus. All volumes of natural gas referred to herein are stated at
the legal pressure base to the state or area where the reserves exit and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume.
BCF. One billion cubic feet of natural gas.
BOE. One barrel of oil equivalent, determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids.
COMMERCIAL WELL; COMMERCIALLY PRODUCTIVE WELL. An oil and gas well which
produces oil and gas in sufficient quantities such that proceeds from the sale
of such production exceed production expenses and taxes.
COMPLETION. The installation of permanent equipment for the production of
oil and natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved areas of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
DRY HOLE OR WELL. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
EXPLORATORY WELL. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
FIELD. An area consisting of a single reservoir or multiple reservoirs all
grouped or related to the same individual geological structural feature and/or
stratigraphic condition.
FORMATION. A succession of sedimentary beds that were deposited under the
same general geologic conditions.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be,
in which a working interest is owned.
HORIZONTAL DRILLING. A drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and can result in both increased
production rates and greater ultimate recoveries of hydrocarbons. Horizontal
wells are drilled at angles greater than 70 degrees from vertical.
MBBLS. One thousand barrels of oil.
MBOE. One thousand barrels of oil equivalent, determined using the ratio of
one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural
gas.
MCF. One thousand cubic feet.
MCFE. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
105
<PAGE>
MMBBLS. One million barrels of oil.
MMBOE. One million barrels of oil equivalent, determined using the ratio of
one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural
gas.
MMCF. One million cubic feet.
MMCFE. One million cubic feet of gas equivalent determined using the ratio
of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural
gas.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.
OIL. Crude oil, condensate and natural gas liquids.
PV-10. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and future income tax expenses or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%. PV-10, as used in
this Prospectus, is determined on the same basis as the Standardized Measure of
Discounted Future Net Cash Flows as required by the Financial Accounting
Standards Board's Statement of Financial Accounting Standards No. 69 except that
PV-10 gives no effect to future income tax expense because the Company is an "S
Corporation" for federal income tax purposes and is not a federal income
tax-paying entity.
PRODUCTIVE WELL. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production.
PROVED DEVELOPED RESERVES. Proved reserves that are expected to be
recovered from existing wellbores with existing equipment and operating methods,
whether or not currently producing, without drilling additional wells.
Production of such reserves may require a recompletion includes additional oil
and gas expected to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery only after testing by pilot project or after
operation of an installed program has confirmed through production response that
increased recovery will be achieved.
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Includes reserves which can be
produced economically through application of improved recovery techniques when
successful testing by a pilot project, the operation of a installed program in
the reservoir, provide support for the engineering analysis on which the project
or program was based.
PROVED UNDEVELOPED LOCATION. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells drilled to a known reservoir on undrilled acreage or
from existing wells where a relatively major expenditure is required for
recompletion does not include acreage for which an application of fluid
injection or other improved recovery technique is contemplated unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
106
<PAGE>
RECOMPLETION. The completion for production of an existing wellbore in
another formation from that in which the well has been previously completed.
RESERVE LIFE. A ratio determined by dividing the existing reserves by
production from such reserves for the prior twelve month period.
RESERVOIR. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reserves.
ROYALTY INTEREST. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
WELLBORE. The hole drilled by the bit.
WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
WORKOVER. Operations on a producing well to restore or increase production.
107
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
CONTINENTAL RESOURCES, INC.
Report of Independent Public Accountants............................................. F-2
Consolidated Balance Sheets as of December 31, 1996 and 1997, and
June 30, 1998 (Unaudited).......................................................... F-3
Consolidated Statements of Operations for the Years Ended December 31, 1995, 1996 and
1997, and for the Six Months Ended June 30, 1997 and 1998 (Unaudited).............. F-4
Consolidated Statements of Stockholders' Equity for the Years Ended December 31,
1995, 1996 and 1997, and for the Six Months Ended June 30, 1998 (Unaudited)........ F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1995, 1996 and
1997, and for the Six Months Ended June 30, 1997 and 1998 (Unaudited).............. F-6
Notes to Consolidated Financial Statements........................................... F-7
BASS ENTERPRISES PRODUCTION CO.
Report of Independent Public Accountants............................................. F-20
Statements of Revenues and Direct Operating Expenses of Oil and Gas Properties
Included in the Purchase Agreement Between Continental Resources, Inc. and Bass
Enterprises Production Co. for the Years Ended December 31, 1995, 1996 and 1997,
and for the Six Months Ended June 30, 1997 and for the Five Months Ended May 31,
1998 (Unaudited)................................................................... F-21
Notes to Statements of Revenues and Direct Operating Expenses of Oil and Gas
Properties Included in the Purchase Agreement Between Continental Resources, Inc.
and Bass Enterprises Production Co................................................. F-22
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors
of Continental Resources, Inc.:
We have audited the accompanying consolidated balance sheets of Continental
Resources, Inc. (an Oklahoma corporation) and subsidiary as of December 31, 1997
and 1996, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. These consolidated financial statements and the supplementary
information referred to below are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Continental
Resources, Inc. and subsidiary as of December 31, 1997 and 1996, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
April 22, 1998
F-2
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
------------------------------ --------------
1996 1997 1998
-------------- -------------- --------------
<S> <C> <C> <C>
(UNAUDITED)
CURRENT ASSETS:
Cash........................................................... $ 3,320,130 $ 1,301,115 $ 1,336,110
Accounts receivable--
Oil and gas sales............................................ 15,249,670 11,432,273 6,349,546
Joint interest and other, net................................ 5,923,216 13,711,270 9,383,015
Inventories.................................................... 3,556,190 3,548,547 4,962,746
Prepaid income taxes........................................... 1,764,484 -- --
Prepaid expenses............................................... 2,072,124 382,725 359,898
Advances to affiliates......................................... 460,551 59,541 19,624,860
-------------- -------------- --------------
Total current assets....................................... 32,346,365 30,435,471 42,016,174
-------------- -------------- --------------
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)--
Producing properties......................................... 137,403,821 195,785,302 233,600,015
Nonproducing leaseholds...................................... 16,878,253 17,047,404 49,029,303
Gas gathering and processing facilities........................ 8,430,318 20,794,944 22,561,309
Service properties, equipment and other........................ 8,453,513 12,848,701 13,650,019
-------------- -------------- --------------
Total property and equipment............................... 171,165,905 246,476,351 318,840,647
Less--Accumulated depreciation, depletion and
amortization............................................. 57,845,700 88,559,352 (103,918,055)
-------------- -------------- --------------
Net property and equipment................................. 113,320,205 157,916,999 214,922,591
-------------- -------------- --------------
OTHER ASSETS..................................................... 26,195 33,696 924,487
-------------- -------------- --------------
Total assets............................................... $ 145,692,765 $ 188,386,166 $ 257,863,253
-------------- -------------- --------------
-------------- -------------- --------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable............................................... $ 17,635,561 $ 19,614,068 $ 12,234,726
Current portion of long-term debt.............................. 3,422,447 315,113 315,113
Revenues and royalties payable................................. 6,807,664 7,497,011 3,653,778
Accrued liabilities and other.................................. 2,212,397 3,164,735 2,951,451
-------------- -------------- --------------
Total current liabilities.................................. 30,078,069 30,590,927 19,155,068
-------------- -------------- --------------
LONG-TERM DEBT, net of current portion........................... 51,336,696 79,316,913 163,737,232
DEFERRED INCOME TAXES............................................ 11,978,570 -- --
OTHER NONCURRENT LIABILITIES..................................... 222,207 213,877 205,862
STOCKHOLDERS' EQUITY:
Common stock, $1 par value, 75,000 shares authorized, 49,045
shares issued, 49,041 shares outstanding..................... 49,045 49,045 49,041
Additional paid-in capital..................................... 2,731,075 2,731,075 2,721,079
Treasury stock, 4 shares, at cost.............................. -- (10,000) --
Retained earnings.............................................. 49,297,103 75,494,329 71,994,971
-------------- -------------- --------------
Total stockholders' equity................................. 52,077,223 78,264,449 74,765,091
-------------- -------------- --------------
Total liabilities and stockholders' equity................. $ 145,692,765 $ 188,386,166 $ 257,863,253
-------------- -------------- --------------
-------------- -------------- --------------
</TABLE>
The accompanying notes are an integral part of these consolidated balance
sheets.
