As filed with the Securities and Exchange Commission on November 22, 2002.
Registration Nos. 333-100735
100735-01
100735-03
100735-04
100735-05
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------
Amendment No. 1 to
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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PLAINS EXPLORATION & PRODUCTION COMPANY
PLAINS E&P COMPANY
(Exact name of registrant as specified in its charter)
Delaware 1311 33-0430755
Delaware 1311 74-3050622
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification No.)
500 Dallas Street, Suite 700
Houston, Texas 77002
(713) 739-6700
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
Timothy T. Stephens
Executive Vice President of Administration, Secretary and General Counsel
500 Dallas Street, Suite 700
Houston, Texas 77002
Telephone: (713) 739-6700
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
Copies to:
Michael E. Dillard, P.C.
Julien R. Smythe, Esq.
Richard J. Wilkie, Esq.
Akin Gump Strauss Hauer & Feld LLP
1900 Pennzoil Place, South Tower
711 Louisiana Street, Suite 1900 - South Tower
Houston, Texas 77002
Telephone: (713) 220-5800
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Approximate date of commencement of proposed sale to the public: As soon as
practicable after the effective date of this Registration Statement.
If any of 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 statement 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 number of the earlier effective registration statement
for the same offering. [_] ____________
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Each Registrant hereby amends this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrants
shall file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) 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(a),
may determine.
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Table of Additional Registrant Guarantors
State or Other I.R.S.
Jurisdiction of Employer
Incorporation or Identification
Exact Name of Registrant Guarantor(1) Organization Number
------------------------------------- ---------------- --------------
Arguello Inc........................ Delaware 76-0608465
Plains Illinois Inc................. Delaware 76-0487569
Plains Resources International Inc.. Delaware 76-0040974
PMCT Inc............................ Delaware 76-0410281
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(1) The address for each Registrant Guarantor is 500 Dallas Street, Suite 700,
Houston, Texas 77002, and the telephone number at that address is (713)
739-6700.
The information in this prospectus is not complete and may be changed. We may
not exchange these securities until the registration statement relating to
these securities filed with the Securities and Exchange Commission is
effective. This prospectus is not an offer to sell these securities and is not
soliciting an offer to buy these securities in any state where the offer or
sale is not permitted.
Subject to Completion, Dated November 22, 2002
PLAINS EXPLORATION & PRODUCTION COMPANY
PLAINS E&P COMPANY
$200,000,000
Offer to Exchange
8 3/4% Series B Senior Subordinated Notes Due 2012 for any and all outstanding
8 3/4% Series A Senior Subordinated Notes due 2012
CUSIP: 726507AA4, 726507AB2 and U72597AA2
This prospectus and accompanying letter of transmittal relate to our
proposed exchange offer. We are offering to exchange up to $200,000,000
aggregate principal amount of new 83/4% Series B senior subordinated notes due
2012, which we call the Series B notes, which will be freely transferable, for
any and all outstanding 83/4% Series A senior subordinated notes due 2012,
which we call the Series A notes, issued in a private offering on July 3, 2002
and which have certain transfer restrictions. In this prospectus, we sometimes
refer to the Series A notes and the Series B notes collectively as the notes.
The notes are unsecured and subordinated to all our existing and future
senior debt, rank equally with all our other senior subordinated debt and rank
senior to all our existing and future senior debt. As of September 30, 2002 we
did not have, and the notes were not senior to, any outstanding subordinated
debt. The notes are fully and unconditionally guaranteed on a senior
subordinated basis by all of our existing and future domestic restricted
subsidiaries.
. The exchange offer expires at 5:00 p.m., New York City time, on
unless extended.
. The terms of the Series B notes are substantially identical to the terms
of the Series A notes, except that the Series B notes will be freely
transferable and issued free of any covenants regarding exchange and
registration rights.
. All Series A notes that are validly tendered and not validly withdrawn
will be exchanged.
. Tenders of Series A notes may be withdrawn at any time prior to
expiration of the exchange offer.
. We will not receive any proceeds from the exchange offer.
. The exchange of Series A notes for Series B notes will not be a taxable
event for United States federal income tax purposes.
. Holders of Series A notes do not have any appraisal or dissenters' rights
in connection with the exchange offer.
. Series A notes not exchanged in the exchange offer will remain
outstanding and be entitled to the benefits of the Indenture, but except
under certain circumstances, will have no further exchange or
registration rights.
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Please see "Risk Factors" beginning on page 13 for a discussion of factors
you should consider in connection with the exchange offer.
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Neither the Securities and Exchange Commission nor any other state
securities commission has approved or disapproved of the notes or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.
The date of this prospectus is , 2002.
In making your investment decision, you should rely only on the information
contained in this prospectus. We have not authorized anyone to provide you with
any other information. If you receive any other information, you should not
rely on it. We are offering to exchange the Series B notes for all outstanding
Series A notes only in places where offers and sales are permitted. You should
not assume that the information contained in this prospectus is accurate as of
any date other than the date on the front cover of this prospectus.
Table of Contents
Page
----
Summary................................ 1
Risk Factors........................... 13
Statement Regarding Forward-Looking
Statements........................... 26
The Exchange Offer..................... 27
Use of Proceeds........................ 39
Capitalization......................... 40
Selected Historical Consolidated and
Combined Financial and Other Data.... 41
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... 43
Business............................... 60
Management............................. 77
Principal Stockholder.................. 86
Page
----
Certain Transactions..................... 87
Description of Certain Other Indebtedness 96
Description of Notes..................... 98
Material U.S. Federal Income Tax
Consequences........................... 148
Certain ERISA Considerations.............
Plan of Distribution..................... 152
Validity of the Series B Notes........... 153
Experts.................................. 153
Where You Can Find More Information...... 153
Glossary of Oil and Gas Terms............ 154
Index to Financial Statements............ F-1
Annex A Letter of Transmittal............ A-1
Annex B Notice of Guaranteed Delivery.... B-1
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In this prospectus, "Plains Exploration & Production," "we," "us" and "our"
refer to Plains Exploration & Production Company and its subsidiaries,
including Plains E&P Company. On September 18, 2002 we converted from a
California limited partnership named Plains Exploration & Production Company,
L.P. to a Delaware corporation named Plains Exploration & Production Company.
This conversion did not materially change your rights as a noteholder. Unless
otherwise indicated, financial information included in this prospectus is
presented on a historical basis.
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Notice to New Hampshire Residents
Neither the fact that a registration statement or an application for a
license has been filed under RSA 421-B with the State of New Hampshire nor the
fact that a security is effectively registered or a person is licensed in the
State of New Hampshire constitutes a finding by the Secretary of State that any
document filed under RSA 421-B is true, complete and not misleading. Neither
any such fact nor the fact that an exemption or exception is available for a
security or a transaction means that the Secretary of State has passed in any
way upon the merits or qualifications of, or recommended or given approval to,
any person, security or transaction. It is unlawful to make, or cause to be
made, to any prospective purchaser, customer or client any representation
inconsistent with the provisions of this paragraph.
i
SUMMARY
This summary highlights information contained elsewhere in this prospectus.
Although this discussion summarizes the material information contained in this
prospectus, it does not contain all of the information you should consider
before exchanging your notes. You should read this entire prospectus carefully,
especially the risks relating to the exchange offer and the risk of owning the
notes discussed under "Risk Factors" beginning on page 13 and the historical
combined financial statements and notes included in this prospectus, before
making an investment decision. Please see page 154 for a glossary of oil and
gas terms we use in this document.
Our Company
We are an independent oil and gas company primarily engaged in the upstream
activities of acquiring, exploiting, developing and producing oil and gas in
the United States. We are 100% owned by Plains Resources Inc. Our core areas of
operation are:
. onshore California, primarily in the Los Angeles Basin, and offshore
California in the Point Arguello unit; and
. the Illinois Basin in southern Illinois and Indiana.
We own a 100% working interest in and operate all of our properties, except
for offshore California, in which we own a 52.6% working interest and where we
are the operator. Our reserves are generally mature but underdeveloped, have
produced significant volumes since initial discovery and have significant
estimated remaining reserves. We opportunistically hedge portions of our oil
production to manage our exposure to commodity price risk.
The following table sets forth information with respect to our oil and gas
properties as of and for the year ended December 31, 2001:
California Illinois
--------------- Basin and
Onshore Offshore Other Total
------- -------- --------- ------
(Dollars in millions)
Proved reserves
MMBOE........................... 211.8 5.0 22.5 239.3
Percent oil..................... 93% 98% 98% 93%
Proved developed reserves (MMBOE) 112.0 3.8 13.3 129.1
Production (MBOE)................ 6,347 1,431 1,000 8,778
PV-10/(1)/....................... $577.7 $ 6.9 $ 58.6 $643.2
Standardized measure/(2)/........ $384.5
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(1) Based on year-end 2001 spot market prices of $19.84 per Bbl of oil and
$2.58 per Mcf of gas. The PV-10 and standardized measure have been reduced
to reflect the abandonment costs of certain properties. PV-10 represents
the standardized measure before deducting estimated future income taxes.
See "Glossary of Oil and Gas Terms" for a complete definition of PV-10.
(2) Estimated future income taxes are calculated on a combined basis using the
statutory income tax rate, accordingly, the standardized measure is
presented in total only. See "Glossary of Oil and Gas Terms" for a complete
definition of standardized measure.
1
During the five-year period ended December 31, 2001 we drilled 561
development wells, 558 of which were successful. During this period, we
incurred aggregate oil and gas acquisition, exploitation, development and
exploration costs of $442.9 million, resulting in proved reserve additions of
177.9 MMBOE, at an average reserve replacement cost of $2.49 per BOE, which we
believe to be among the lowest of our peer group. During that period,
approximately 99% of our oil and gas capital expenditures were for acquisition,
exploitation and development activities. During that same period, the average
replacement cost for large domestic exploration and production companies was
$6.57 per BOE.
Our Competitive Strengths
Quality Asset Base with Long Reserve Life. We had estimated total proved
reserves of 239.3 MMBOE as of December 31, 2001, of which 93% was comprised of
oil and 54% was proved developed. We have a reserve life of over 27 years and a
proved developed reserve life of over 14 years. We believe our long-lived, low
production decline reserve base combined with our active hedging strategy
should provide us with relatively stable and recurring cash flow. As of
December 31, 2001 and based on year-end 2001 spot market prices of $19.84 per
Bbl of oil and $2.58 per Mcf of gas, our reserves had a PV-10 of $643.2 million
and a standardized measure of $384.5 million.
Efficient Operations with 100% Operatorship. We own a 100% working
interest in and operate all of our properties, except for offshore California,
in which we own a 52.6% working interest and where we are the operator. As a
result, we benefit from economies of scale and control the level, timing and
allocation of substantially all of our capital expenditures and expenses. We
believe this gives us more flexibility than many of our peers to
opportunistically pursue exploitation and development projects relating to our
properties.
Large Exploitation and Development Inventory. We have a large inventory of
projects in our core areas that we believe will support at least five years of
exploitation and development activity. Over the last five years, we have
achieved a high success rate on these types of projects, drilling a total of
561 development wells with a 99.5% success rate. In addition, we have completed
numerous other production enhancement projects, such as recompletions,
workovers and upgrades. The results of these activities over the last five
years have been additions to proved reserves, excluding reserves added through
acquisition activities, totaling 120.6 MMBOE, or approximately 332% of
cumulative net production for this period. Reserve replacement costs, excluding
acquisitions, have averaged approximately $3.17 per BOE for the same period.
Experienced and Proven Management and Operations Team. Our executive
management team has an average of 20 years of experience in the oil and gas
industry. Our Chief Executive Officer is James Flores, who founded Flores &
Rucks Incorporated, a predecessor of Ocean Energy, Inc., and was President and
Chief Executive Officer of Ocean Energy from July 1995 until March 1999. Mr.
Flores served as Chairman of the Board of Ocean Energy from March 1999 until
January 2000, and as Vice Chairman from January 2000 until January 2001. The
executive management of Plains Resources is supported by a core team of 23
technical and operating managers who have worked with our properties for many
years and have an average of 22 years of experience in the oil and gas industry.
2
Strategy
Our strategy is to continue to grow our cash flow from operations and to
use this cash flow to increase our proved developed reserves and production,
acquire additional underdeveloped oil and gas properties and make other
strategic acquisitions. We intend to implement our strategy as follows:
Continue Exploitation and Development of Current Asset Base. We believe
that we have a proven track record of exploiting underdeveloped properties to
increase reserves and cash flow. We focus on implementing improved production
practices and recovery techniques, and relatively low-risk development
drilling. An example of our success in exploiting underdeveloped properties can
be found in our Montebello field located in the Los Angeles, or LA, Basin.
Since our acquisition of this field in March 1997, our exploitation and
development activities have resulted in an increase in our net average
production from approximately 930 BOE per day at the time of acquisition to
approximately 2,500 BOE per day during the first nine months of 2002,
representing a compound annual growth rate of over 20%.