F-3
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
FOR THE SIX MONTHS
FOR THE YEARS ENDED DECEMBER 31 ENDED JUNE 30,
------------------------------------ ----------------------
1995 1996 1997 1997 1998
---------- ----------- ----------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES:
Oil and gas sales............................ $30,575,937 $75,016,352 $78,599,075 $39,135,128 $31,291,036
Gathering, marketing and processing.......... 20,638,962 25,765,782 25,020,764 15,522,153 9,803,962
Oil and gas service operations............... 6,148,487 6,490,759 6,405,387 3,714,776 3,062,320
---------- ----------- ----------- ---------- ----------
Total revenues............................. 57,363,386 107,272,893 110,025,226 58,372,057 44,157,318
---------- ----------- ----------- ---------- ----------
OPERATING COSTS AND EXPENSES:
Production expenses and taxes................ 7,610,850 19,337,987 20,748,414 10,621,812 9,074,294
Exploration expenses......................... 6,184,239 4,512,355 6,806,491 3,409,693 2,649,514
Gathering, marketing and processing.......... 13,223,476 21,789,861 22,715,336 12,872,663 8,408,877
Oil and gas service operations............... 3,680,089 4,033,547 3,654,277 1,854,812 1,824,746
Depreciation, depletion and amortization..... 9,613,747 22,875,743 33,354,430 16,712,641 16,482,968
General and administrative................... 8,260,416 9,154,725 8,988,984 3,986,405 4,914,457
---------- ----------- ----------- ---------- ----------
Total operating costs and expenses......... 48,572,817 81,704,218 96,267,932 49,458,026 43,354,856
---------- ----------- ----------- ---------- ----------
OPERATING INCOME............................... 8,790,569 25,568,675 13,757,294 8,914,031 802,462
---------- ----------- ----------- ---------- ----------
OTHER INCOME AND EXPENSES
Interest income.............................. 136,757 311,981 241,456 103,665 779,897
Interest expense............................. (2,395,626) (4,550,488) (4,803,837) (2,313,297) (5,174,113)
Other income (expense)....................... 410,765 232,947 8,060,863 685,348 92,396
---------- ----------- ----------- ---------- ----------
Total other income and (expenses).......... (2,669,634) (4,005,560) 3,498,482 (1,524,284) (4,301,820)
---------- ----------- ----------- ---------- ----------
INCOME BEFORE INCOME TAXES..................... 6,120,935 21,563,115 17,255,776 7,389,747 (3,499,358)
INCOME TAX BENEFIT (EXPENSE)................... (2,251,591) (8,238,124) 8,941,450 8,941,450 --
---------- ----------- ----------- ---------- ----------
NET INCOME..................................... $3,869,344 $13,324,991 $26,197,226 $16,331,197 $(3,499,358)
---------- ----------- ----------- ---------- ----------
---------- ----------- ----------- ---------- ----------
EARNINGS PER COMMON SHARE...................... $ 78.89 $ 271.69 $ 534.18 $ 333.00 $ (71.36)
---------- ----------- ----------- ---------- ----------
---------- ----------- ----------- ---------- ----------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995, 1996 AND 1997 AND FOR THE
SIX MONTHS ENDED JUNE 30, 1998 (UNAUDITED)
<TABLE>
<CAPTION>
ADDITIONAL TOTAL
COMMON PAID-IN TREASURY RETAINED STOCKHOLDERS'
STOCK CAPITAL STOCK EARNINGS EQUITY
--------- ------------ ---------- ------------- -------------
<S> <C> <C> <C> <C> <C>
BALANCE, December 31, 1994.................... $ 49,045 $ 2,731,075 $ -- $ 32,102,768 $ 34,882,888
Net income.................................. -- -- -- 3,869,344 3,869,344
--------- ------------ ---------- ------------- -------------
BALANCE, December 31, 1995.................... 49,045 2,731,075 -- 35,972,112 38,752,232
Net income.................................. -- -- -- 13,324,991 13,324,991
--------- ------------ ---------- ------------- -------------
BALANCE, December 31, 1996.................... 49,045 2,731,075 -- 49,297,103 52,077,223
Purchase shares of treasury stock........... -- -- (10,000) -- (10,000)
Net income.................................. -- -- -- 26,197,226 26,197,226
--------- ------------ ---------- ------------- -------------
BALANCE, December 31, 1997.................... 49,045 2,731,075 (10,000) 75,494,329 78,264,449
--------- ------------ ---------- ------------- -------------
Retirement of treasury stock (unaudited).... (4) (9,996) 10,000 -- --
Net income (unaudited)...................... -- -- -- (3,499,358) (3,499,358)
--------- ------------ ---------- ------------- -------------
BALANCE, June 30, 1998 (unaudited)............ $ 49,041 $ 2,721,079 $ -- $ 71,994,971 $ 74,765,091
--------- ------------ ---------- ------------- -------------
--------- ------------ ---------- ------------- -------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
FOR THE SIX MONTHS ENDED
FOR THE YEARS ENDED DECEMBER 31 JUNE 30,
------------------------------------- ------------------------
1995 1996 1997 1997 1998
----------- ----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income....................................... $ 3,869,344 $13,324,991 $26,197,226 $16,331,198 $(3,499,358)
Adjustments to reconcile net income to net cash
provided by operating activities--
Depreciation, depletion and amortization..... 9,613,747 22,875,743 33,354,430 16,712,641 16,482,968
(Gain)/loss on sale of assets................ 410,765 (232,947) (674,091) (643,279) (21,696)
Dry hole cost and impairment of undeveloped
leases..................................... 2,417,378 1,167,204 1,467,235 2,238,969 129,925
Deferred income taxes........................ 1,618,130 8,238,124 (11,978,570) (11,978,570) --
Other noncurrent assets...................... -- -- -- (321,492) (8,015)
Changes in current assets and liabilities--
Increase in accounts receivable................ (5,273,021) (10,238,194) (3,970,657) 2,164,717 9,410,982
Decrease/(increase) in inventories............. (102,471) (624,052) 7,643 (439,566) (1,414,199)
Decrease/(increase) in prepaid income taxes and
expenses..................................... (58,964) 1,246,074 3,453,883 2,508,048 22,822
Increase in accounts payable................... 9,561,493 264,922 1,978,507 3,519,245 (7,379,342)
Increase/(decrease) in revenues and royalties
payable...................................... (504,304) 5,230,072 689,347 (1,666,771) (3,843,233)
Increase/(decrease) in accrued liabilities and
other........................................ (2,567,587) 471,680 952,338 (476,926) (213,284)
----------- ----------- ----------- ----------- -----------
Net cash provided by operating
activities............................... 18,984,510 41,723,617 51,477,291 27,948,214 9,667,570
----------- ----------- ----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development.................... (37,212,880) (43,588,567) (63,701,798) (36,120,893) (28,866,225)
Gas gathering and processing facilities and
service properties, equipment and other...... (4,720,755) (3,428,080) (16,759,814) (5,352,478) (2,567,683)
Purchase of producing properties............... (16,292,607) (3,323,952) (475,535) (204,810) (85,100,000)
Proceeds from sale of assets................... 204,116 182,040 2,176,948 2,010,800 387,124
Advances from (to) affiliates.................. -- (460,551) 401,010 (5,809) 16,168
----------- ----------- ----------- ----------- -----------
Net cash used in investing activities...... (58,022,126) (50,619,110) (78,359,189) (39,673,190) (116,130,616)
----------- ----------- ----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Purchase of treasury stock....................... -- -- (10,000) -- --
Proceeds from line of credit and other........... 41,034,977 14,144,383 33,493,240 20,000,000 109,014,597
Repayment of line of credit and other............ (3,041,181) (3,650,610) (30,570,357) (11,443,740) (1,625,765)
Loans from majority stockholder.................. -- -- 21,950,000 -- (890,791)
----------- ----------- ----------- ----------- -----------
Net cash provided by financing
activities............................... 37,993,796 10,493,773 24,862,883 8,556,260 106,498,041
----------- ----------- ----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH.................... (1,043,820) 1,598,280 (2,019,015) (3,168,716) 34,995
CASH, beginning of period.......................... 2,765,670 1,721,850 3,320,130 3,320,130 1,301,115
----------- ----------- ----------- ----------- -----------
CASH, end of period................................ $ 1,721,850 $ 3,320,130 $ 1,301,115 $ 151,414 $ 1,336,110
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid.................................... $ 2,395,626 $ 4,550,488 $ 4,301,977 $ 2,313,297 $ 5,174,113
Income taxes paid................................ $ 2,713,000 $ 589,000 $ 300,000 $ -- $23,315,151
NONCASH INVESTING AND FINANCING ACTIVITIES:
Advance to affiliate made with sale of 50%
interest in producing properties............... -- -- -- -- $19,581,487
Satisfaction of note payable to principal
stockholder through sale of 50% interest in
producing properties........................... -- -- -- -- $22,968,513
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION:
Continental Resources, Inc. ("CRI") was incorporated in Oklahoma on November
16, 1967, as Shelly Dean Oil Company. On September 23, 1976, the name was
changed to Hamm Production Company. In January 1987, the Company acquired all of
the assets and assumed the debt of Continental Trend Resources, Inc. Affiliated
entities, J.S. Aviation and Wheatland Oil Co. were merged into Hamm Production
Company, and the corporate name was changed to Continental Trend Resources, Inc.
at that time. In 1991, the Company's name was changed to Continental Resources,
Inc.