Pursue Additional Growth Opportunities. We believe we can continue our
strong reserve and production growth through the exploitation and development
of our existing inventory of projects relating to our properties. We also
intend to be opportunistic in pursuing selective acquisitions of oil or gas
properties or exploration projects, for example, during periods of weak
commodity prices. We will consider opportunities located in our current core
areas of operation as well as projects in other areas in North America that
meet our investment criteria.
Maintain Long-term Hedging Program. We actively manage our exposure to
commodity price fluctuations by hedging significant portions of our oil
production through the use of swaps, collars and purchased puts and calls. The
level of our hedging activity depends on our view of market conditions,
available hedge prices and our operating strategy. Under our hedging program,
we typically hedge approximately 70-75% of our production for the current year,
40-50% of our production for the next year and up to 25% of our production for
the following year. For example, assuming estimated fourth quarter 2002
production levels are held constant in subsequent periods, as of September 30,
2002 we had hedged approximately 78% of production for the fourth quarter of
2002, approximately 68% of production for 2003 and approximately 49% of
production for 2004.
Risk Factors
You should carefully consider the risks described under "Risk Factors"
beginning on page 13, as well as the other information contained in this
prospectus. These risks include the fact that we primarily operate onshore and
offshore California, some of the most highly regulated areas in the United
States. Regulatory factors could therefore delay our ability to exploit our
properties in the time frame we currently anticipate. In addition, through our
pursuit of additional growth opportunities we will be competing with many
companies larger than ourselves with greater financial and technical resources.
Our hedging strategy also may not provide us with the returns and surety of
returns that we expect. If one or more of these consequences occur, it could
negatively impact our ability to implement our business strategy successfully.
Recent Developments
Spin-off
Our parent is Plains Resources Inc., which, in addition to owning us, owns
an aggregate 25% ownership interest in Plains All American Pipeline, or PAA,
including 44% of the general partner of
3
PAA. PAA is a publicly traded master limited partnership that is engaged in the
midstream activities of marketing, transportation and terminalling of oil and
marketing liquified petroleum gas. Plains Resources also owns interests in oil
and gas properties in Florida, which included 17.3 MMBOE of proved oil reserves
as of December 31, 2001.
On May 22, 2002 Plains Resources received a favorable private letter ruling
from the Internal Revenue Service, or IRS, stating that, for United States
federal income tax purposes, a distribution by Plains Resources of our capital
stock owned by it to its stockholders will generally be tax-free to both Plains
Resources and its stockholders. We call this proposed distribution the
"spin-off". We expect the spin-off to occur within 30 days of the date of this
prospectus. The indenture governing the notes will permit the spin-off and the
spin-off will not, in itself, constitute a "change of control" for purposes of
the indenture.
The spin-off will, among other things:
. allow Plains Resources and us to focus corporate strategies and
management teams for each business; and
. simplify Plains Resources' and our corporate structure.
The spin-off is also expected to allow Plains Resources to obtain cost
savings through improved access to capital markets for its midstream affiliate,
PAA.
Reorganization
On July 3, 2002 Plains Resources contributed to us all of the capital stock
of its subsidiaries that own oil and gas properties offshore California and in
Illinois. As a result, we indirectly own our offshore California and Illinois
properties and directly own our onshore California properties. Plains Resources
and its management will continue to manage our operations under the terms of a
transition services agreement. Plains Resources also contributed to us
intercompany payables that we or our subsidiaries owed to it which totalled
$257.7 million at June 30, 2002. We call this series of transactions our
"reorganization".
Although Plains Resources has historically owned and operated the offshore
California and Illinois properties through subsidiaries, our discussion in this
prospectus assumes we owned and operated these properties since the time Plains
Resources acquired them. For example, if Plains Resources through our
subsidiaries drilled a well in 1999 on an Illinois property, in this prospectus
we will state that we drilled the well in 1999.
Financings
On July 3, 2002 we and Plains E&P Company, our wholly owned subsidiary that
has no material assets and was formed for the sole purpose of being a corporate
co-issuer of certain of our indebtedness, issued $200.0 million of Series A
notes. The Series A notes and the Series B notes (when issued) are our
unsecured general obligations, are subordinated in right of payment to all of
our existing and future senior indebtedness and are jointly and severally
guaranteed on a full and unconditional basis by all of our existing and future
domestic restricted subsidiaries.
On July 3, 2002 we also entered into a $300.0 million revolving credit
facility. The credit facility provides for a borrowing base of $225.0 million
that will be reviewed every six months, with the lenders and us each having the
right to one annual interim unscheduled redetermination, and adjusted based
4
on our oil and gas properties, reserves, other indebtedness and other relevant
factors, and matures in 2005. As of September 30, 2002 we had $90.7 million
outstanding under this credit facility. Additionally, the credit facility
contains a $30.0 million sub-limit on letters of credit (of which $5.2 million
had been issued as of September 30, 2002). To secure borrowings, we pledged
100% of the shares of stock of our domestic subsidiaries and gave mortgages
covering 80% of the total present value of our domestic oil and gas properties.
We distributed the net proceeds of $195.3 million from the Series A notes
and $116.7 million in initial borrowings under our credit facility to Plains
Resources, which used:
. $287.0 million to redeem its 10.25% senior subordinated notes on August
2, 2002; and
. $25.0 million to repay the amounts outstanding under its credit facility.
Purchase of Additional Point Arguello Interest
In August 2002 we acquired an additional 26.3% working interest in the
Point Arguello unit and the various partnerships owning the related
transportation, processing and marketing infrastructure. The seller retained
responsibility for certain abandonment costs, including: (1) removing,
dismantling and disposing of the existing offshore platforms; (2) removing and
disposing of all pipelines; and (3) removing, dismantling, disposing and
remediating all existing onshore facilities. We assumed the seller's share of
the costs of plugging the wells and flushing the lines. As consideration for
receiving the transferred properties and assuming the obligations described
above, we received $2.4 million in cash and $3.0 million for our share of
revenues less costs for the period from April 1 to July 30, 2002. This
transaction doubled our working interest in the Point Arguello unit to 52.6%.
Our Executive Offices
Our principal executive offices are located at 500 Dallas Street, Suite
700, Houston Texas 77002, and our telephone number at that address is (713)
739-6700.
5
CORPORATE STRUCTURE
The diagram below shows our and our parent's corporate structure and
obligations under the notes. Plains Resources, Calumet Florida and Plains
Holdings do not guarantee or have any other obligations in respect of the notes.
[FLOW CHART]
- --------
(1) Subsidiary guarantor of the notes. Plains Resources International Inc. and
PMCT Inc., wholly-owned subsidiaries of Plains Exploration & Production
Company that have no material assets or operations, are also subsidiary
guarantors of the notes.
6
THE EXCHANGE OFFER
You are entitled to exchange in the exchange offer your outstanding Series
A notes for Series B notes with substantially identical terms. You should read
the discussion under the heading "Description of Notes" beginning on page 98
for further information regarding the Series B notes.
Registration Rights
Agreement................. We sold $200.0 million in aggregate principal
amount of Series A notes to J.P. Morgan
Securities Inc., Goldman, Sachs & Co., Banc One
Capital Markets, Inc., BNP Paribas Securities
Corp., Fleet Securities, Inc. and Fortis
Investment Services LLC as initial purchasers in
a transaction exempt from the registration
requirements of the Securities Act. We entered
into a registration rights agreement dated as of
July 3, 2002 with the initial purchasers which
grants the holders of the Series A notes exchange
and registration rights. This exchange offer
satisfies those exchange rights.
The Exchange Offer........ $1,000 principal amount of Series B notes in
exchange for each $1,000 principal amount of
Series A notes. As of the date of this
prospectus, $200.0 million aggregate principal
amount of the Series A notes are outstanding. We
will issue Series B notes to holders promptly
following the Expiration Date.
Resales of the Series B
notes..................... Based on interpretations by the staff of the SEC
set forth in no-action letters issued to third
parties, we believe that, except as described
below, the Series B notes issued in the exchange
offer may be offered for resale, resold and
otherwise transferred by holders of the Series B
notes, other than a holder that is an "affiliate"
of ours 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 the Series B
notes are acquired in the ordinary course of the
holder's business and the holder has no
arrangement or understanding with any person to
participate in the distribution of the Series B
notes.
Each broker-dealer that receives Series B notes
pursuant to the exchange offer in exchange for
Series A notes that the broker-dealer acquired
for its own account as a result of market-making
activities or other trading activities, other
than Series A notes acquired directly from us or
our affiliates, must acknowledge that it will
deliver a prospectus in connection with any
resale of the Series B notes. The letter of
transmittal states that by 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.
7
If we receive notices in the letter of
transmittal, this prospectus, as it may be
amended or supplemented from time to time, may be
used for the period described below by a
broker-dealer in connection with resales of
Series B notes received in exchange for Series A
notes where the Series A notes were acquired by
the broker-dealer as a result of market making
activities or other trading activities and not
acquired directly from us.
The letter of transmittal requires broker-dealers
tendering Series A notes in the exchange offer to
indicate whether the broker-dealer acquired the
Series A notes for its own account as a result of
market-making activities or other trading
activities, other than Series A notes acquired
directly from us or any of our affiliates. If no
broker-dealer indicates that the Series A notes
were so acquired, we have no obligation under the
registration rights agreement to maintain the
effectiveness of the registration statement past
the consummation of the exchange offer or to
allow the use of this prospectus for such
resales. See "The Exchange Offer--Registration
Rights" and "--Resale of the Series B Notes; Plan
of Distribution."
Expiration Date........... The exchange offer expires at 5:00 p.m., New York
City time on , unless we extend the exchange
offer in our sole discretion, in which case the
term "Expiration Date" means the latest date and
time to which the exchange offer is extended.
Conditions to the Exchange
Offer..................... The exchange offer is subject to certain
conditions which we may waive. See "The Exchange
Offer--Conditions to the Exchange Offer."
Procedures for Tendering
the Series A Notes........ Each holder of Series A notes wishing to accept
the exchange offer must complete, sign and date
the accompanying letter of transmittal in
accordance with the instructions, and mail or
otherwise deliver the letter of transmittal
together with the Series A notes and any other
required documentation to the exchange agent
identified below under "Exchange Agent" at the
address set forth in this prospectus. By
executing the letter of transmittal, a holder
will make certain representations to us. See "The
Exchange Offer--Registration Rights" and
"--Procedures for Tendering Series A Notes."
Special Procedures for
Beneficial Owners......... Any beneficial owner whose Series A notes are
registered in the name of a broker, dealer,
commercial bank, trust company or other nominee
and who wishes to tender should contact the
registered holder promptly and instruct the
registered holder to tender on its behalf. See
"The Exchange Offer--Procedures for Tendering
Series A Notes."
8
Guaranteed
Delivery Procedures....... Holders of Series A notes who wish to tender
their Series A notes when those securities are
not immediately available or who cannot deliver
their Series A 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 Series A notes
according to the guaranteed delivery procedures
set forth in "The Exchange Offer--Procedures for
Tendering Series A Notes--Guaranteed Delivery."
Withdrawal Rights......... Tenders of Series A notes pursuant to the
exchange offer may be withdrawn at any time prior
to the Expiration Date.
Acceptance of Series A
Notes and Delivery of
Series B Notes............ We will accept for exchange any and all Series A
notes that are properly tendered in the exchange
offer and not withdrawn prior to the Expiration
Date. The Series B notes issued in the exchange
offer will be issued on the earliest practicable
date following our acceptance for exchange of the
Series A notes. See "The Exchange Offer--Terms of
the Exchange Offer."
Exchange Agent............ JPMorgan Chase Bank is serving as exchange agent
in connection with the exchange offer. See "The
Exchange Offer--Exchange Agent."
Ratio of Earnings to Fixed Charges
The ratio of earnings to fixed charges for each of the periods indicated is
as follows:
Nine Months Ended
September 30, Year Ended December 31,
----------------- --------------------------
2002 2001 2001 2000 1999 1998 1997
---- ---- ---- ---- ---- ---- ----
3.0 5.8 5.2 3.1 2.1 --(1) 4.6
- --------
(1) In 1998 earnings were insufficient to cover fixed charges by $29.2 million.
We have computed the ratio of earnings to fixed charges by dividing
earnings by fixed charges. For this purpose, earnings consists of income before
income taxes and the cumulative effect of accounting changes and fixed charges.
Fixed charges consist of interest expense, capitalized interest and that
portion of annual rental expense we have deemed to represent the interest
factor.
9
SUMMARY FINANCIAL INFORMATION
The following table sets forth our summary consolidated and combined
historical financial information that has been derived from (i) the audited
combined statements of income and cash flows for our business for each of the
years ended December 31, 2001, 2000 and 1999, (ii) the unaudited consolidated
statements of income and cash flows for our business for the nine months ended
September 30, 2002 and 2001 and (iii) our unaudited consolidated balance sheet
as of September 30, 2002. Pro forma information reflects (i) the
reorganization, (ii) our issuance of Series A notes, (iii) our new $300 million
revolving credit facility and our initial borrowings thereunder and (iv) the
distribution of the proceeds of our notes offering and our initial borrowings
under our credit facility to Plains Resources. You should read this financial
information in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and our historical combined
financial statements and notes and the unaudited pro forma condensed financial
information and notes thereto included elsewhere in this prospectus. The
information set forth below is not necessarily indicative of our future results.
Nine Months Ended
September 30, Year Ended December 31,
----------------------------- --------------------------------------
Pro Pro
Forma Forma
2002 2002 2001 2001 2001 2000 1999
-------- --------- -------- -------- -------- -------- --------
(Amounts in thousands, except per share data)
Statement of Income Data:
Revenues:
Oil and liquids........................ $129,563 $ 129,563 $133,957 $174,895 $174,895 $126,434 $102,390
Gas.................................... 7,130 7,130 26,870 28,771 28,771 16,017 5,095
Other operating revenues............... 27 27 468 473 473 -- --
-------- --------- -------- -------- -------- -------- --------
136,720 136,720 161,295 204,139 204,139 142,451 107,485
-------- --------- -------- -------- -------- -------- --------
Costs and expenses:
Production expenses.................... 56,826 56,826 47,995 63,795 63,795 56,228 50,527
General and administrative/(1)/........ 7,362 7,362 7,074 10,210 10,210 6,308 4,367
Depreciation, depletion and
amortization.......................... 21,723 21,262 16,999 25,010 24,105 18,859 13,329
-------- --------- -------- -------- -------- -------- --------
85,911 85,450 72,068 99,015 98,110 81,395 68,223
-------- --------- -------- -------- -------- -------- --------
Income from operations................... 50,809 51,270 89,227 105,124 106,029 61,056 39,262
Other income (expense)
Expenses of terminated public equity
offering.............................. (1,700) (1,700) -- -- -- -- --
Interest expense....................... (16,487) (14,427) (12,942) (21,979) (17,411) (15,885) (14,912)
Interest and other income.............. 114 114 459 463 463 343 87
-------- --------- -------- -------- -------- -------- --------
Income before income taxes and
cumulative effect of accounting
change.................................. 32,736 35,257 76,744 83,608 89,081 45,514 24,437
Income tax expense....................... (12,773) (13,757) (29,623) (32,275) (34,388) (16,765) (5,332)
-------- --------- -------- -------- -------- -------- --------
Income before cumulative effect of
accounting change....................... $ 19,963 21,500 47,121 $ 51,333 54,693 28,749 19,105
======== ========
Cumulative effect of accounting change,
net of tax benefit...................... -- (1,522) (1,522) -- --
--------- -------- -------- -------- --------
Net income............................... $ 21,500 $ 45,599 $ 53,171 $ 28,749 $ 19,105
========= ======== ======== ======== ========
Net income per common share:
Basic and diluted...................... $ 0.82 $ 0.89 $ 1.89 $ 2.12 $ 2.20 $ 1.19 $ 0.79
Weighted averaged common shares
outstanding:
Basic and diluted...................... 24,200 24,200 24,200 24,200 24,200 24,200 24,200
Other Financial Data:
EBITDA/(2)/.............................. $ 70,832 $ 70,832 $106,226 $130,134 $130,134 $ 79,915 $ 52,591
Net cash provided by operating activities 58,353 102,071 116,808 79,464 4,609
Net cash used in investing activities.... 53,644 (99,453) 125,880 70,871 59,362
Net cash provided by (used in) financing
activities.............................. (3,956) (3,151) 8,549 (13,132) 59,690
Oil and gas capital expenditures......... 53,589 99,346 125,753 70,505 59,167
(footnotes on following page)
10
As of
September 30,
2002
Historical
--------------
(In thousands)
Balance Sheet Data:
Cash and cash equivalents $ 766
Working capital.......... (50,500)
Total assets............. 541,056
Total debt............... 288,525
Stockholder's equity..... 120,127
- --------
(1) General and administrative expenses consist of our direct expenses plus
amounts allocated from Plains Resources for various operational, financial,
accounting and administrative services provided to us. We estimate that as
a result of our reorganization and spin-off, our annual general and
administrative expenses will increase by approximately $5.3 million over
the amount reported for the year ended December 31, 2001, reflecting the
incremental costs of operating as a separate, publicly-held company.
In addition, in connection with the issuance of stock appreciation rights
(SARs) to Plains Resources' employees, officers and directors as part of
and at the time of the spin-off, if the exercise price of the SAR is below
the fair market value of a share of our common stock on the date of the
spin-off, we will be required to record a charge to earnings equal to that
difference. Assuming that the value of a share of Plains Resources common
stock before the spin-off is equal to the closing trading price of Plains
Resources common stock as of November 20, 2002 minus the value of one of
our shares of common stock, which we assume for purposes of this
calculation to be $10.00, we would incur the following initial charge in
connection with the spin-off.
Plains Resources Our Assumed Estimated # SARs to Charge to Net Effect on Basic
Share Price Share Price be Outstanding Income Earnings Per Share
$20.45 $10.00 3.9 million $1.5 million $0.06
SARs are subject to variable accounting treatment. As a result, in
subsequent periods our results of operations could be adversely affected by
fluctuations in the price of our common stock. See the discussion of new
Plains Resources stock options and stock appreciation rights on page 25.
(2) EBITDA means earnings before interest income and expense, income taxes,
depreciation, depletion and amortization and other income. EBITDA is not a
measurement presented in accordance with generally accepted accounting
principles, or GAAP, and should not be considered as an alternative to cash
flow from operating activities as a measure of liquidity or net income as a
measure of operating results in accordance with GAAP.
EBITDA is presented because we believe it provides additional information
with respect to our ability to meet our future debt service, capital
expenditures and working capital requirements. When evaluating EBITDA,
investors should consider, among other factors, (i) increasing or
decreasing trends in EBITDA, (ii) whether EBITDA has remained at positive
levels historically and (iii) how EBITDA compares to levels of interest
expense. However, EBITDA does not necessarily indicate whether cash flow
will be sufficient for such items as working capital requirements, capital
expenditures or to react to changes in our industry or to the economy in
general, as certain functional or legal requirements of our business may
require us to use our available funds for other purposes. EBITDA, as
presented herein, is not necessarily comparable to other similarly titled
captions of other companies due to potential inconsistencies in the method
of calculation.
EBITDA includes amortization of hedge premiums of $0.6 million and $3.1
million for the nine months ended September 30, 2002 and 2001,
respectively, and $3.2 million and $0.9 million for the years ended
December 31, 2001 and 2000, respectively. EBITDA is calculated as follows:
Nine Months Ended
September 30, Year Ended December 31,
-------------------------- ------------------------------------
Pro Pro
Forma Forma
2002 2002 2001 2001 2001 2000 1999
------- ------- -------- -------- -------- ------- -------
(In thousands)
Income before income taxes
and cumulative effect of
accounting change......... $32,736 $35,257 $ 76,744 $ 83,608 $ 89,081 $45,514 $24,437
Interest and other income.. (114) (114) (459) (463) (463) (343) (87)
Interest expense........... 16,487 14,427 12,942 21,979 17,411 15,885 14,912
Depreciation, depletion and
amortization.............. 21,723 21,262 16,999 25,010 24,105 18,859 13,329
------- ------- -------- -------- -------- ------- -------
EBITDA..................... $70,832 $70,832 $106,266 $130,134 $130,134 $79,915 $52,591
======= ======= ======== ======== ======== ======= =======
(3) We have computed the ratios of earnings to fixed charges by dividing
earnings by fixed charges. For this purpose, "earnings" consist of income
before income taxes and the cumulative effect of accounting changes and
fixed charges. "Fixed charges" consist of interest expense, capitalized
interest and that portion of annual rental expense we have deemed to
represent the interest factor.
11
SUMMARY RESERVE AND PRODUCTION DATA
The following table sets forth certain of our historical reserve and
operating data. You should read the historical data in conjunction with our
historical combined financial statements and notes included elsewhere in this
prospectus. The information set forth below is not necessarily indicative of
our future results.
Nine Months Ended
September 30, Year Ended December 31,
---------------- ------------------------------
2002 2001 2001 2000 1999
------- ------- -------- ---------- ----------
(Dollars in thousands, except per unit amounts)
Estimated proved reserves (at end
of period):
Oil (MBbl)...................... 223,293 204,387 195,213
Gas(MMcf)....................... 96,217 93,486 90,873
Total (MBOE).............. 239,329 219,968 210,359
Percent oil...................... 93% 93% 93%
Percent proved developed......... 54% 52% 52%
PV-10 (at end of period)(1)...... $643,220 $1,304,182 $1,106,358
Standardized measure(1)(2)....... 384,467 789,438 727,286
Reserve additions (MBOE)......... 28,140 17,770 92,554
Reserve life (years)............. 27.3 27.0 27.6
Production:
Oil (MBbl)...................... 6,433 6,057 8,219 7,654 7,081
Gas (MMcf)...................... 2,540 2,499 3,355 3,042 3,163
Total (MBOE).............. 6,856 6,473 8,778 8,161 7,608
Costs incurred:
Exploitation and development(3). $56,535 $96,820 $123,778 $ 68,186 $ 54,996
Exploration..................... -- 32 286 293 796
Acquisition..................... (2,946) 2,494 1,689 2,026 3,375
Total costs incurred...... 53,589 99,346 125,753 70,505 59,167
Reserve replacement cost per
BOE............................ $ 4.47 $ 3.97 $ 0.64
Industry average reserve
replacement cost per BOE(4).... 8.58 5.40 4.53
Reserve replacement ratio........ 321% 218% 1,216%
Average sales price per unit:
Oil ($/Bbl)..................... $ 20.14 $ 22.12 $ 21.28 $ 16.52 $ 14.46
Gas ($/Mcf)..................... 2.81 10.75 8.58 5.26 1.61
BOE............................. 19.94 24.85 23.20 17.46 14.13
Expense per BOE:
Production expenses............. $ 8.29 $ 7.41 $ 7.27 $ 6.89 $ 6.64
General and administrative...... 1.07 1.09 1.16 0.77 0.57
- --------
(1) Based on year-end spot market prices of: (a) $19.84 per Bbl of oil and
$2.58 per Mcf of gas for 2001; (b) $26.80 per Bbl of oil and $13.70 per Mcf
of gas for 2000; and (c) $25.60 per Bbl of oil and $2.37 per Mcf of gas for
1999. PV-10 represents the standardized measure before deducting estimated
future income taxes.
(2) Our year-end 2001 standardized measure includes future development costs
related to proved undeveloped reserves of $25.5 million in 2002, $58.9
million in 2003 and $45.2 million in 2004.
(3) Exploitation and development costs include expenditures of $58.5 million in
2001, $20.6 million in 2000 and $10.7 million in 1999 related to the
development of proved undeveloped reserves included in our proved oil and
gas reserves at the beginning of each year.
(4) Represents the average replacement cost for large domestic exploration and
production companies.
12
RISK FACTORS
You should carefully consider the risks described below in addition to
other information contained in this prospectus before making an investment
decision. Realization of any of the following risks could have a material
adverse effect on our business, financial condition, cash flow and results of
operations.
Risks Relating to the Exchange Offer
If you do not tender your Series A notes for exchange, your ability to transfer
your Series A notes will be limited.
We issued the Series A notes in a private offering. As a result, the Series
A notes have not been registered under the Securities Act and may not be resold
by purchasers thereof unless the Series A notes are subsequently registered or
an exemption from the registration requirements of the Securities Act is
available. The Series A notes that are not tendered in the exchange offer will
continue to be subject to the existing restrictions upon their transfer. We
will have no obligation to provide for the registration under the Securities
Act of unexchanged Series A notes.
Your ability to transfer the notes may be limited by the absence of an active
trading market, and there is no assurance that any active trading market will
develop for the notes.
The notes are a new issue of securities for which there is no established
public market. At the time of the private placement of the Series A notes, the
initial purchasers advised us that they intended to make a market in the Series
A notes and the Series B notes, if issued, as permitted by applicable laws and
regulations. The Series A notes that were sold to institutional buyers are
currently eligible for trading in The PORTAL Market. However, the initial
purchasers are not obligated to make a market in the notes, and they may
discontinue their market-making activities at any time without notice.
Therefore, an active market for the notes may not develop or, if developed, may
not continue. Historically, the market for non-investment grade debt has been
subject to disruptions that have caused substantial volatility in the prices of
securities similar to the notes. The market, if any, for the notes may not be
free from similar disruptions and any such disruptions may adversely affect the
prices at which you may sell your notes. In addition, subsequent to their
initial issuance, the notes may trade at a discount from their initial offering
price, depending upon prevailing interest rates, the market for similar notes,
our performance and other factors.
Risks Relating to the Notes
We may not be able to generate enough cash flow to meet our debt obligations.
We expect our earnings and cash flow to vary significantly from year to
year. As a result, the amount of debt that we can manage in some periods may
not be appropriate for us in other periods. Additionally, our future cash flow
may be insufficient to meet our debt obligations and commitments, including the
notes. Any insufficiency could negatively impact our business. A range of
economic, competitive, business and industry factors will affect our future
financial performance, and, as a result, our ability to generate cash flow from
operations and to pay our debt, including the notes. Many of these factors,
such as oil and gas prices, economic and financial conditions in our industry
and the global economy or competitive initiatives of our competitors, are
beyond our control.