The Company has one wholly-owned subsidiary, Continental Gas, Inc. ("CGI").
CGI was incorporated in April 1990.
CRI's principal business is oil and natural gas exploration, development and
production. CRI has interests in approximately 1,000 wells and serves as the
operator in the majority of such wells. CRI's operations are primarily in
Oklahoma, North Dakota, South Dakota, Montana, Illinois and Texas.
CGI is engaged principally in natural gas marketing, gathering and
processing activities and operates six gas gathering systems and two gas
processing plants in Oklahoma. In addition, CGI participates with CRI in certain
oil and natural gas wells.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts and
operations of CRI and CGI (collectively the "Company"). All significant
intercompany accounts and transactions have been eliminated in the consolidated
financial statements.
INTERIM FINANCIAL INFORMATION
The interim consolidated financial statements as of March 31, 1998, and for
the six months ended June 30, 1997 and 1998, are unaudited, and certain
information and footnote disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principals have been
omitted. In the opinion of management, all adjustments, consisting of normal
recurring adjustments, necessary to fairly present the financial position,
results of operations and cash flows with respect to the consolidated interim
financial statements have been included.
ACCOUNTS RECEIVABLE
The Company operates exclusively in the oil and natural gas exploration and
production, gas gathering and processing and gas marketing industries. The
Company's joint interest receivables at December 31, 1996 and 1997, are recorded
net of an allowance for doubtful accounts of approximately $200,000 and
$467,000, respectively, in the accompanying consolidated balance sheets.
INVENTORIES
Inventories consist primarily of tubular goods, production equipment and
crude oil in tanks, which are stated at the lower of average cost or market. At
December 31, 1996 and 1997, tubular goods and production equipment totaled
approximately $2,773,000 and $2,692,000, respectively; crude oil in tanks
totaled approximately $783,000 and $856,000, respectively.
F-7
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
PROPERTY AND EQUIPMENT
The Company utilizes the successful efforts method of accounting for oil and
gas activities whereby costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that find proved reserves and
to drill and equip development wells are capitalized. These costs are amortized
to operations on a unit-of-production method based on proved developed oil and
gas reserves, allocated property by property, as estimated by petroleum
engineers. Geological and geophysical costs, lease rentals and costs associated
with unsuccessful exploratory wells are expensed as incurred. Nonproducing
leaseholds are periodically assessed for impairment based on exploration results
and planned drilling activity. Maintenance and repairs are expensed as incurred,
except that the costs of replacements or renewals that expand capacity or
improve production are capitalized. Gas gathering systems and gas processing
plants are depreciated using the straight-line method over an estimated useful
life of 14 years. Service properties and equipment and other is depreciated
using the straight-line method over estimated useful lives of 5 to 40 years.
INCOME TAXES
The Company filed a consolidated income tax return based on a May 31 fiscal
tax year end. Through May 31, 1997, deferred income taxes were provided for
temporary differences between financial reporting and income tax bases of assets
and liabilities. The estimated Federal and state income taxes on income or loss
generated between June 1 and December 31 is included in deferred income taxes at
each calendar year end prior to December 31, 1997.
Effective June 1, 1997, the Company converted to an "S-corporation" under
Subchapter S of the Internal Revenue Code. As a result, income taxes
attributable to Federal taxable income of the Company after May 31, 1997, if
any, will be payable by the stockholders of the Company. The effect of
eliminating the deferred tax assets and liabilities were recognized in the
results of operations for the year ended December 31, 1997, the year of
adoption.
EARNINGS PER COMMON SHARE
Earnings per common share includes no dilution and is computed by dividing
income available to common stockholders by the weighted-average number of shares
outstanding for the period. There are no common stock equivalents or securities
outstanding which would result in material dilution. The weighted-average number
of shares used to compute earnings per common share was 49,045 in 1995 and 1996
and 49,042 in 1997.
FUTURES CONTRACTS
CGI, in the normal course of business, enters into fixed price contracts for
either the purchase or sale of natural gas at future dates. Due to fluctuations
in the natural gas market, CGI buys or sells natural gas futures contracts to
hedge the price and basis risk associated with the specifically identified
purchase or sales contracts. CGI accounts for changes in the market value of
futures contracts as a deferred gain or loss until the production month of the
hedged transaction, at which time the gain or loss on the natural gas futures
contract is recognized in the results of operations. At December 31, 1996 and
1997, there were no open natural gas futures contracts. Net gains and losses on
futures contracts are included in gas gathering,
F-8
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
marketing and processing revenues in the accompanying consolidated statements of
operations and were immaterial for the years ended December 31, 1995, 1996 and
1997.
GAS BALANCING ARRANGEMENTS
The Company follows the "sales method" of accounting for its gas revenue
whereby the Company recognizes sales revenue on all gas sold to its purchasers,
regardless of whether the sales are proportionate to the Company's ownership in
the property. A liability is recognized only to the extent that the Company has
a net imbalance in excess of their share of the reserves in the underlying
properties. The Company's aggregate imbalance positions at December 31, 1996 and
1997 were not material.
SIGNIFICANT CUSTOMER
During 1995, 1996 and 1997 approximately 13.1%, 41.3% and 46.6%,
respectively, of the Company's total revenue were derived from sales made to a
single customer.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist primarily of cash, trade
receivables, trade payables and bank debt. The carrying value of cash, trade
receivables and trade payables are considered to be representative of their
respective fair values, due to the short maturity of these instruments. The fair
value of bank debt approximates its carrying value based on the borrowing rates
currently available to the Company for bank loans with similar terms and
maturities.
PRESENTATION
Certain prior year information has been reclassified to conform to the 1997
presentation.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Of the
estimates and assumptions that affect reported results, the estimate of the
Company's oil and natural gas reserves, which is used to compute depreciation,
depletion, amortization and impairment on producing oil and gas properties, is
the most significant.
F-9
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT:
Long-term debt as of December 31, 1996 and 1997, consists of the following:
<TABLE>
<CAPTION>
1996 1997
------------- -------------
<S> <C> <C>
Line of credit agreement (a)............................................. $ 54,759,143 $ 53,725,403
Notes payable to majority stockholder (b)................................ -- 21,950,000
Note payable to General Electric Capital Corporation (c)................. -- 3,865,962
Capital lease agreements (d)............................................. -- 90,661
------------- -------------
Outstanding debt....................................................... 54,759,143 79,632,026
Less--Current portion.................................................... 3,422,447 315,113
------------- -------------
Total long-term debt................................................... $ 51,336,696 $ 79,316,913
------------- -------------
------------- -------------
</TABLE>
(a) The line of credit with a bank allows borrowings up to $75,000,000. The
Company has collateralized the loan with substantially all of its oil and
natural gas interests, and gathering, marketing and processing properties.
This loan bears interest at either Wall Street Journal Prime (8.5% at
December 31, 1997) or Adjusted LIBOR which includes the LIBOR rate (5.9% for
ninety day LIBOR at December 31, 1997) posted in the Wall Street Journal
adjusted for a capacity fee. The LIBOR rate can be locked in for thirty,
sixty or ninety days as determined by the Company through the use of various
principal tranches; or the Company can elect to leave the interest amount
based on the Prime interest rate. Interest is payable monthly on Prime
balances and at the expiration of LIBOR tranches with all outstanding
principal and interest due at maturity on December 31, 2000.
(b) Throughout 1997 (May to December), CRI and CGI entered into various notes
with the majority stockholder of the Company. These notes bear interest at
8.25% with interest payments due monthly or quarterly for twenty-four to
thirty-six months. On December 31, 1997, the notes between CRI and the
majority shareholder were combined into one note totaling $21,750,000
bearing interest at 8.25% with interest payments due on a quarterly basis
for twenty-four months. The balance is to be paid in full by December 31,
2002. The note between CGI and the majority shareholder bears interest at
8.25% with interest payments due on a quarterly basis for thirty-six months.
After the three-year period, the balance owed by CGI can be converted to an
amortization schedule payable by November 2002. Subsequent to December 31,
1997, the CGI note was paid in full.
(c) In July 1997, the Company borrowed $4,000,000 from General Electric Capital
Corporation to finance the purchase of an airplane. The note accrues
interest at 7.91% to be paid in one hundred nineteen (119) consecutive
monthly installments of principal and interest of $48,341 each and a final
installment of approximately $48,000. It is secured by the airplane.