At September 30, 2002 we had $90.7 million outstanding under our new credit
facility which is senior in right of payment to the notes. In addition, we had
$129.1 million in additional borrowing capacity under the new credit facility,
which if borrowed would be secured debt senior in right of payment to the notes.
13
If we do not generate enough cash flow from operations to satisfy our debt
obligations, we may have to undertake alternative financing plans, such as:
. refinancing or restructuring our debt;
. selling assets;
. reducing or delaying capital investments; or
. seeking to raise additional capital.
However, undertaking alternative financing plans, if necessary, may not
allow us to meet our debt obligations. Our inability to generate sufficient
cash flow to satisfy our debt obligations, including our obligations under the
notes, or to obtain alternative financing, could materially and adversely
affect our business, financial condition, results of operations and prospects.
Your right to receive payments on the notes is junior to all of our and the
subsidiary guarantors' existing senior indebtedness and any additional senior
indebtedness we and the subsidiary guarantors may incur.
The notes rank behind all of our existing and future senior indebtedness
(which includes our revolving credit facility but does not include trade
payables and certain other indebtedness), except any future indebtedness that
expressly provides that it ranks equal with, or is subordinated in right of
payment to, the notes. The subsidiary guarantees are similarly subordinated. As
a result, upon any distribution to our creditors or the creditors of any
subsidiary guarantors in a bankruptcy or similar proceeding relating to us or
any subsidiary guarantors, the holders of our senior debt and the senior debt
of any subsidiary guarantors will be entitled to be paid in full in cash before
any payment may be made with respect to the notes or any subsidiary guarantees.
In the event of a bankruptcy, liquidation or reorganization or similar
proceeding relating to us or any subsidiary guarantor, holders of the notes
will participate with all other holders of our senior subordinated indebtedness
and that of any subsidiary guarantors in the assets remaining after we and the
subsidiary guarantors have paid all of our senior debt. In any of these cases,
we and the subsidiary guarantors may not have sufficient funds to pay all of
our creditors and holders of the notes would receive ratably less than senior
creditors.
In addition, a breach of any of the covenants contained in our credit
facility, or our inability to comply with the required financial ratios, could
result in an event of default. To secure our borrowing under the credit
facility, we pledged 100% of the shares of stock of our domestic subsidiaries
and gave mortgages covering 80% of the total present value of our domestic oil
and gas properties. If we default under the credit facility, the lenders
thereunder could discontinue lending and/or declare all amounts outstanding to
be immediately due and payable, foreclose upon the assets pledged to them,
require us to apply all of our available cash to repay our borrowings or
prevent us from making payments on the notes. If the amounts outstanding under
the credit facility or the notes were to be accelerated, we cannot assure you
that our assets would be sufficient to repay in full the money owed to the
lenders or to our other debt holders, including you as a noteholder. Further,
if the lenders under our credit facility proceed against the collateral
securing that debt, the proceeds received upon the realization of the
collateral upon which the lenders under our credit facility have a first
priority lien would be applied first to amounts due under our credit facility
before any proceeds will be available to make payments on the notes.
We may not be able to repurchase the notes upon a change of control.
Upon the occurrence of certain change of control events, we are required to
offer to repurchase all or any part of the notes then outstanding for cash at
101% of the principal amount. The source of
14
funds for any repurchase required as a result of any change of control will be
our available cash or cash generated from our oil and gas operations or other
sources, including:
. borrowings under our credit facilities or other sources;
. sales of assets; or
. sales of equity.
Sufficient funds may not be available at the time of any change of control
to repurchase your notes after first repaying any of our senior debt that may
exist at the time. In addition, restrictions under our credit facility or any
future credit facilities will not allow such repurchases. Additionally, a
"change of control" (as defined in the indenture) will be an event of default
under our credit facility that would permit the lenders to accelerate the debt
outstanding under the credit facility. Finally, using available cash to fund
the potential consequences of a change of control may impair our ability to
obtain additional financing in the future, which could negatively impact our
ability to conduct our business operations. The spin-off, if and when it
occurs, will not be a "change of control" for purposes of the indenture.
A financial failure by us or our subsidiaries may result in the assets of any
or all of those entities becoming subject to the claims of all creditors of
those entities.
A financial failure by us, our subsidiaries, or our parent prior to the
spin-off, could affect payment of the notes if a bankruptcy court were to
substantively consolidate us and our subsidiaries or us and our parent. If a
bankruptcy court substantively consolidated us and our subsidiaries or us and
our parent, the assets of each entity would be subject to the claims of
creditors of all entities. This would expose you not only to the usual
impairments arising from bankruptcy, but also to potential dilution of the
amount ultimately recoverable because of the larger creditor base. Furthermore,
forced restructuring of the notes could occur through the cram-down provision
of the bankruptcy code. Under this provision, the notes could be restructured
over your objections as to their general terms, primarily interest rate and
maturity.
If the subsidiary guarantees are deemed fraudulent conveyances or preferential
transfers, a court may subordinate or void them.
Under various fraudulent conveyance or fraudulent transfer laws, a court
could subordinate or void our subsidiary guarantees. Generally, a United States
court may void or subordinate a subsidiary guarantee in favor of the
subsidiary's other obligations if it finds that at the time the subsidiary
entered into a subsidiary guarantee it:
. intended to hinder, delay or defraud any present or future creditor or
contemplated insolvency with a design to favor one or more creditors to
the exclusion of others; or
. did not receive fair consideration or reasonably equivalent value for
issuing the subsidiary guarantee, or
. at the time it issued the subsidiary guarantee, the subsidiary
. was insolvent or became insolvent as a result of issuing the subsidiary
guarantee,
. was engaged or about to engage in a business or transaction for which
the remaining assets of the subsidiary constituted unreasonably small
capital, or
. intended to incur, or believed that it would incur, debts beyond its
ability to pay those debts as they matured.
In addition, a guarantee may be voided based on the level of benefits the
guarantor received compared to the amount of the subsidiary guarantee. If a
subsidiary guarantee is voided or held
15
unenforceable, you would not have any claim against that subsidiary and would
be creditors solely of us and Plains E&P Company and any subsidiary guarantors
whose guarantees are not held unenforceable. After providing for all prior
claims, there may not be sufficient assets to satisfy claims of holders of
notes relating to any voided portions of any of the subsidiary guarantees.
There is a risk of a preferential transfer if:
. a subsidiary guarantor declares bankruptcy or its creditors force it to
declare bankruptcy within 90 days (or in certain cases, one year) after a
payment on the guarantee; or
. a subsidiary guarantee was made in contemplation of insolvency.
The subsidiary guarantee could be voided by a court as a preferential
transfer. In addition, a court could require holders of notes to return any
payments made on the notes during the 90-day (or one-year) period.
Risks Relating to Our Business
Our substantial debt could adversely restrict our ability to operate and affect
our financial condition.
We have a substantial amount of debt and the ability to incur substantially
more debt. In addition to the $200 million of Series A notes we have
outstanding we have a $300.0 million revolving credit facility with a current
borrowing base of $225.0 million, which is collateralized by a pledge of the
equity of our subsidiaries and substantially all of our other assets and
supported by guarantees of our subsidiaries. As of September 30, 2002 we had
$90.7 million outstanding under this credit facility.
We have been assigned a Ba3 senior implied rating and our Series A notes
have been assigned a B2 rating by Moody's Investor Service Inc. We have also
been assigned a BB- corporate credit rating, on credit watch with negative
implications, by Standard and Poor's Ratings Group. All of these ratings are
below investment grade. As a result, at times we may have difficulty accessing
capital markets or raising capital on favorable terms as we will incur higher
borrowing costs than our competitors that have higher ratings. Therefore, our
financial results may be negatively affected by our inability to raise capital
or the cost of such capital as a result of our ratings.
We and all of our restricted subsidiaries must comply with various
covenants contained in our revolving credit facility, the indenture related to
our senior subordinated notes and any of our future debt arrangements which,
among other things, limit the ability of us and those subsidiaries to:
. incur additional debt or liens;
. make payments in respect of or redeem or acquire any debt or equity
issued by us;
. sell assets;
. make loans or investments;
. acquire or be acquired by other companies; and
. amend some of our contracts.
Our substantial debt could have important consequences to you. For example,
it could:
. increase our vulnerability to general adverse economic and industry
conditions;
. limit our ability to fund future working capital and capital
expenditures, to engage in future acquisitions, construction or
development activities, or to otherwise fully realize the value of our
16
assets and opportunities because of the need to dedicate a substantial
portion of our cash flow from operations to payments on our debt or to
comply with any restrictive terms of our debt;
. limit our flexibility in planning for, or reacting to, changes in our
businesses and the industries in which we operate; and
. place us at a competitive disadvantage as compared to our competitors
that have less debt.
In addition, if we fail to comply with the terms of any of our debt, the
lenders will have the right to accelerate the maturity of that debt and
foreclose upon the collateral, if any, securing that debt. Realization of any
of these factors could adversely affect our financial condition.
Volatile oil and gas prices could adversely affect our financial condition and
results of operations.
Our success is largely dependent on oil and gas prices, which are extremely
volatile. Any substantial or extended decline in the price of oil and gas below
current levels will have a material adverse effect on our business operations
and future revenues. Moreover, oil and gas prices depend on factors we cannot
control, such as:
. supply and demand for oil and gas and expectations regarding supply and
demand;
. weather;
. actions by the Organization of Petroleum Exporting Countries, or OPEC;
. political conditions in other oil-producing and gas-producing countries;
. general economic conditions in the United States and worldwide; and
. governmental regulations.
With respect to our business, prices of oil and gas will affect:
. our revenues, cash flows and earnings;
. our ability to attract capital to finance our operations and the cost of
such capital;
. the amount that we are allowed to borrow; and
. the value of our oil and gas properties.
Any prolonged, substantial reduction in the demand for oil and gas, or
distribution problems in meeting this demand, could adversely affect our
business.
Our success is materially dependent upon the demand for oil and gas. The
availability of a ready market for our oil and gas production depends on a
number of factors beyond our control, including the demand for and supply of
oil and gas, the availability of alternative energy sources, the proximity of
reserves to, and the capacity of, oil and gas gathering systems, pipelines or
trucking and terminal facilities. If there is no market for the oil and gas
which we produce, we will be unable to sell it. We may also have to shut-in
some of our wells temporarily due to a lack of market. If the demand for oil
and gas diminishes, our financial results would be negatively impacted.
In addition, there are limited methods of transportation for our
production. Substantially all of our oil and gas production is transported by
pipelines, trucks and barges owned by third parties. The inability or
unwillingness of these parties to provide transportation services to us for a
reasonable fee could result in our having to find transportation alternatives,
increased transportation costs or involuntary curtailment of a significant
portion of our oil and gas production, any of which could have a negative
impact on our results of operation and cash flows.
17
Our equity oil production is dedicated to a single customer and, as a result,
our credit exposure to that customer is significant.
We have entered into an oil marketing agreement with PAA, an affiliate of
both ours and Plains Resources, under which PAA is the exclusive purchaser of
all of our equity oil production. We generally do not require letters of credit
or other collateral from PAA to support our trade receivables. Accordingly, a
material adverse change in PAA's financial condition could adversely impact our
ability to collect our receivables from PAA and thereby affect our financial
condition.
If we are unable to replace the reserves that we have produced, our reserves
and revenues will decline.
Our future success depends on our ability to find, develop and acquire
additional oil and gas reserves that are economically recoverable which, in
itself, is dependent on oil and gas prices. Without continued successful
exploitation, acquisition or exploration activities, our reserves and revenues
will decline as a result of our current reserves being depleted by production.
We may not be able to find or acquire additional reserves at acceptable costs.
We may not be successful in acquiring, exploiting, developing or exploring for
oil and gas properties.
The successful acquisition, exploitation or development of or exploration
for oil and gas properties requires an assessment of recoverable reserves,
future oil and gas prices and operating costs, potential environmental and
other liabilities, and other factors. These assessments are necessarily
inexact. As a result, we may not recover the purchase price of a property from
the sale of production from the property, or may not recognize an acceptable
return from properties we do acquire. In addition, our exploitation and
development operations may not result in any increases in reserves. Our
operations may be curtailed, delayed or canceled as a result of:
. inadequate capital or other factors, such as title problems;
. weather;
. compliance with governmental regulations or price controls;
. mechanical difficulties; or
. shortages or delays in the delivery of equipment.
In addition, exploitation and development costs may greatly exceed initial
estimates. In that case, we would be required to make unanticipated
expenditures of additional funds to develop these projects, which could
materially adversely affect our business, financial condition and results of
operations.
In the future, we may focus on exploration opportunities onshore and
offshore. Exploration for oil and gas has inherent and historically high risk.
Exploration may involve unprofitable efforts, not only with respect to dry
wells, but also with respect to wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs. Future reserve increases and production may be dependent on our success
in these exploration efforts, which may be unsuccessful.