(d) During 1997, the Company entered into two capital lease agreements to
purchase a copier and computer equipment. The agreements require monthly
payments of principal and interest for forty-two and sixty months,
respectively.
F-10
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT: (CONTINUED)
The annual maturities of debt subsequent to December 31, 1997, are as
follows:
<TABLE>
<S> <C>
1998................................................... $ 315,113
1999................................................... 338,423
2000................................................... 61,335,261
2001................................................... 7,711,569
2002 and thereafter.................................... 9,931,660
----------
Total maturities..................................... $79,632,026
----------
----------
</TABLE>
4. INCOME TAXES:
The Company follows Statement of Financial Accounting Standards ("SFAS") No.
109, "Accounting for Income Taxes." As mentioned in Note 2, effective June 1,
1997, the Company converted to an S-Corporation resulting in the taxable income
or loss of the Company from that date being reported to the shareholders and
included in their respective Federal and state income tax returns. Accordingly,
the deferred income tax assets and liabilities at May 31, 1997, were eliminated
through recording a provision for income tax benefit. The components of income
tax expense (benefit) are as follows:
<TABLE>
<CAPTION>
(IN THOUSANDS)
1995 1996 1997
--------- --------- ----------
<S> <C> <C> <C>
Current........................................................ $ 633 $ -- $ 3,038
Deferred....................................................... 1,619 8,238 (11,979)
--------- --------- ----------
Income tax expense (benefit)............................... $ 2,252 $ 8,238 $ (8,941)
--------- --------- ----------
--------- --------- ----------
</TABLE>
The provision for income taxes differs from an amount computed at the
statutory rates at December 31, as follows:
<TABLE>
<CAPTION>
(IN THOUSANDS)
1995 1996 1997
--------- --------- ----------
<S> <C> <C> <C>
Federal income tax at statutory rates.......................... $ 2,142 $ 7,547 $ 6,040
State income taxes............................................. 184 647 518
Statutory depletion............................................ (73) - -
Nondeductible expenses......................................... 4 21 30
Conversion to S-corporation.................................... - - (15,529)
Other.......................................................... (5) 23 -
--------- --------- ----------
Income tax expense (benefit)................................. $ 2,252 $ 8,238 $ (8,941)
--------- --------- ----------
--------- --------- ----------
</TABLE>
F-11
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES: (CONTINUED)
Deferred tax assets and (liabilities) at December 31, 1996, arising from
temporary differences between tax bases and the financial reporting carrying
amounts for certain assets and liabilities are as follows (in thousands):
<TABLE>
<S> <C>
Exploration and development costs................................. $ (11,532)
Alternative minimum tax carryforward.............................. 1,789
Investment tax credit carryforward................................ 717
Net operating loss carryforward................................... 1,836
Income between tax year end and December 31....................... (5,537)
Other............................................................. 748
---------
$ (11,979)
---------
---------
</TABLE>
The investment tax credit carryforward was utilized during the Company's tax
year ended May 31, 1997.
5. COMMITMENTS AND CONTINGENCIES:
The Company maintains a defined contribution pension plan for its employees
under which it contributes to the plan 4% of the annual compensation of all
employees at least 21 years old with a minimum of six months service. Pension
expense for the years ended December 31, 1995, 1996 and 1997, was approximately
$144,000, $152,000 and $242,000, respectively.
The Company and other affiliated companies participate jointly in a
self-insurance pool (the "Pool") covering health and workers' compensation
claims made by employees up to the first $50,000 and $500,000, respectively, per
claim. Any amounts paid above these are reinsured through third-party providers.
Premiums charged to the Company are based on estimated costs per employee of the
Pool. Premiums are expensed as incurred. No additional premium assessments are
anticipated for periods prior to December 31, 1997. Property and general
liability insurance is maintained through third-party providers with a $50,000
deductible on each policy.
The Company is involved in various legal proceedings in the normal course of
business, none of which, in the opinion of management, will have a material
adverse effect on the financial position or results of operations of the
Company. The Company has been successful in Federal courts in its lawsuit
against a gas purchaser arising from tortious interference with business
relations. A judgment was awarded for actual and punitive damages under the
Federal lawsuit totaling $30,269,000 plus accrued interest. In May 1996, this
decision was remanded by the U.S. Supreme Court back to the Tenth Circuit Court
of Appeals for further consideration. No amounts were included in the
accompanying financial statements for this judgment as the ultimate outcome was
uncertain at December 31, 1996. During 1997, this lawsuit was settled with an
aggregate judgment of $9,500,000 of which the Company's share was approximately
$7,500,000. It is included in other income in the accompanying statement of
operations for the year ended December 31, 1997.
Due to the nature of the oil and gas business, the Company is exposed to
possible environmental risks. The Company has implemented various policies and
procedures to avoid environmental contamination and risks from environmental
contamination. The Company is not aware of any material potential environmental
issues or claims.
F-12
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. RELATED PARTY TRANSACTIONS:
The Company, acting as operator on certain properties, utilizes affiliated
companies to provide oilfield services such as drilling and trucking. The total
amount paid to these companies, a portion of which is billed to other interest
owners, was approximately $5,899,000, $5,870,000 and $11,852,000 during the
years ended December 31, 1995, 1996 and 1997, respectively. These services are
provided at amounts which management believes approximate the costs which would
have been paid to an unrelated party for the same services. At December 31, 1996
and 1997, the Company owed approximately $826,000 and $1,094,000, respectively,
to these companies which is included in accounts payable and accrued liabilities
in the accompanying consolidated balance sheets. These companies and other
companies owned by the Company's majority stockholder also own interests in
wells operated by the Company. At December 31, 1996 and 1997, approximately
$461,000 and $336,000, respectively, from affiliated companies is included in
joint interest accounts receivable in the accompanying consolidated balance
sheets.
Beginning in 1996, a portion of the Company's Oklahoma, South Dakota, North
Dakota and Montana crude oil production sold by the Company to an unrelated
purchaser. In unrelated transactions, Independent Trading and Transportation
Company ("ITT") an affiliate of the Company, purchased, resold and traded crude
oil at various delivery points. The Company realized no gain or loss on
transactions by ITT.
During the years ended December 31, 1996 and 1997, the Company and CGI
advanced certain amounts to affiliates primarily for operating expenditures. The
advances outstanding to affiliates at December 31, 1996 and 1997, totaled
approximately $461,000 and $60,000, respectively. Interest income earned during
the years ended December 31, 1995, 1996 and 1997, was approximately $13,000,
$33,000 and $33,000, respectively, on advances to affiliates.
The Company leases office space under operating leases directly or
indirectly from the majority stockholder. Rents paid associated with these
leases totaled approximately $228,000, $232,000 and $294,000 for the years ended
December 31, 1995, 1996 and 1997, respectively.
During 1997, advances were made to the Company from the majority
stockholder. Interest paid or accrued during the year related to these advances
totaled approximately $744,000.
7. IMPAIRMENT OF LONG-LIVED ASSETS:
In March 1995, the Financial Accounting Standards Board issued SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of." The Company adopted SFAS No. 121 in the year ended December 31,
1996. During 1996 and 1997, the Company reviewed its oil and gas properties
which are maintained under the successful efforts method of accounting, to
identify properties with excess of net book value over projected future net
revenue of such properties. Any such excess net book values identified were
evaluated further considering such factors as future price escalation,
probability of additional oil and gas reserves and a discount to present value.
If an impairment was determined appropriate an additional charge was added to
depreciation, depletion and amortization ("DD&A") expense. The Company
recognized additional DD&A impairment in 1996 and 1997 of approximately
$2,100,000 and $5,000,000, respectively.
F-13
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. GUARANTOR SUBSIDIARIES
The Company's wholly owned subsidiaries have guaranteed the debt discussed
in Note 10. The following is a summary of the financial information of guarantor
subsidiaries as of December 31, 1997.