Estimates of oil and gas reserves depend on many assumptions that may be
inaccurate. Any material inaccuracies could adversely affect the quantity and
value of our oil and gas reserves.
The proved oil and gas reserve information included in this prospectus
represents only estimates. These estimates are based on reports prepared by
independent petroleum engineers. The estimates
18
were calculated using oil and gas prices in effect on the date indicated in the
reports. Any significant price changes will have a material effect on the
quantity and present value of our reserves.
Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows depend upon a number of variable factors and assumptions, including:
. historical production from the area compared with production from other
comparable producing areas;
. the assumed effects of regulations by governmental agencies;
. assumptions concerning future oil and gas prices; and
. assumptions concerning future operating costs, severance and excise
taxes, development costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the
following items may differ materially from those assumed in estimating reserves:
. the quantities of oil and gas that are ultimately recovered;
. the timing of the recovery of oil and gas reserves;
. the production and operating costs incurred; and
. the amount and timing of future development expenditures.
Furthermore, different reserve engineers may make different estimates of
reserves and cash flows based on the same available data. Actual production,
revenues and expenditures with respect to reserves will vary from estimates and
the variances may be material.
The discounted future net revenues included in this prospectus should not
be considered as the market value of the reserves attributable to our
properties. As required by the SEC, the estimated discounted future net
revenues from proved reserves are generally based on prices and costs as of the
date of the estimate, while actual future prices and costs may be materially
higher or lower. Actual future net revenues will also be affected by factors
such as:
. the amount and timing of actual production;
. supply and demand for oil and gas; and
. changes in governmental regulations or taxation.
In addition, the 10% discount factor, which the SEC requires to be used to
calculate discounted future net revenues for reporting purposes, is not
necessarily the most appropriate discount factor based on the cost of capital
in effect from time to time and risks associated with our business and the oil
and gas industry in general.
The geographic concentration and lack of marketable characteristics of our oil
and gas reserves may have a greater effect on our ability to sell our oil and
gas compared to other companies.
Substantially all of our oil and gas reserves are located in California and
Illinois. Because our reserves are not diversified geographically, our business
is more subject to local conditions than other, more diversified companies. Any
regional events, including price fluctuations, natural disasters, and
restrictive regulations, that increase costs, reduce availability of equipment
or supplies, reduce demand
19
or limit our production may impact our operations more than if our reserves
were more geographically diversified.
California oil reserves are largely 14 to 25 degree API gravity, which is
heavier than premium grade light crude oil. Due to the processes required to
refine this type of oil and the transportation requirements, it would be
difficult to market our oil outside California.
Operating hazards, natural disasters or other interruptions of our operations
could result in potential liabilities, which may not be fully covered by our
insurance.
The oil and gas business involves certain operating hazards such as:
. well blowouts;
. cratering;
. explosions;
. uncontrollable flows of oil, gas or well fluids;
. fires;
. pollution; and
. releases of toxic gas.
In addition, our operations in California are especially susceptible to
damage from natural disasters such as earthquakes and fires and involve
increased risks of personal injury, property damage and marketing interruptions
because of the population density of southern California. Any of these
operating hazards could cause serious injuries, fatalities or property damage,
which could expose us to liabilities. The payment of any of these liabilities
could reduce, or even eliminate, the funds available for exploration,
development, and acquisition, or could result in a loss of our properties.
Consistent with insurance coverage generally available to the industry, our
insurance policies provide limited coverage for losses or liabilities relating
to pollution, with broader coverage for sudden and accidental occurrences. Our
insurance might be inadequate to cover our liabilities. For example, we are not
fully insured against earthquake risk in California because of high premium
costs. Insurance covering earthquakes or other risks may not be available at
premium levels that justify its purchase in the future, if at all. The
insurance market in general and the energy insurance market in particular has
been a difficult market over the past several years. Upon renewal in June 2002,
our cost of insurance increased substantially over the prior year's amount. In
addition, we increased deductibles and decreased or eliminated certain types of
coverages to mitigate the cost increase. Insurance costs are expected to
continue to increase over the next few years and we may decrease coverage and
retain more risk to mitigate future cost increases. If we incur substantial
liability and the damages are not covered by insurance or are in excess of
policy limits, or if we incur liability at a time when we are not able to
obtain liability insurance, then our business, results of operations and
financial condition could be materially adversely affected.
Governmental agencies and other bodies, including those in California, might
impose regulations that increase our costs and may terminate or suspend our
operations.
Our business is subject to federal, state and local laws and regulations as
interpreted by governmental agencies and other bodies, including those in
California, vested with such authority relating to the exploration for, and the
development, production and transportation of, oil and gas, as well as
environmental and safety matters.
20
Under certain circumstances, the United States Minerals Management Service,
or MMS, may require that our operations on federal leases be suspended or
terminated. These circumstances include our failure to pay royalties or our
failure to comply with safety and environmental regulations. The requirements
imposed by these laws and regulations are frequently changed and subject to new
interpretations. It is likely that the costs of compliance could increase the
cost of operating offshore drilling equipment or significantly limit drilling
activity.
Our offshore California operations are subject to substantial regulations and
risks, which could adversely affect our ability to operate and our financial
results.
We conduct operations offshore California. Our offshore California
activities are subject to more extensive governmental regulation than our other
oil and gas activities. In addition, we are vulnerable to the risks associated
with operating offshore, including risks relating to:
. adverse weather conditions;
. oil field service costs and availability;
. compliance with environmental and other laws and regulations;
. remediation and other costs resulting from oil spills or releases of
hazardous materials; and
. failure of equipment or facilities.
If we experience any of these events, we may incur substantial liabilities,
which could adversely affect our operations and financial results.
Environmental liabilities could adversely affect our financial condition.
The oil and gas business is subject to environmental hazards, such as oil
spills, gas leaks and ruptures and discharges of petroleum products and
hazardous substances, and historic disposal activities. These environmental
hazards could expose us to material liabilities for property damages, personal
injuries or other environmental harm, including costs of investigating and
remediating contaminated properties. In addition, we also may be liable for
environmental damages caused by the previous owners or operators of properties
we have purchased or are currently operating. A variety of stringent federal,
state and local laws and regulations govern the environmental aspects of our
business and impose strict requirements for, among other things:
. well drilling or workover, operation and abandonment;
. waste management;
. land reclamation;
. financial assurance under the Oil Pollution Act of 1990; and
. controlling air, water and waste emissions.
Any noncompliance with these laws and regulations could subject us to
material administrative, civil or criminal penalties or other liabilities.
Additionally, our compliance with these laws may, from time to time, result in
increased costs to our operations or decreased production, and may affect our
costs of acquisitions.
In addition, environmental laws may, in the future, cause a decrease in our
production or cause an increase in our costs of production, development or
exploration. Pollution and similar environmental risks generally are not fully
insurable.
21
Some fields in our onshore California and Illinois properties have been in
operation for more than 90 years, and current or future local, state and
federal environmental and other laws and regulations may require substantial
expenditures to remediate the properties or to otherwise comply with these laws
and regulations, or to spend material amounts to comply with these laws and
regulations. In addition, approximately 183 acres of our 450 acres in the
Montebello field have been designated as California Coastal Sage Scrub, a known
habitat for the gnatcatcher, which is a species of bird designated as a federal
threatened species under the Endangered Species Act, or ESA. A variety of
existing laws, rules and guidelines govern activities that can be conducted on
properties that contain Coastal Sage Scrub and gnatcatchers and generally limit
the scope of operations that we can conduct on this property. The presence of
Coastal Sage Scrub and gnatcatchers on the Montebello field and other existing
or future laws, rules and guidelines could prohibit or limit our operations and
our planned activities for this property.
Our acquisition strategy could fail or present unanticipated problems for our
business in the future, which could adversely affect our ability to make
acquisitions or realize anticipated benefits of those acquisitions.
Our growth strategy may include acquiring oil and gas businesses and
properties. We may not be able to identify suitable acquisition opportunities
or finance and complete any particular acquisition successfully. Furthermore,
acquisitions involve a number of risks and challenges, including:
. diversion of management's attention;
. the need to integrate acquired operations;
. potential loss of key employees and customers of the acquired companies;
. potential lack of operating experience in a geographic market of the
acquired business; and
. an increase in our expenses and working capital requirements.
Any of these factors could adversely affect our ability to achieve
anticipated levels of cash flows from our acquired businesses or realize other
anticipated benefits of those acquisitions.
We intend to continue hedging a portion of our production, which may result in
our making cash payments or prevent us from receiving the full benefit of
increases in prices for oil and gas.
We reduce our exposure to the volatility of oil and gas prices by actively
hedging a portion of our production. Hedging will also prevent us from
receiving the full advantage of increases in oil or gas prices above the fixed
amount specified in the hedge agreement. In a typical hedge transaction, we
have the right to receive from the hedge counterparty the excess of the fixed
price specified in the hedge agreement over a floating price based on a market
index, multiplied by the quantity hedged. If the floating price exceeds the
fixed price, we are required to pay the counterparty this difference multiplied
by the quantity hedged even if we had insufficient production to cover the
quantities specified in the hedge agreement. Accordingly, any production
shortfalls that result in us having significantly less production than we have
hedged when the floating price exceeds the fixed price would result in us being
required to make payments where we had no offsetting sales of production. If
these payments become too large, the remainder of our business may be adversely
affected. In addition, our hedging agreements expose us to risk of financial
loss if the counterparty to a hedging contract defaulted on its contract
obligations.
Loss of key executives and failure to attract qualified management could limit
our growth and negatively impact our operations.
The successful implementation of our strategies will depend, in part, on
Plains Resources' management team and, after the spin-off, our management team.
The loss of members of Plains
22
Resources' management or, after the spin-off, our management team could have an
adverse effect on our business. Our exploitation success and the success of
other activities integral to our operations will depend, in part, on Plains
Resources' ability, and after our spin-off our ability, to attract and retain
experienced engineers, geoscientists and other professionals. Competition for
experienced professionals is extremely intense. If we or Plains Resources
cannot attract or retain experienced technical personnel, our ability to
compete could be harmed.
Plains Resources will be able to exert significant influence over our
operations and may exert its influence in a manner adverse to us or you.
Plains Resources owns 100% of our outstanding common stock. As a result,
Plains Resources will be able to significantly influence our board of directors
and effectively control all matters that our stockholders vote upon, even if
other directors or stockholders oppose them. These matters include the election
of directors and significant transactions, such as business combinations. Such
concentration of ownership may have the effect of delaying, deterring or
preventing a change of control or other business combinations which would be
economically beneficial to us or our noteholders.
Plains Resources and its subsidiaries have conflicts of interest with us and
with you and, as such, may not always act in our best interest.
We and Plains Resources and its subsidiaries share and, therefore will
compete for, the time and effort of Plains Resources personnel who provide
services to us, including directors, officers and other personnel. Officers of
Plains Resources and its subsidiaries do not, and will not be required to,
spend any specified percentage or amount of time on our business. Since these
officers and directors function as both our representatives and those of Plains
Resources and its subsidiaries, conflicts of interest could arise between
Plains Resources and its subsidiaries, on the one hand, and us or you, on the
other.
Additionally, some of these officers and directors own and are awarded from
time to time shares, or options to purchase shares, of Plains Resources.
Accordingly, their financial interests may not always be aligned with ours or
yours and could create, or appear to create, potential conflicts of interest
when these officers and directors are faced with decisions that could have
different implications for us and Plains Resources.
Some other situations in which an actual or potential conflict of interest
arises between us, on the one hand, and Plains Resources or its subsidiaries,
on the other hand, and there is a benefit to Plains Resources or its
subsidiaries in which neither we nor you will share include payments made under
our transition services agreement to Plains Resources consisting principally of
reimbursements for general and administrative expenses and employee costs.
Plains Resources and its subsidiaries may not always act in your best
interest, even though doing so may appear to:
. protect and enhance Plains Resources' investment in us;
. generate substantial cash flows to Plains Resources; and
. provide Plains Resources with efficiently priced capital for its planned
acquisitions.
We have entered into a number of agreements with Plains Resources including
agreements concerning management of our business and employee and tax matters.
See "Certain Transactions".
23
Risks Relating to the Reorganization and Spin-off
Our historical financial results as subsidiaries of Plains Resources may not be
representative of our results as a separate company.
The historical financial information included in this prospectus does not
necessarily reflect what our financial position, results of operations and cash
flows would have been had we been a separate, stand-alone entity during the
periods presented. Our costs and expenses reflect charges from Plains Resources
for centralized corporate services and infrastructure costs. These allocations
have been determined based on what we and Plains Resources considered to be
reasonable reflections of the utilization of services provided to us or for the
benefits received by us. This historical financial information is not
necessarily indicative of what our results of operations, financial position
and cash flows will be in the future. We may experience significant changes in
our cost structure, funding and operations as a result of our reorganization
and spin-off from Plains Resources, including increased costs associated with
reduced economies of scale, and increased costs associated with being a
publicly traded, stand-alone company.