<TABLE>
<CAPTION>
1995 1996 1997
------------ ------------ ------------
<S> <C> <C> <C>
AS OF DECEMBER 31,
Current assets................................................ 9,227,642 3,093,829
Noncurrent assets............................................. 8,964,581 20,283,053
------------ ------------
Total assets................................................ 18,192,223 23,356,882
------------ ------------
------------ ------------
Current liabilities........................................... 8,278,045 11,043,405
Noncurrent liabilities........................................ 345,794 200,000
Stockholder's equity.......................................... 9,568,384 12,113,477
------------ ------------
Total liabilities and stockholder's equity.................. 18,192,223 23,356,882
------------ ------------
------------ ------------
FOR THE YEAR ENDED DECEMBER 31,
Total revenues................................................ 24,473,514 32,068,218 29,656,292
Operating costs and expenses.................................. 17,807,533 28,150,886 29,121,921
------------ ------------ ------------
Operating income............................................ 6,665,981 3,917,332 534,371
Other income and (expenses)................................... 19,971 95,055 (16,782)
Income tax benefit (expense).................................. (2,340,083) (1,404,336) 2,027,504
------------ ------------ ------------
Net income.................................................... 4,345,869 2,608,051 2,545,093
------------ ------------ ------------
------------ ------------ ------------
</TABLE>
At December 31, 1996 and 1997, current liabilities payable to CRI totaled
approximately $222,000 and $7,313,000, respectively. For the years ended
December 31, 1995, 1996 and 1997, depreciation, depletion and amortization,
included in operating costs, totaled approximately $766,000, $899,000 and
$1,560,000, respectively.
9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
PROVED OIL AND GAS RESERVES (UNAUDITED)
The following reserve information was developed from reserve reports as of
December 31, 1996 and 1997, prepared by independent reserve engineers and by the
Company's internal reserve engineers and set forth the changes in estimated
quantities of proved oil and gas reserves of the Company during each of the
three years presented. Information prior to December 31, 1996, was determined
from the Company's
F-14
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): (CONTINUED)
production, drilling, acquisition and sale data as applied to the December 31,
1996, reserve reports as reports on a December 31 year-end basis prior to 1996
were not available.
<TABLE>
<CAPTION>
CRUDE OIL AND
NATURAL GAS CONDENSATE
(MMCF) (BBLS IN THOUSANDS)
----------- -------------------
<S> <C> <C>
Proved reserves as of December 31, 1994........................................ 55,900 7,591
Revisions of previous estimates.............................................. -- --
Extensions, discoveries and other additions.................................. 4,747 4,150
Production................................................................... (5,880) (1,199)
Sale of minerals in place.................................................... -- --
Purchase of minerals in place................................................ 53 6,959
----------- ------
Proved reserves as of December 31, 1995........................................ 54,820 17,501
Revisions of previous estimates.............................................. -- --
Extensions, discoveries and other additions.................................. 2,232 4,874
Production................................................................... (6,527) (2,888)
Sale of minerals in place.................................................... (387) (236)
Purchase of minerals in place................................................ 397 241
----------- ------
Proved reserves as of December 31, 1996........................................ 50,535 19,492
Revisions of previous estimates.............................................. 3,640 6,731
Extensions, discoveries and other additions.................................. 2,903 2,072
Production................................................................... (5,789) (3,518)
Sale of minerals in place.................................................... (1,911) (58)
Purchase of minerals in place................................................ -- --
----------- ------
Proved reserves as of December 31, 1997........................................ 49,378 24,719
----------- ------
----------- ------
</TABLE>
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating quantities of proved
oil and gas reserves. Oil and gas reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be precisely
measured, and estimates of engineers other than the Company's might differ
materially from the estimates set forth herein. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing and
production subsequent to the date of the estimate may justify revision of such
estimate. Accordingly, reserve estimates are often different from the quantities
of oil and gas that are ultimately recovered.
Gas imbalance receivables and liabilities for each of the three years ended
December 31, 1995, 1996 and 1997, were not material and have not been included
in the reserve estimates.
F-15
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): (CONTINUED)
PROVED DEVELOPED OIL AND GAS RESERVES (UNAUDITED)
The following reserve information was developed by the Company and set forth
the estimated quantities of proved developed oil and gas reserves of the Company
as of the beginning of each year.
<TABLE>
<CAPTION>
CRUDE OIL AND
NATURAL GAS CONDENSATE
PROVED DEVELOPED RESERVES (MMCF) (BBLS IN THOUSANDS)
- ----------------------------------------------------------- ----------- -------------------
<S> <C> <C>
January 1, 1995 55,900 7,591
January 1, 1996 52,588 12,627
January 1, 1997 49,082 15,265
January 1, 1998 47,676 19,411
</TABLE>
Proved developed reserves are proved reserves which are expected to be
recovered through existing wells with existing equipment and operating methods.
COSTS INCURRED IN OIL AND GAS ACTIVITIES
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities during the year are shown below (in
thousands of dollars). Amounts are presented in accordance with SFAS No. 19, and
may not agree with amounts determined using traditional industry definitions.
<TABLE>
<CAPTION>
1995 1996 1997
--------- --------- ---------
<S> <C> <C> <C>
Property acquisition costs:
Proved............................................................... $ 16,293 $ 3,327 $ 476
Unproved............................................................. 14,697 6,085 4,641
--------- --------- ---------
Total property acquisition costs................................... 30,990 9,412 5,117
Exploration costs...................................................... 18,276 16,901 9,792
Development costs...................................................... 4,240 20,600 49,268
--------- --------- ---------
Total.............................................................. $ 53,506 $ 46,913 $ 64,177
--------- --------- ---------
--------- --------- ---------
</TABLE>
AGGREGATE CAPITALIZED COSTS
Aggregate capitalized costs relating to the Company's oil and gas producing
activities, and related accumulated DD&A, as of December 31 (in thousands of
dollars):
<TABLE>
<CAPTION>
1996 1997
---------- ----------
<S> <C> <C>
Unproved oil and gas properties................................................. $ 16,878 $ 17,047
Proved oil and gas properties................................................... 137,404 195,785
---------- ----------
Total......................................................................... 154,282 212,832
Less--Accumulated DD&A.......................................................... 51,282 82,157
---------- ----------
Net capitalized costs........................................................... $ 103,000 $ 130,675
---------- ----------
---------- ----------
</TABLE>
F-16
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): (CONTINUED)
OIL AND GAS OPERATIONS (UNAUDITED)
Aggregate results of operations for each period ended December 31, in
connection with the Company's oil and gas producing activities are shown below
(in thousands of dollars):
<TABLE>
<CAPTION>
1995 1996 1997
--------- --------- ---------
<S> <C> <C> <C>
Revenues............................................................... $ 30,576 $ 75,016 $ 78,599
Production costs....................................................... 7,611 19,338 20,748
Exploration expenses................................................... 6,184 4,512 6,806
DD&A and valuation provision*.......................................... 8,999 21,635 30,202
--------- --------- ---------
Income................................................................. 7,782 29,531 20,843
Income tax expense**................................................... 2,957 11,222 3,300
--------- --------- ---------
Results of operations from producing activities (excluding corporate
overhead and interest costs)......................................... $ 4,825 $ 18,309 $ 17,543
--------- --------- ---------
--------- --------- ---------
</TABLE>
- --------------------------
* Includes $2.1 million and $5 million in 1996 and 1997, respectively, of
additional DD&A as a result of adoption of SFAS No. 121.
** The 1997 income tax provision was computed based on estimated oil and gas
operations income for the five months ended May 31, 1997, times the
estimated effective income tax rate. The Company's S-Corporation status was
effective June 1, 1997.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES (UNAUDITED)
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 1995, 1996, and 1997 as required by Financial Accounting
Standards Board's Statement of Financial Accounting Standards No. 69. The
Standard requires the use of a 10 percent discount rate. This information is not
the fair market value nor does it represent the expected present value of future
cash flows of the Company's proved oil and gas reserves (in thousands of
dollars).
<TABLE>
<CAPTION>
1995 1996 1997
----------- ----------- -----------
<S> <C> <C> <C>
Future cash inflows.............................................. $ 619,081 $ 612,158 $ 576,330
Future production and development costs.......................... (213,752) (191,947) (189,520)
Future income tax expenses....................................... (145,620) (141,487) --
----------- ----------- -----------
Future net cash flows............................................ 259,709 278,724 386,810
10% annual discount for estimated timing of cash flows........... (105,182) (101,591) (145,185)
----------- ----------- -----------
Standardized measure of discounted future net cash flows......... $ 154,527 $ 177,133 $ 241,625
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
Future cash inflows are computed by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves. The year-end weighted average oil price utilized in the computation of
future cash inflows was approximately $18.06 per BBL at December 31, 1997 and
$23.00 per BBL at December 31, 1995 and 1996. The year-end weighted average gas
price utilized in the computation of future cash inflows was approximately $2.25
per MCF at December 31, 1997 and $3.28 per MCF at December 31, 1995 and 1996.
F-17
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): (CONTINUED)
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Company's proved oil and gas reserves at the end
of the year, based on year-end costs, and assuming continuation of existing
economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates to the future pretax net cash flows relating to the
Company's proved oil and gas reserves, less the tax bases of the properties
involved. The future income tax expenses give effect to tax credits and
allowances, but do not reflect the impact of general and administrative costs
and exploration expenses of ongoing operations relating to the Company's proved
oil and gas reserves. Income taxes were not computed at December 31, 1997, as
the Company elected S-Corporation status effective June 1, 1997.