Under our tax allocation agreement, if we take actions that cause the
distribution of our stock by Plains Resources to its stockholders to fail to
qualify as a tax-free transaction, we will be required to indemnify Plains
Resources for the resulting tax liability and may not have sufficient financial
resources to achieve our growth strategy or may prevent a change in control of
us.
Plains Resources intends to distribute its shares of our common stock to
its stockholders pursuant to the spin-off and has obtained a ruling from the
IRS stating that, for United States federal income tax purposes, the spin-off
will be generally tax-free to Plains Resources and its stockholders.
We have agreed with Plains Resources that we will not take any action
inconsistent with any information, covenant or representation provided to the
IRS in connection with obtaining the tax ruling stating that the spin-off will
generally be tax-free to Plains Resources and its stockholders and have further
agreed to be liable for any taxes arising from a breach of that agreement. In
addition, we have agreed that, during the three-year period following the
spin-off, we will not engage in transactions that could adversely affect the
tax treatment of the spin-off without the prior written consent of Plains
Resources, unless we obtain a supplemental tax ruling from the IRS or a tax
opinion acceptable to Plains Resources of nationally recognized tax counsel to
the effect that the proposed transaction would not adversely affect the tax
treatment of the spin-off. Moreover, we will be liable to Plains Resources for
any corporate level taxes incurred by Plains Resources as a result of the
spin-off or to specified transactions involving us following the spin-off
including the acquisition of 50% of our common stock by any person or persons.
To the extent the taxes arise as a result of a change of control of Plains
Resources, failure of Plains Resources to continue the active conduct of its
trade or business or failure of Plains Resources to comply with the
representations underlying its tax ruling or a supplemental tax ruling relating
to the spin-off, Plains Resources will be solely responsible for the taxes
resulting from the spin-off. If there are any corporate level taxes incurred by
Plains Resources as a result of the spin-off and not due to any of the factors
discussed in the two preceding sentences, we would be responsible for 50% of
any such liability. The amount of any indemnification payments would be
substantial and would likely result in events of default under all of our
credit agreements. As a result, we likely would not have sufficient financial
resources to achieve our growth strategy or, possibly, repay our indebtedness
after making these payments.
Current tax law provides that, depending on the facts and circumstances,
the distribution of our stock by Plains Resources, if it occurs, may be taxable
to Plains Resources if we undergo a 50% or greater change in stock ownership
within two years after the distribution. Under agreements between us and Plains
Resources, Plains Resources is entitled to require us to reimburse any tax
costs incurred
24
by Plains Resources as a result of a transaction resulting in a change in
control of us. These costs may be so great that they delay or prevent a
strategic acquisition or change in control of us.
We may in the future take accounting charges against our earnings as a result
of a "split" of existing Plains Resources stock options into new Plains
Resources stock options and stock appreciation rights with respect to our
common stock in connection with the spin-off.
At the time of the spin-off, pursuant to our employee matters agreement
with Plains Resources detailed on pages 89-90, all outstanding options to
acquire Plains Resources common stock at the time of the spin-off would be
"split" into (1) an equal number of options to acquire Plains Resources common
stock and (2) a number of stock appreciation rights, or SARs, with respect to
our common stock equal to the number of original Plains Resources stock options
multiplied by the spin-off distribution ratio (the number of shares of our
common stock distributed in the spin-off for each share of Plains Resources
common stock then outstanding). The exercise price for the original Plains
Resources stock options would also be "split" between the new Plains Resources
stock options and the SARs based on the following relative amounts: the closing
price of Plains Resources common stock on the spin-off date less the closing
price (on a "when-issued" basis) of our common stock on the spin-off date, both
as reported on the NYSE, and such closing price of our common stock.
If the SARs are in-the-money at the time of the "split", then we would at
that time recognize an accounting charge as compensation expense equal to the
aggregate in-the-money value of the SARs deemed vested at that time. Assuming
that the value of a share of Plains Resources common stock before the spin-off
is equal to the closing trading price of Plains Resources common stock of
$20.45 on November 20, 2002 minus the value of one of our shares of common
stock, which we assume for purposes of this calculation to be $10.00, we would
incur the following initial charge in connection with the spin off:
Estimated #
Plains Resources Our Assumed Share SARs to be Charge to Effect on Basic
Share Price Price Outstanding Net Income Earnings Per Share
$20.45 $10.00 3.9 million $1.5 million $0.06
The amount of the charge could have a material adverse effect on our
results of operations.
In addition, SARs are subject to variable accounting treatment under U.S.
generally accepted accounting principles. As a result, at the end of each
quarter, we would compare the closing price of our common stock on the last day
of the quarter to the exercise price of each SAR. To the extent the closing
price exceeds the exercise price of each SAR, we would recognize such excess as
an accounting charge for the SAR's deemed vested in the quarter to the extent
such excess had not been recognized in previous quarters. If such excess were
to be less than the extent to which accounting charges had been recognized in
previous quarters, we would recognize the difference as income in the quarter.
These quarterly charges and income would make our results of operations depend,
in part, on fluctuations in the price of our common stock and could have a
material adverse effect on our results of operations.
25
STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This prospectus includes forward-looking statements on our current
expectations and projections about future events. Statements that are
predictive in nature, that depend upon or refer to future events or conditions,
or that include words such as "will", "would", "should", "plans", "likely",
"expects", "anticipates", "intends", "believes", "estimates", "thinks", "may",
and similar expressions, are forward-looking statements. These statements
involve known and unknown risks, uncertainties and other factors that may cause
our actual results and performance to be materially different from any future
results or performance expressed or implied by these forward-looking
statements. These factors include, among other things, those matters discussed
under the caption "Risk Factors," as well as the following:
. the consequences of any potential change in control of us or other change
in the relationship between us and Plains Resources, including Plains
Resources' contemplated spin-off of us;
. uncertainties inherent in the development and production of and
exploration for oil and gas and in estimating reserves;
. unexpected future capital expenditures (including the amount and nature
thereof);
. impact of oil and gas price fluctuations;
. the effects of competition;
. the success of our risk management activities;
. the availability (or lack thereof) of acquisition or combination
opportunities;
. the impact of current and future laws and governmental regulations;
. environmental liabilities that are not covered by an effective indemnity
or insurance; and
. general economic, market or business conditions.
All forward-looking statements in this prospectus are made as of the date
hereof, and you should not place undue certainty on these statements without
also considering the risks and uncertainties associated with these statements
and our business that are addressed in this prospectus. Moreover, although we
believe the expectations reflected in the forward-looking statements are based
upon reasonable assumptions, we can give no assurance that we will attain these
expectations or that any deviations will not be material.
26
THE EXCHANGE OFFER
For the purposes of this section, "we" means Plains Exploration &
Production Company, Plains E&P Company and the Subsidiary Guarantors.
Registration Rights
This is a summary of the material provisions of the registration rights
agreement, a copy of which is filed as an exhibit to the registration statement
of which this prospectus is a part.
At the closing of the offering of the Series A notes, we entered into a
registration rights agreement with the initial purchasers pursuant to which we
agreed, for the benefit of the holders of the Series A notes, to use our
reasonable best efforts to file an exchange offer registration statement with
the SEC with respect to the exchange offer for the Series B notes.
Upon the exchange offer registration statement being declared effective, we
agreed to promptly offer the Series B notes in exchange for surrender of the
Series A notes. We agreed to use our reasonable best efforts to cause the
exchange offer to be consummated not later than 90 business days after the
exchange offer registration statement is declared effective by the SEC.
For each Series A note surrendered to us pursuant to the exchange offer,
the holder of such Series A note will receive a Series B note having a
principal amount equal to that of the surrendered Series A note. Interest on
each Series B note will accrue from the last interest payment date on which
interest was paid on the Series A note surrendered in exchange therefor or, if
no interest has been paid on such Series A note, from the date of its original
issue. The registration rights agreement also provides an agreement to include
in this prospectus certain information necessary to allow a broker-dealer who
holds Series A notes that were acquired for its own account as a result of
market-making activities or other ordinary course trading activities (other
than Series A notes acquired directly from us or one of our affiliates) to
exchange such Series A notes pursuant to the exchange offer and to satisfy the
prospectus delivery requirements in connection with resales of Series B notes
received by such broker-dealer in the exchange offer. We agreed to use our
reasonable best efforts to maintain the effectiveness of the exchange offer
registration statement for these purposes for a period of 180 days after the
closing of the exchange offer.
The preceding agreement is needed because any broker-dealer who acquires
Series A notes for its own account as a result of market-making activities or
other trading activities is required to deliver a prospectus meeting the
requirements of the Securities Act. This prospectus covers the offer and sale
of the Series B notes pursuant to the exchange offer made hereby and the resale
of Series B notes received in the exchange offer by any broker-dealer who held
Series A notes of the same series acquired for its own account as a result of
market-making activities or other trading activities other than Series A notes
acquired directly from us or one of our affiliates.
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that the Series B notes issued
pursuant to the exchange offer would in general be freely tradeable after the
exchange offer without further registration under the Securities Act. However,
any purchaser of Series A notes who is an "affiliate" of ours or who intends to
participate in the exchange offer for the purpose of distributing the related
Series B notes
. will not be able to rely on the interpretation of the staff of the SEC,
. will not be able to tender its Series A notes in the exchange offer, and
27
. must comply with the registration and prospectus delivery requirements of
the Securities Act in connection with any sale or transfer of the Series
A notes unless such sale or transfer is made pursuant to an exemption
from such requirements.
Each holder of the Series A notes (other than certain specified holders)
who wishes to exchange Series A notes for Series B notes in the exchange offer
will be required to make certain representations, including
. that any Series B notes received by it in the exchange offer will be
acquired in the ordinary course of business,
. that at the time of the commencement of the exchange offer it has no
arrangement or understanding with any person to participate in a
distribution of the Series B notes, and
. that it is not an affiliate of Plains Exploration & Production Company or
Plains E&P Company.
We further agreed to use our reasonable best efforts to cause to be filed
with the SEC a shelf registration statement as soon as practicable after any of
the following:
. we determine that we may not effect the exchange offer as contemplated in
this prospectus because it would violate any applicable law or applicable
interpretations of the staff of the SEC;
. the exchange offer is not for any other reason completed by December 30,
2002;
. any holder of Series A notes is prohibited by law or the applicable
interpretations of the staff of the SEC from participating in the
exchange offer; or does not receive freely transferable Series B notes on
the date of the exchange that may be sold without restriction under
federal and state securities laws; or
. any initial purchaser, upon completion of the exchange offer requests
that a shelf registration be made in connection with the sale or offering
of any of the Series B notes.
For the purposes of the registration rights agreement, transfer restricted
securities means each Series A note, until the earlier of:
. the date on which a registration statement covering that Series A note
has been declared effective by the SEC and that Series A note has been
disposed of pursuant to that registration statement;
. the date on which that Series A note has been exchanged in the exchange
offer for a Series B note that may be resold without restriction under
federal and state securities laws;
. the date on which that Series A note has been sold in compliance with
Rule 144 or is eligible to be sold pursuant to Rule 144(k) under the
Securities Act or any similar provision other than Rule 144A; or
. the date on which that Series A note ceases to be outstanding.
We agreed to use our reasonable best efforts to keep the shelf registration
statement continuously effective for a period ending on the earlier of:
. two years after the date of issuance of the Series A notes; or
. the date on which all of the transfer restricted securities covered by
the shelf registration statement have been sold pursuant to the shelf
registration statement.
28
The registration rights agreement provides that:
. if the exchange offer is not completed or any required shelf registration
statement is not declared effective on or prior to December 30, 2002, the
interest rate on the transfer restricted securities will be increased by
1.00% per annum until the exchange offer is completed or the shelf
registration statement is declared effective by the SEC or the Series A
notes become freely tradeable under the Securities Act;
. if any required shelf registration statement has been declared effective
and thereafter either ceases to be effective or the related prospectus
ceases to be usable at any time that we are obligated to maintain its
effectiveness and such failure to remain effective or usable exists for
more than 30 days (whether or not consecutive) in any 12-month period,
then the interest rate on the transfer restricted securities will be
increased by 1.00% per annum commencing on the 31st day in such 12-month
period and ending on the date that the shelf registration statement has
again been declared effective or the prospectus again becomes usable.
Holders of Series A notes will be required to make certain representations
to us (as described in the registration rights agreement) in order to
participate in the exchange offer and will be required to deliver information
to be used in connection with the shelf registration statement and to provide
comments on the shelf registration statement within the time periods set forth
in the registration rights agreement in order to have their Series A notes or
exchange notes included in the shelf registration statement.
Except as set forth above, after consummation of the exchange offer,
holders of Series A notes that are the subject of the exchange offer have no
registration or exchange rights under the registration rights agreement. See
"--Consequences of Failure to Exchange," and "--Resale of the Series B Notes;
Plan of Distribution."