Principal changes in the aggregate standardized measure of discounted future
net cash flows attributable to the Company's proved oil and gas reserves at
year-end are shown below (in thousands of dollars):
<TABLE>
<CAPTION>
1995 1996 1997
---------- ---------- ----------
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows at the
beginning of the year............................................ $ 126,687 $ 154,527 $ 177,133
Extensions, discoveries and improved recovery, less related
costs............................................................ 23,489 28,815 16,352
Revisions of previous quantity estimates........................... -- -- 58,001
Changes in estimated future development costs...................... -- -- (36,901)
Purchases/sales of minerals in place............................... 27,615 -- (3,233)
Net changes in prices and production costs......................... -- -- (51,456)
Accretion of discount.............................................. 12,669 15,453 17,713
Sales of oil and gas produced, net of production costs............. (22,965) (55,678) (57,851)
Development costs incurred during the period....................... -- 23,212 32,474
Net change in income taxes......................................... (15,787) 3,200 89,915
Change in timing of estimated future production, and other......... 2,819 7,604 (522)
---------- ---------- ----------
Standardized measure of discounted future net cash flows at the end
of the year...................................................... $ 154,527 $ 177,133 $ 241,625
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
The standardized measure and changes in standardized measure prior to
December 31, 1996, were determined from production, drilling, acquisition and
sale records of the Company applied to the reserve reports as of December 31,
1996, without revision for oil and gas price assumptions.
10. SUBSEQUENT EVENTS (UNAUDITED):
On May 8, 1998, the Company incorporated Continental Crude Co., a wholly
owned subisidiary. Since its incorporation, Continental Crude Co. has had no
operations, has acquired no assets and has incurred no liabilities.
On May 18, 1998, the Company consummated the purchase of approximately
$86,500,000 of producing and non-producing oil and gas properties and certain
other related assets in the Worland Field (the "Worland Field Properties")
effective as of June 1, 1998, which the Company funded through borrowings
F-18
<PAGE>
CONTINENTAL RESOURCES, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUBSEQUENT EVENTS (UNAUDITED): (CONTINUED)
on its line of credit. Subsequently, and effective June 1, 1998, the Company
sold an undivided 50% interest in the Worland Field Properties (excluding
inventory and certain equipment) to the Company's principal stockholder for
approximately $42.6 million. Of the total sale price to the stockholder,
approximately $23.0 million plus interest of approximately $0.3 million was
offset against the outstanding balance of notes payable to the stockholder and
approximately $19.6 million was recorded as an increase in advances to
affiliates in the accompanying June 30, 1998 consolidated condensed balance
sheet.
In May 1998, the Company entered into a forward interest rate swap contract
to hedge its exposure to changes in prevailing interest rates on the anticipated
debt offering described in the following paragraph. Due to changes in treasury
note rates, the Company paid $3.9 million to settle the forward interest rate
swap contract. This payment will result in an increase of approximately 0.5% to
the Company's effective interest rate or an increase in interest expense of
approximately $0.4 million per year over the next 10 years.
On July 24, 1998, the Company issued $150 million of 10 1/4% Senior
Subordinated Notes due August 1, 2008 (the "Notes") in a private transaction
under Securities Act Rule 144A. In connection with the issuance of the Notes,
the Company incurred debt issuance costs of approximately $4.6 million, which
has been capitalized as other assets and is being amortized on a straight-line
basis over the life of the Notes.
On July 24, 1998, the outstanding balance under the line of credit of
approximately $162.8 million was repaid using approximately $19.6 million in
proceeds received from the principal stockholder relating to the sale of a 50%
undivided interest in the Worland Properties and approximately $143.2 million in
proceeds from the Notes. Upon issuance of the Notes and payment of the
outstanding balance under the line of credit, the line of credit was amended to
allow borrowings up to $75.0 million.
F-19
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Continental Resources, Inc.:
We have audited the accompanying statements of revenues and direct operating
expenses of the oil and gas properties included in the Purchase Agreement
between Continental Resources Inc. and Bass Enterprises Production Co. (the
"Properties") for the three years in the period ended December 31, 1997. These
statements are the responsibility of Continental Resources management. Our
responsibility is to express an opinion on these statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statements of revenues and direct
operating expenses are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statements of revenues and direct operating expenses. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
The accompanying statements of revenues and direct operating expenses were
prepared in connection with the purchase of the Properties and, as described in
Note 1, exclude general and administrative expenses, depreciation, depletion and
amortization, interest, income tax expenses, and other items as these expenses
would not be comparable to those resulting from the proposed future operations
of the Properties.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of the Properties for the three years in the period
ended December 31, 1997.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
June 4, 1998
F-20
<PAGE>
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF OIL AND GAS PROPERTIES INCLUDED IN THE PURCHASE AGREEMENT BETWEEN
CONTINENTAL RESOURCES, INC. AND BASS ENTERPRISES PRODUCTION CO.
<TABLE>
<CAPTION>
FOR THE SIX
FOR THE YEARS ENDED DECEMBER 31, MONTHS ENDED FOR THE FIVE
------------------------------------------ JUNE 30, MONTHS ENDED
1995 1996 1997 1997 MAY 31, 1998
------------ ------------- ------------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES:
Oil sales.............................. $ 9,002,941 $ 13,463,786 $ 9,993,174 $ 5,605,242 $ 1,883,222
Gas sales.............................. 189,592 110,020 132,750 63,297 243,345
------------ ------------- ------------- ------------ ------------
Total revenues....................... 9,192,533 13,573,806 10,125,924 5,668,539 2,126,567
DIRECT OPERATING EXPENSES:
Production and operating expenses...... 3,634,950 4,845,364 5,209,488 3,109,314 1,268,409
------------ ------------- ------------- ------------ ------------
REVENUES IN EXCESS OF DIRECT OPERATING
EXPENSES............................... $ 5,557,583 $ 8,728,442 $ 4,916,436 $ 2,559,225 $ 858,150
------------ ------------- ------------- ------------ ------------
------------ ------------- ------------- ------------ ------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-21
<PAGE>
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF OIL AND GAS PROPERTIES INCLUDED IN THE PURCHASE AGREEMENT BETWEEN
CONTINENTAL RESOURCES, INC. AND BASS ENTERPRISES PRODUCTION CO.
1. BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION
The accompanying statements present revenues and direct operating expenses
of working and royalty interests in oil and gas properties located near the town
of Worland in the Bighorn Basin of Wyoming included in the Purchase Agreement
between Continental Resources, Inc. ("Continental") and Bass Enterprises
Production Co., adjusted for Continental's sale of a 50% interest in the oil and
gas properties to Continental's majority shareholder (the "Properties").
The accompanying statements of revenues and direct operating expenses were
prepared on the accrual basis of accounting and relate only to the Properties
described above. These historical results may not be indicative of future
operations. The statements do not include general and administrative expenses,
interest, depreciation, depletion and amortization, Federal and state income
taxes and other items because such amounts would not be indicative of those
expenses which will be incurred by Continental.
The unaudited statements of revenues and direct operating expenses for the
six month period ended June 30, 1997 and the five month period ended May 31,
1998, in the opinion of Continental management, were prepared on a basis
consistent with the audited statements of revenues and direct operating expenses
of the Properties for the three years in the period ended December 31, 1997, and
include all adjustments, consisting only of normal recurring accruals, necessary
to present fairly the revenues and direct operating expenses for the indicated
periods. The statement of revenues and direct operating expenses for the five
month period ended May 31, 1998 represents the revenues and direct operating
expenses of the Properties up to the time of their acquisition by Continental on
June 1, 1998.
USE OF ESTIMATES
The preparation of the statements of revenues and direct operating expenses
in conformity with generally accepted accounting principles requires Continental
to make estimates and assumptions that affect the reported amounts of revenues
and direct operating expenses during the reporting periods. Actual results could
differ from those estimates as additional information becomes available.
CONCENTRATION OF REVENUE AND LIMITED NUMBER OF CUSTOMERS
Approximately 84%, 78% and 75% of revenues were derived from one property
during 1995, 1996 and 1997, respectively. In addition, virtually all of the
production of the properties was purchased by three purchasers during the
periods.
2. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
PROVED OIL AND GAS RESERVES (UNAUDITED)
The following reserve information was developed from reserve reports as of
January 1, 1998, prepared by independent reserve engineers and set forth the
changes in estimated quantities of proved oil and gas reserves of the Properties
during each of the three years presented. Information prior to January 1, 1998,
F-22
<PAGE>
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF OIL AND GAS PROPERTIES INCLUDED IN THE PURCHASE AGREEMENT BETWEEN
CONTINENTAL RESOURCES, INC. AND BASS ENTERPRISES PRODUCTION CO. (CONTINUED)
2. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): (CONTINUED)
was determined from production and drilling as applied to the January 1, 1998,
reserve reports as reports prior to January 1, 1998, were not available.