Consequences of Failure to Exchange
The Series A notes which are not exchanged for Series B notes in the
exchange offer and are not included in a resale prospectus which, if required,
will be filed as part of an amendment to the registration statement of which
this prospectus is a part, will remain restricted securities and subject to
restrictions on transfer. Accordingly, such Series A notes may only be resold
(1) to us, upon redemption thereof or otherwise,
(2) so long as the Series A notes are eligible for resale pursuant to Rule
144A, to a person whom the seller reasonably believes is a qualified
institutional buyer within the meaning of Rule 144A under the
Securities Act, purchasing for its own account or for the account of a
qualified institutional buyer to whom notice is given that the resale,
pledge or other transfer is being made in reliance on Rule 144A,
(3) in an offshore transaction in accordance with Regulation S under the
Securities Act,
(4) pursuant to an exemption from registration in accordance with Rule 144,
if available, under the Securities Act,
(5) in reliance on another exemption from the registration requirements of
the Securities Act, or
(6) pursuant to an effective registration statement under the Securities
Act.
In all of the situations discussed above, the resale must be in accordance
with any applicable securities laws of any state of the United States and
subject to certain requirements of the registrar or co-registrar being met,
including receipt by the registrar or co-registrar of a certification and, in
the case of (3), (4) and (5) above, an opinion of counsel reasonably acceptable
to us and the registrar.
29
To the extent Series A notes are tendered and accepted in the exchange
offer, the principal amount of outstanding Series A notes will decrease with a
resulting decrease in the liquidity in the market therefor. Accordingly, the
liquidity of the market of the Series A notes could be adversely affected.
Terms of the Exchange Offer
Upon the terms and subject to the conditions set forth in this prospectus
and in the letter of transmittal, a copy of which is attached to this
prospectus as Annex A, we will accept any and all Series A notes validly
tendered and not withdrawn prior to the Expiration Date. We will issue $1,000
principal amount of Series B notes in exchange for each $1,000 principal amount
of Series A notes accepted in the exchange offer. Holders may tender some or
all of their Series A notes pursuant to the exchange offer. However, Series A
notes may be tendered only in integral multiples of $1,000 principal amount.
The form and terms of the Series B notes are the same as the form and terms
of the Series A notes, except that
. the Series B notes will have been registered under the Securities Act and
will not bear legends restricting their transfer pursuant to the
Securities Act, and
. except as otherwise described above, holders of the Series B notes will
not be entitled to the rights of holders of Series A notes under the
registration rights agreement.
The Series B notes will evidence the same debt as the Series A notes which
they replace, and will be issued under, and be entitled to the benefits of, the
indenture which governs all of the notes.
Solely for reasons of administration and for no other purpose, we have
fixed the close of business on , as the record date for the exchange
offer to determine the persons to whom this prospectus and the letter of
transmittal will be mailed initially. Only a registered holder of Series A
notes or such holder's legal representative or attorney-in-fact as reflected on
the records of the trustee under the indenture may participate in the exchange
offer. There will be no fixed record date for determining registered holders of
the Series A notes entitled to participate in the exchange offer.
Holders of the Series A notes do not have any appraisal or dissenters'
rights under Delaware law or the indenture in connection with the exchange
offer. We intend to conduct the exchange offer in accordance with the
applicable requirements of the Exchange Act and the rules and regulations of
the SEC thereunder.
We shall be deemed to have accepted validly tendered Series A notes when,
as and if we have given oral or written notice thereof to the exchange agent.
The exchange agent will act as agent for the tendering holders of the Series A
notes for the purposes of receiving the Series B notes. The Series B notes
delivered in the exchange offer will be issued on the earliest practicable date
following our acceptance for exchange of Series A notes.
If any tendered Series A 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 Series A notes will be
returned, without expense, to the tendering holder as promptly as practicable
after the Expiration Date.
Holders who tender Series A 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
the Series A notes in the exchange offer. We will pay all charges and
30
expenses, other than certain applicable taxes, in connection with the exchange
offer. See "--Fees and Expenses."
Expiration Date; Extensions; Amendments
The term "Expiration Date" with respect to the exchange offer means 5:00
p.m., New York City time, on unless we, in our sole discretion,
extend the exchange offer, in which case the term "Expiration Date" means the
latest date and time to which the exchange offer is extended.
If we extend the exchange offer, we will notify the exchange agent by oral
or written notice and will make a public announcement thereof, each prior to
9:00 a.m., New York City time, on the next business day after the previously
scheduled Expiration Date.
We reserve the right, in our sole discretion,
. to extend the exchange offer,
. if any of the conditions set forth below under "--Conditions to the
Exchange Offer" have not been satisfied, to terminate the exchange offer,
or
. to amend the terms of the exchange offer in any manner.
We may effect any such delay, extension or termination by giving oral or
written notice thereof to the exchange agent.
Except as specified in the second paragraph under this heading, we will
make a public announcement of any such delay in acceptance, extension,
termination or amendment as promptly as practicable. If we amend the exchange
offer in a manner determined by us to constitute a material change, we will
promptly disclose such amendment in a prospectus supplement that will be
distributed to the registered holders of the Series A notes. The exchange offer
will then be extended for a period of five to 10 business days, as required by
law, depending upon the significance of the amendment and the manner of
disclosure to the registered holders.
We will make a timely release of a public announcement of any delay,
extension, termination or amendment of the exchange offer to the Dow Jones News
Service.
Procedures for Tendering Series A Notes
Tenders of Series A Notes. The tender by a holder of Series A notes
pursuant to any of the procedures set forth below will constitute the tendering
holder's acceptance of the terms and conditions of the exchange offer. Our
acceptance for exchange of Series A notes tendered pursuant to any of the
procedures described below will constitute a binding agreement between such
tendering holder and us in accordance with the terms and subject to the
conditions of the exchange offer. Only holders are authorized to tender their
Series A notes. The procedures by which Series A notes may be tendered by
beneficial owners that are not holders will depend upon the manner in which the
Series A notes are held.
DTC has authorized DTC participants that are beneficial owners of Series A
notes through DTC to tender their Series A notes as if they were holders. To
effect a tender, DTC participants should
31
either (1) complete and sign the letter of transmittal or a facsimile thereof,
have the signature thereon guaranteed if required by Instruction 1 of the
letter of transmittal, and mail or deliver the letter of transmittal or such
facsimile pursuant to the procedures for book-entry transfer set forth below
under "--Book-entry delivery procedures," or (2) transmit their acceptance to
DTC through the DTC Automated Tender Offer Program, or ATOP, for which the
transaction will be eligible, and follow the procedures for book-entry
transfer, set forth below under "--Book-Entry Delivery Procedures."
Tender of Series A Notes Held in Physical Form. To tender effectively
Series A notes held in physical form in the exchange offer
. a properly completed letter of transmittal applicable to such notes (or a
facsimile thereof) duly executed by the tendering holder, and any other
documents required by the letter of transmittal, must be received by the
exchange agent at one of its addresses set forth in this prospectus, and
tendered Series A notes must be received by the exchange agent at such
address (or delivery effected through the deposit of Series A notes into
the exchange agent's account with DTC and making book-entry delivery as
set forth below), on or prior to the Expiration Date, or
. the tendering holder must comply with the guaranteed delivery procedures
set forth below.
Letters of transmittal or Series A notes should be sent only to the
exchange agent and should not be sent to us.
Tender of Series A Notes Held Through a Custodian. To tender effectively
Series A notes that are held of record by a custodian bank, depository, broker,
trust company or other nominee, the beneficial owner thereof must instruct such
holder to tender the Series A notes on the beneficial owner's behalf. A letter
of instructions from the record owner to the beneficial owner may be included
in the materials provided along with this prospectus which may be used by the
beneficial owner in this process to instruct the registered holder of such
owner's Series A notes to effect the tender.
Tender of Series A Notes Held Through DTC. To tender effectively Series A
notes that are held through DTC, DTC participants should either
. properly complete and duly execute the letter of transmittal (or a
facsimile thereof), and any other documents required by the letter of
transmittal, and mail or deliver the letter of transmittal or such
facsimile pursuant to the procedures for book-entry transfer set forth
below, or
. transmit their acceptance through ATOP, for which the transaction will be
eligible, and DTC will then edit and verify the acceptance and send an
Agent's Message to the exchange agent for its acceptance.
The term "Agent's Message" means a message transmitted by DTC to, and
received by, the exchange agent and forming a part of the Book-Entry
Confirmation, which states that DTC has received an express acknowledgment from
each participant in DTC tendering the Series A notes and that such participant
has received the letter of transmittal and agrees to be bound by the terms of
the letter of transmittal and we may enforce such agreement against such
participant.
Delivery of tendering Series A notes held through DTC must be made to the
exchange agent pursuant to the book-entry delivery procedures set forth below
or the tendering DTC participant must comply with the guaranteed delivery
procedures set forth below.
The method of delivery of Series A notes and letters of transmittal, any
required signature guarantees and all other required documents, including
delivery through DTC and any acceptance or Agent's Message transmitted through
ATOP, is at the election and risk of the person tendering Series A notes and
delivering letters of transmittal. Except as otherwise provided in the letter
of transmittal,
32
delivery will be deemed made only when actually received by the exchange agent.
If delivery is by mail, it is suggested that the holder use properly insured,
registered mail with return receipt requested, and that the mailing be made
sufficiently in advance of the Expiration Date to permit delivery to the
exchange agent prior to such date.
Except as provided below, unless the Series A notes being tendered are
deposited with the exchange agent on or prior to the Expiration Date
(accompanied by a properly completed and duly executed letter of transmittal or
a properly transmitted Agent's Message), we may, at our option, reject such
tender. Exchange of Series B notes for Series A notes will be made only against
deposit of the tendered Series A notes and delivery of all other required
documents.
Book-Entry Delivery Procedures. The exchange agent will establish accounts
with respect to the Series A notes at DTC for purposes of the exchange offer
within two business days after the date of this prospectus, and any financial
institution that is a participant in DTC may make book-entry delivery of the
Series A notes by causing DTC to transfer such Series A notes into the exchange
agent's account in accordance with DTC's procedures for such transfer. However,
although delivery of Series A notes may be effected through book-entry at DTC,
the letter of transmittal (or facsimile thereof), with any required signature
guarantees or an Agent's Message in connection with a book-entry transfer, and
any other required documents, must, in any case, be transmitted to and received
by the exchange agent at one or more of its addresses set forth in this
prospectus on or prior to the Expiration Date, or compliance must be made with
the guaranteed delivery procedures described below. Delivery of documents to
DTC does not constitute delivery to the exchange agent. The confirmation of a
book-entry transfer into the exchange agent's account at DTC as described above
is referred to as a "Book-Entry Confirmation."
Signature Guarantees. Signatures on all letters of transmittal must be
guaranteed by a recognized member of the Medallion Signature Guarantee Program
or by any other "eligible guarantor institution," as such term is defined in
Rule 17Ad-15 promulgated under the Exchange Act (each of the foregoing, an
"Eligible Institution"), unless the Series A notes tendered thereby are
tendered (1) by a registered holder of Series A notes (or by a participant in
DTC whose name appears on a DTC security position listing as the owner of such
Series A notes) who has not completed either the box entitled "Special Issuance
Instructions" or "Special Delivery Instructions" on the letter of transmittal,
or (2) for the account of an Eligible Institution. See Instruction 1 of the
letter of transmittal. If the Series A notes are registered in the name of a
person other than the signer of the letter of transmittal or if Series A notes
not accepted for exchange or not tendered are to be returned to a person other
than the registered holder, then the signatures on the letter of transmittal
accompanying the tendered Series A notes must be guaranteed by an Eligible
Institution as described above. See Instructions 1 and 5 of the letter of
transmittal.
Guaranteed Delivery. If a holder desires to tender Series A notes pursuant
to the exchange offer and time will not permit the letter of transmittal,
certificates representing such Series A notes and all other required documents
to reach the exchange agent, or the procedures for book-entry transfer cannot
be completed, on or prior to the Expiration Date, such Series A notes may
nevertheless be tendered if all the following conditions are satisfied:
. the tender is made by or through an Eligible Institution;
. a properly completed and duly executed notice of guaranteed delivery,
substantially in the form provided by us herewith, or an Agent's Message
with respect to guaranteed delivery that is accepted by us, is received
by the exchange agent on or prior to the Expiration Date, as provided
below; and
33
. the certificates for the tendered Series A notes, in proper form for
transfer (or a Book-Entry Confirmation of the transfer of such Series A
notes into the exchange agent's account at DTC as described above),
together with the letter of transmittal (or facsimile thereof), property
completed and duly executed, with any required signature guarantees and
any other documents required by the letter of transmittal or a properly
transmitted Agent's Message, are received by the exchange agent within
two business days after the date of execution of the notice of guaranteed
delivery.
The notice of guaranteed delivery may be sent by hand delivery, telegram,
facsimile transmission or mail to the exchange agent and must include a
guarantee by an Eligible Institution in the form set forth in the notice of
guaranteed delivery.