<TABLE>
<CAPTION>
CRUDE OIL AND
NATURAL GAS CONDENSATE
(MMCF) (BBLS IN THOUSANDS)
----------- -------------------
<S> <C> <C>
Proved reserves as of December 31, 1994.............................. 29,791 26,783
Extensions, discoveries and other additions........................ -- 592
Production......................................................... (367) (565)
----------- ------
Proved reserves as of December 31, 1995.............................. 29,424 26,810
Extensions, discoveries and other additions........................ 177 1,119
Production......................................................... (521) (675)
----------- ------
Proved reserves as of December 31, 1996.............................. 29,080 27,254
Extensions, discoveries and other additions........................ -- 622
Production......................................................... (610) (628)
----------- ------
Proved reserves as of December 31, 1997.............................. 28,470 27,248
----------- ------
----------- ------
</TABLE>
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
There are numerous uncertainties inherent in estimating quantities of proved
oil and gas reserves. Oil and gas reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be precisely
measured, and estimates of other engineers might differ materially from the
estimates set forth herein. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing and production
subsequent to the date of the estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered.
PROVED DEVELOPED OIL AND GAS RESERVES (UNAUDITED)
The following reserve information was developed by Continental and set forth
the estimated quantities of proved developed oil and gas reserves of the
Properties as of the beginning of each year.
<TABLE>
<CAPTION>
CRUDE OIL AND
NATURAL GAS CONDENSATE (BBLS IN
PROVED DEVELOPED RESERVES (MMCF) THOUSANDS)
- --------------------------------------------------------------------- ----------- -------------------
<S> <C> <C>
January 1, 1995...................................................... 13,889 10,879
January 1, 1996...................................................... 13,699 10,906
January 1, 1997...................................................... 13,355 11,350
January 1, 1998...................................................... 12,565 11,344
</TABLE>
F-23
<PAGE>
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF OIL AND GAS PROPERTIES INCLUDED IN THE PURCHASE AGREEMENT BETWEEN
CONTINENTAL RESOURCES, INC. AND BASS ENTERPRISES PRODUCTION CO. (CONTINUED)
2. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): (CONTINUED)
Proved developed reserves are proved reserves which are expected to be
recovered through existing wells with existing equipment and operating methods.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES (UNAUDITED)
The following information is based on Continental's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 1995, 1996, and 1997 as required by Financial Accounting
Standards Board's Statement of Financial Accounting Standards No. 69. The
Standard requires the use of a 10 percent discount rate. This information is not
the fair market value nor does it represent the expected present value of future
cash flows of Continental's proved oil and gas reserves (in thousands of
dollars).
<TABLE>
<CAPTION>
1995 1996 1997
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows................................................ $ 361,538 $ 348,847 $ 339,212
Future production and development costs............................ 204,874 192,407 180,945
---------- ---------- ----------
Future net cash flows.............................................. 156,664 156,440 158,267
10% annual discount for estimated timing of cash flows............. 137,116 135,184 132,876
---------- ---------- ----------
Standardized measure of discounted future net cash flows........... $ 19,548 $ 21,256 $ 25,391
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
Future cash inflows are computed by applying year-end prices of oil and gas
relating to the Properties' proved reserves to the year-end quantities of those
reserves. The year-end weighted average oil price utilized in the computation of
future cash inflows was approximately $11.44 per BBL at December 31, 1995, 1996
and 1997. The year-end weighted average gas price utilized in the computation of
future cash inflows was approximately $1.00 per MCF at December 31, 1995, 1996
and 1997.
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Properties' proved oil and gas reserves at the
end of the year, based on year-end 1997 costs, and assuming continuation of
existing economic conditions.
F-24
<PAGE>
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF OIL AND GAS PROPERTIES INCLUDED IN THE PURCHASE AGREEMENT BETWEEN
CONTINENTAL RESOURCES, INC. AND BASS ENTERPRISES PRODUCTION CO. (CONTINUED)
2. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED): (CONTINUED)
Principal changes in the aggregate standardized measure of discounted future
net cash flows attributable to the Properties' proved oil and gas reserves at
year-end are shown below (in thousands of dollars):
<TABLE>
<CAPTION>
1995 1996 1997
---------- ---------- ----------
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows at the
beginning of the year............................................ $ 16,715 $ 19,548 $ 21,256
Extensions, discoveries and improved recovery, less related
costs............................................................ 468 884 491
Accretion of discount.............................................. 1,778 1,932 2,308
Sales of oil and gas produced, net of production costs............. (5,558) (8,729) (4,917)
Development costs incurred during the period....................... 6,145 7,621 6,253
---------- ---------- ----------
Standardized measure of discounted future net cash flows at the end
of the year...................................................... $ 19,548 $ 21,256 $ 25,391
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
The standardized measure and changes in standardized measure prior to
December 31, 1997, were determined from production and drilling records of the
Properties applied to the reserve reports as of January 1, 1998, without
revision for oil and gas price assumptions.
F-25
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
As permitted by the Oklahoma General Corporation Act under which the Company
is incorporated, the Company's Certificate of Incorporation, as amended,
provides for indemnification of each of the Company's officers and directors
against (a) expenses, including attorney's fees, judgments, fines and amounts
paid in settlement actually and reasonably incurred by him in connection with
any action, suit or proceeding brought by reason of his being or having been a
director, officer, employee or agent of the Company, or of any other
corporation, partnership, joint venture, or other enterprise at the request of
the Company, other than an action by or in the right of the Company, provided
that he acted in good faith and in a manner he reasonably believed to be in the
best interest of the Company, and with respect to any criminal action, he had no
reasonable cause to believe that his conduct was unlawful and (b) expenses
(including attorney's fees) actually and reasonably incurred by him in
connection with the defense or settlement of any action or suit by or in the
right of the Company brought by reason of his being or having been a director,
officer, employee or agent of the Company, or any other corporation,
partnership, joint venture, or other enterprise at the request of the Company,
provided that he acted in good faith and in a manner he reasonably believed to
be in or not opposed to the best interest of the Company; except that no
indemnification shall be made in respect of any claim, issue or matter as to
which such person shall have been adjudged liable to the Company, unless and
only to the extent that the court in which such action or suit was decided has
determined that the person is fairly and reasonably entitled to indemnification
for such expenses which the court shall deem proper. The Company's bylaws
provide for similar indemnification. These provisions may be sufficiently broad
to indemnify such persons for liabilities arising under the Securities Act of
1933, as amended.
The Company's directors and officers are also insured against claims arising
out of the performance of their duties in such capacities.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBERS DESCRIPTION
- ----------- ----------------------------------------------------------------------------------------------
<S> <C>
3.1 Registrant's Certificate of Incorporation, as amended and restated
3.2 Registrant's Bylaws, as amended and restated
3.3 Certificate of Incorporation of Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as amended and restated
3.5 Certificate of Incorporation of Continental Crude Co.
3.6 Bylaws of Continental Crude Co.
4.1 Restated Credit Agreement dated May 12, 1998 among Continental Resources, Inc. and Continental
Gas, Inc., as Borrowers and Bank One, Oklahoma, N.A. and the Institutions named therein as
Banks and Bank One, Oklahoma, N.A., as Agent (the "Credit Agreement")
4.2 Form of Revolving Note under the Credit Agreement
4.3 Indenture dated as of July 24, 1998 between the Registrant, as Issuer, the Subsidiary
Guarantors named therein and United States Trust Company of New York, as Trustee
4.4 Exchange and Registration Rights Agreement dated July 24, 1998 between the Registrant, the
Subsidiary Guarantors named therein and Chase Securities, Inc.
5 Opinion of McAfee & Taft A Professional Corporation
</TABLE>
II-1
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBERS DESCRIPTION
- ----------- ----------------------------------------------------------------------------------------------
<S> <C>
10.1 Purchase and Sale Agreement dated March 28, 1998 by and between Bass Enterprises Production
Co., et al. as Sellers and Continental Resources, Inc. as Buyer
10.2 Worland Area Purchase and Sale Agreement, as amended, dated June 25, 1998 by and between
Continental Resources, Inc. as Seller and Harold G. Hamm, Trustee of the Harold G. Hamm
Revocable Intervivos Trust dated April 23, 1984 as Buyer
12.1 Statement re computation of ratio of debt to EBITDA
12.2 Statement re computation of ratio of earnings to fixed charges
12.3 Statement re computation of ratio of EBITDA to interest expense
21 Subsidiaries
23.1 Consent of McAfee & Taft A Professional Corporation is contained in Exhibit 5 hereto
23.2* Consent of Arthur Andersen LLP
23.3* Consent of Ryder Scott Company Petroleum Engineers
24 Power of Attorney
25 Statement of eligibility of Trustee
27 Financial Data Schedule
99.1 Letter of Transmittal
99.2 Notice of Guarantee of Delivery
99.3 Company letter
99.4 Client letter
99.5 Guidelines for certification of taxpayer identification number
</TABLE>
- ------------------------
* Filed herewith.
(b) Financial Statement Schedules
None
ITEM 22. UNDERTAKINGS.
The undersigned Registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made,
a post-effective amendment to this Registration Statement:
(i) To include any prospectus required by section 10(a)(3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after
the effective date of the Registration Statement (or the most recent
post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set forth in
the Registration Statement;
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in the Registration Statement or
any material change to such information in the Registration Statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at the time shall be deemed to
be the initial bona fide offering thereof.
II-2
<PAGE>
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.
The undersigned Registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Items 4, 10(b), 11 or 13 of this Form, within one business day of receipt of
such request, and to send the incorporated documents by first class mail or
other equally prompt means. This includes information contained in documents
filed subsequent to the effective date of the Registration Statement through the
date of responding to the request.
The undersigned Registrant hereby undertakes to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in the Registration Statement when it became effective.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
Registration pursuant to the provisions described under Item 20, or otherwise,
the Registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnifications against public policy as expressed in
the Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
Registrant of expenses incurred or paid by a director, officer or controlling
person of the Registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the Registrant will, unless in
the opinion of its counsel the matter has been settled by controlling precedent,
submit a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Act and will
be governed by the final adjudication of such issue.
II-3
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Amendment to the Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma
City, State of Oklahoma, on November 9, 1998.
<TABLE>
<S> <C> <C>
CONTINENTAL RESOURCES, INC.
By: /s/ HAROLD HAMM
-----------------------------------------
Harold Hamm
CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF
EXECUTIVE OFFICER
</TABLE>
Pursuant to the requirements of the Securities Act of 1933, this Amendment
to the Registration Statement has been signed by the following persons in the
capacities indicated on November 9, 1998.
<TABLE>
<CAPTION>
NAME TITLE
- ------------------------------ --------------------------
<C> <S> <C>
Chairman of the Board,
/s/ HAROLD HAMM President and Chief
- ------------------------------ Executive Officer
Harold Hamm (Principal Executive
Officer) and Director
/s/ JACK H. STARK
- ------------------------------ Senior Vice President and
Jack H. Stark Director
Senior Vice President,
Treasurer and Chief
/s/ ROGER V. CLEMENT Financial Officer
- ------------------------------ (Principal Financial and
Roger V. Clement Accounting Officer) and
Director
/s/ JEFF HUME
- ------------------------------ Senior Vice President,
Jeff Hume Director
/s/ RANDY MOEDER Senior Vice President,
- ------------------------------ General Counsel,
Randy Moeder Secretary and Director
</TABLE>
II-4
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the following
additional Registrant has duly caused this Amendment to the Registration
Statement to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Oklahoma City, State of Oklahoma, on November 9,
1998.
<TABLE>
<S> <C> <C>
CONTINENTAL GAS, INC.
By: /s/ HAROLD HAMM
-----------------------------------------
Harold Hamm
CHAIRMAN OF THE BOARD AND CHIEF EXECUTIVE
OFFICER
</TABLE>
Pursuant to the requirements of the Securities Act of 1933, this Amendment
to the Registration Statement has been signed by the following persons in the
capacities indicated on November 9, 1998.
SIGNATURE TITLE
- ------------------------------ ----------------------------------------
/s/ HAROLD HAMM Chairman of the Board, Chief Executive
- ------------------------------ Officer (Principal Executive Officer)
Harold Hamm and Director of Continental Gas, Inc.
/s/ RANDY MOEDER
- ------------------------------ President and Director of Continental
Randy Moeder Gas, Inc.
Assistant Secretary and Chief Financial
/s/ ROGER V. CLEMENT Officer (Principal Financial Officer
- ------------------------------ and Principal Accounting Officer) of
Roger V. Clement Continental Gas, Inc.
II-5
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the following
additional Registrant has duly caused this Amendment to the Registration
Statement to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Oklahoma City, State of Oklahoma, on November 9,
1998.
<TABLE>
<S> <C> <C>
CONTINENTAL CRUDE CO.
By: /s/ JEFF WHITE
-----------------------------------------
Jeff White
PRESIDENT AND CHIEF EXECUTIVE OFFICER
</TABLE>
Pursuant to the requirements of the Securities Act of 1933, this Amendment
to the Registration Statement has been signed by the following persons in the
capacities indicated on November 9, 1998.
SIGNATURE TITLE
- ------------------------------ ----------------------------------------
/s/ JEFF WHITE President, Chief Executive Officer
- ------------------------------ (Principal Executive Officer) and
Jeff White Director of Continental Crude Co.
Treasurer and Chief Financial Officer
/s/ ROGER V. CLEMENT (Principal Financial Officer and
- ------------------------------ Principal Accounting Officer) and
Roger V. Clement Director of Continental Crude Co.
/s/ RANDY MOEDER
- ------------------------------ Secretary
Randy Moeder
II-6
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBERS DESCRIPTION
- ----------- ----------------------------------------------------------------------------------------------
<S> <C>
3.1 Registrant's Certificate of Incorporation, as amended and restated
3.2 Registrant's Bylaws, as amended and restated
3.3 Certificate of Incorporation of Continental Gas, Inc.
3.4 Bylaws of Continental Gas, Inc., as amended and restated
3.5 Certificate of Incorporation of Continental Crude Co.
3.6 Bylaws of Continental Crude Co.
4.1 Restated Credit Agreement dated May 12, 1998 among Continental Resources, Inc. and Continental
Gas, Inc., as Borrowers and Bank One, Oklahoma, N.A. and the Institutions named therein as
Banks and Bank One, Oklahoma, N.A., as Agent (the "Credit Agreement")
4.2 Form of Revolving Note under the Credit Agreement
4.3 Indenture dated as of July 24, 1998 between the Registrant, as Issuer, the Subsidiary
Guarantors named therein and United States Trust Company of New York, as Trustee
4.4 Exchange and Registration Rights Agreement dated July 24, 1998 between the Registrant, the
Subsidiary Guarantors named therein and Chase Securities, Inc.
5 Opinion of McAfee & Taft A Professional Corporation
10.1 Purchase and Sale Agreement dated March 28, 1998 by and between Bass Enterprises Production
Co., et al. as Sellers and Continental Resources, Inc. as Buyer
10.2 Worland Area Purchase and Sale Agreement, as amended, dated June 25, 1998 by and between
Continental Resources, Inc. as Seller and Harold G. Hamm, Trustee of the Harold G. Hamm
Revocable Intervivos Trust dated April 23, 1984 as Buyer
12.1 Statement re computation of ratio of debt to EBITDA
12.2 Statement re computation of ratio of earnings to fixed charges
12.3 Statement re computation of ratio of EBITDA to interest expense
21 Subsidiaries
23.1 Consent of McAfee & Taft A Professional Corporation is contained in Exhibit 5 hereto
23.2* Consent of Arthur Andersen LLP
23.3* Consent of Ryder Scott Company Petroleum Engineers
24 Power of Attorney
25 Statement of eligibility of Trustee
27 Financial Data Schedule
99.1 Letter of Transmittal
99.2 Notice of Guarantee of Delivery
99.3 Company letter
99.4 Client letter
99.5 Guidelines for certification of taxpayer identification number
</TABLE>
- ------------------------
* Filed herewith.
<PAGE>
EXHIBIT 23.2
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use of our report
dated April 22, 1998, on the consolidated financial statements of Continental
Resources, Inc. and subsidiary and our report dated June 4, 1998, on the
Statements of Revenues and Direct Operating Expenses of Oil and Gas Properties
included in the Purchase Agreement Between Continental Resources, Inc. and Bass
Enterprises Production Co. and to all references to our Firm included Amendment
2 to this registration statement.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
November 6, 1998
<PAGE>
EXHIBIT 23.3
CONSENT OF RYDER SCOTT COMPANY PETROLEUM ENGINEERS
As independent petroleum engineers, we hereby consent to the use of our review
and all references to our firm included or made a part of the Registration
Statement of Continental Resources, Inc. and its subsidiaries on Form S-4.
/s/ RYDER SCOTT COMPANY PETROLEUM ENGINEERS
---------------------------------------------------
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
Denver, Colorado
November 5, 1998