Notwithstanding any other provision hereof, delivery of Series B notes by
the exchange agent for Series A notes tendered and accepted for exchange
pursuant to the exchange offer will, in all cases, be made only after timely
receipt by the exchange agent of such Series A notes (or Book-Entry
Confirmation of the transfer of such Series A notes into the exchange agent's
account at DTC as described above), and the letter of transmittal (or facsimile
thereof) with respect to such Series A notes, properly completed and duly
executed, with any required signature guarantees and any other documents
required by the letter of transmittal, or a properly transmitted Agent's
Message.
Determination of Validity. All questions as to the validity, form,
eligibility (including time of receipt), acceptance and withdrawal of tendered
Series A notes will be determined by us in our sole discretion, which
determination will be final and binding. We reserve the absolute right to
reject any and all Series A notes not properly tendered or any Series A notes
our acceptance of which, in the opinion of our counsel, would be unlawful.
We also reserve the right to waive any defects, irregularities or
conditions of tender as to particular Series A notes. The interpretation of the
terms and conditions of our exchange offer (including the instructions in the
letter of transmittal) by us will be final and binding on all parties. Unless
waived, any defects or irregularities in connection with tenders of Series A
notes must be cured within such time as we shall determine.
Although we intend to notify holders of defects or irregularities with
respect to tenders of Series A notes through the exchange agent, neither we,
the exchange agent nor any other person is under any duty to give such notice,
nor shall they incur any liability for failure to give such notification.
Tenders of Series A notes will not be deemed to have been made until such
defects or irregularities have been cured or waived.
Any Series A 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 Series A notes are submitted in a principal amount greater than
the principal amount of Series A notes being tendered by such tendering holder,
such unaccepted or non-exchanged Series A notes will either be
. returned by the exchange agent to the tendering holders, or
. in the case of Series A notes tendered by book-entry transfer into the
exchange agent's account at the book-entry transfer facility pursuant to
the book-entry transfer procedures described below, credited to an
account maintained with such book-entry transfer facility.
By tendering, each registered holder will represent to us that, among other
things,
. the Series B notes to be acquired by the holder and any beneficial
owner(s) of the Series A notes in connection with the exchange offer are
being acquired by the holder and any beneficial owner(s) in the ordinary
course of business of the holder and any beneficial owner(s),
34
. the holder and each beneficial owner are not participating, do not intend
to participate, and have no arrangement or understanding with any person
to participate, in a distribution of the Series B notes,
. the holder and each beneficial owner acknowledge and agree that (x) any
person participating in the exchange offer for the purpose of
distributing the Series B notes must comply with the registration and
prospectus delivery requirements of the Securities Act in connection with
a secondary resale transaction with respect to the Series B notes
acquired by such person and cannot rely on the position of the Staff of
the SEC set forth in no-action letters that are discussed herein under
"--Resale of the Series B Notes; Plan of Distribution," and (y) any
broker-dealer that receives Series B notes for its own account in
exchange for Series A notes pursuant to the exchange offer must deliver a
prospectus in connection with any resale of such Series B notes, but by
so acknowledging, the holder shall not be deemed to admit that, by
delivering a prospectus, it is an "underwriter" within the meaning of the
Securities Act,
. neither the holder nor any beneficial owner is an "affiliate," as defined
under Rule 405 of the Securities Act, of ours except as otherwise
disclosed to us in writing, and
. the holder and each beneficial owner understands that a secondary resale
transaction described in the third bullet above should be covered by an
effective registration statement containing the selling securityholder
information required by Item 507 of Regulation S-K of the SEC.
Each broker-dealer that receives Series B notes for its own account in
exchange for Series A notes, where such Series A notes were acquired by such
broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of such Series B notes. See "--Resale of the Series B Notes;
Plan of Distribution."
Withdrawal of Tenders
Except as otherwise provided herein, tenders of Series A notes in the
exchange offer may be withdrawn, unless accepted for exchange as provided in
the exchange offer, at any time prior to the Expiration Date.
To be effective, a written or facsimile transmission notice of withdrawal
must be received by the exchange agent at its address set forth herein prior to
the Expiration Date. Any such notice of withdrawal must
. specify the name of the person having deposited the Series A notes to be
withdrawn,
. identify the Series A notes to be withdrawn, including the certificate
number or numbers of the particular certificates evidencing the Series A
notes (unless such Series A notes were tendered by book-entry transfer),
and aggregate principal amount of such Series A notes, and
. be signed by the holder in the same manner as the original signature on
the letter of transmittal (including any required signature guarantees)
or be accompanied by documents of transfer sufficient to have the trustee
under the indenture register the transfer of the Series A notes into the
name of the person withdrawing such Series A notes.
If Series A notes have been delivered pursuant to the procedures for
book-entry transfer set forth in "--Procedures for Tendering Series A
Notes--Book-Entry Delivery Procedures," any notice of withdrawal must specify
the name and number of the account at the appropriate book-entry transfer
facility to be credited with such withdrawn Series A notes and must otherwise
comply with such book-entry transfer facility's procedures.
35
If the Series A notes to be withdrawn have been delivered or otherwise
identified to the exchange agent, a signed notice of withdrawal meeting the
requirements discussed above is effective immediately upon written or facsimile
notice of withdrawal even if physical release is not yet effected. A withdrawal
of Series A notes can only be accomplished in accordance with these procedures.
All questions as to the validity, form and eligibility (including time of
receipt) of such notices will be determined by us in our sole discretion, which
determination shall be final and binding on all parties. No withdrawal of
Series A notes will be deemed to have been properly made until all defects or
irregularities have been cured or expressly waived. Neither we, the exchange
agent nor any other person will be under any duty to give notification of any
defects or irregularities in any notice of withdrawal or revocation, nor shall
we or they incur any liability for failure to give any such notification. Any
Series A notes so withdrawn will be deemed not to have been validly tendered
for purposes of the exchange offer and no Series B notes will be issued with
respect thereto unless the Series A notes so withdrawn are retendered. Properly
withdrawn Series A notes may be retendered by following one of the procedures
described above under "--Procedures for Tendering Series A Notes" at any time
prior to the Expiration Date.
Any Series A notes which have been tendered but which are not accepted for
exchange due to the rejection of the tender due to uncured defects or the prior
termination of the exchange offer, or which have been validly withdrawn, will
be returned to the holder thereof unless otherwise provided in the letter of
transmittal, as soon as practicable following the Expiration Date or, if so
requested in the notice of withdrawal, promptly after receipt by us of notice
of withdrawal without cost to such holder.
Conditions to the Exchange Offer
The exchange offer shall not be subject to any conditions, other than that
. the SEC has issued an order or orders declaring the indenture governing
the notes qualified under the Trust Indenture Act of 1939,
. the exchange offer, or the making of any exchange by a holder, does not
violate applicable law or any applicable interpretation of the staff of
the SEC,
. no action or proceeding shall have been instituted or threatened in any
court or by or before any governmental agency with respect to the
exchange offer, which, in our judgment, might impair our ability to
proceed with the exchange offer,
. there shall not have been adopted or enacted any law, statute, rule or
regulation which, in our judgment, would materially impair our ability to
proceed with the exchange offer, or
. there shall not have occurred any material change in the financial
markets in the United States or any outbreak of hostilities or escalation
thereof or other calamity or crisis the effect of which on the financial
markets of the United States, in our judgment, would materially impair
our ability to proceed with the exchange offer.
If we determine in our reasonable discretion that any of the conditions to
the exchange offer are not satisfied, we may
. refuse to accept any Series A notes and return all tendered Series A
notes to the tendering holders,
. extend the exchange offer and retain all Series A notes tendered prior to
the Expiration Date, subject, however, to the rights of holders to
withdraw such Series A notes, or
. waive such unsatisfied conditions with respect to the exchange offer and
accept all validly tendered Series A notes which have not been withdrawn.
36
If such waiver constitutes a material change to the exchange offer, we will
promptly disclose such waiver by means of a prospectus supplement that will be
distributed to the registered holders, and will extend the exchange offer for a
period of five to 10 business days, 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 five to 10 business day period.
Exchange Agent
JPMorgan Chase Bank, the trustee under the indenture governing the notes,
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
and other documents should be directed to the exchange agent addressed as
follows:
By Mail:
JPMorgan Chase Bank
600 Travis Street, Suite 1500
Houston, Texas 77002
Attention: Rebecca Newman
By Facsimile:
(713) 577-5200
Attention: Rebecca Newman
Confirm by Telephone:
(713) 216-4931
Attention: Rebecca Newman
By Hand:
JPMorgan Chase Bank
600 Travis Street, Suite 1500
Houston, Texas 77002
Attention: Rebecca Newman
Fees and Expenses
We will bear the expenses of soliciting tenders. The principal solicitation
is being made by mail; however, additional solicitation may be made by
telegraph, telecopy, telephone or in person by officers and regular employees
of Plains Exploration & Production Company or our affiliates.
No dealer-manager has been retained in connection with the exchange offer
and no payments will be made to brokers, dealers or others soliciting
acceptance of the exchange offer. However, reasonable and customary fees will
be paid to the exchange agent for its services and it will be reimbursed for
its reasonable out-of-pocket expenses.
Our out of pocket expenses for the exchange offer will include fees and
expenses of the exchange agent and the trustee under the indenture, accounting
and legal fees and printing costs, among others.
We will pay all transfer taxes, if any, applicable to the exchange of the
Series A notes pursuant to the exchange offer. If, however, a transfer tax is
imposed for any reason other than the exchange of
37
the Series A 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.
Accounting Treatment for Exchange Offer
The Series B notes will be recorded at the carrying value of the Series A
notes and no gain or loss for accounting purposes will be recognized. The
expenses of the exchange offer will be amortized over the term of the Series B
notes.
Resale of the Series B Notes; Plan of Distribution
Each broker-dealer that receives Series B notes for its own account
pursuant to the exchange offer must acknowledge that it will deliver a
prospectus in connection with any resale of Series B notes. 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 Series B notes received in exchange
for Series A notes where such Series A notes were acquired as a result of
market-making activities or other trading activities. In addition, until
(90 days after the date of this prospectus), all dealers effecting transactions
in the Series B notes, whether or not participating in this distribution, may
be required to deliver a prospectus. This requirement is in addition to the
obligation of dealers to deliver a prospectus when acting as underwriters and
with respect to their unsold allotments or subscriptions.
We will not receive any proceeds from any sale of Series B notes by
broker-dealers. Series B 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 Series B 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
. at 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 or the purchasers of any such Series B
notes.
Any broker-dealer that resells Series B notes that were received by it for
its own account pursuant to the exchange offer and any broker or dealer that
participates in a distribution of such Series B notes may be deemed to be an
"underwriter" within the meaning of the Securities Act and any profit on any
such resale of Series B notes and any commission on concessions received by any
such persons may be deemed to be underwriting compensation under the Securities
Act. The letter of transmittal states that, by acknowledging that it will
deliver a prospectus 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.
We agreed to permit the use of this prospectus by such broker-dealers to
satisfy this prospectus delivery requirement. To the extent necessary to ensure
that the prospectus is available for sales of
38
Series B notes by broker-dealers, we agreed to use our reasonable best efforts
to keep the exchange offer registration statement continuously effective,
supplemented, amended and current for a period of 180 days from the closing of
the exchange offer. We will provide sufficient copies of the latest version of
this prospectus to such broker-dealers no event later than one day after such
request at any time during this period.
USE OF PROCEEDS
The exchange offer is intended to satisfy our obligations under the
registration rights agreement. We will not receive any cash proceeds from the
issuance of the Series B notes offered by this prospectus. In consideration for
issuing the Series B notes as contemplated in this prospectus, we will receive
in exchange Series A notes in like principal amount, the form and terms of
which are the same as the form and terms of the Series B notes, except as
otherwise described herein under "The Exchange Offer--Terms of the Exchange
Offer." The Series A notes surrendered in exchange for the Series B notes will
be retired and canceled and cannot be reissued. Accordingly, issuance of the
Series B notes will not result in any increase in our indebtedness.
39
CAPITALIZATION
The following table sets forth our capitalization as of September 30, 2002.
You should read the capitalization data set forth in the table below in
conjunction with "Use of Proceeds", "Selected Historical Consolidated and
Combined Financial and Other Data", "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and our historical combined
financial statements and the notes appearing elsewhere in this prospectus.
As of
September 30,
2002
--------------
(In thousands)
Cash and cash equivalents.............. $ 766
========
Total debt:
Revolving credit facility............. $ 90,700
8.75% notes, net of discount of $3,197 196,803
Other long-term debt.................. 1,022
--------
Total debt.......................... 288,525
Stockholder's equity................... 134,730 (1)
Accumulated other comprehensive income. (14,603)
--------
Total capitalization................... $408,652
========
- --------
(1) Prior to July 2002 certain of our operations were conducted by Stocker
Resources L.P., a limited partnership of which Plains Resources and one of
its subsidiaries were the limited and general partners. As a result, when
the spin-off occurs the tax basis of certain assets and liabilities related
to such operations will be retained by Plains Resources. Accordingly, upon
the consummation of the spin-off, our stockholder's equity will decrease by
$5.3 million and our deferred tax liability will increase by a
corresponding amount to reflect the effect of the tax basis that will be
retained by Plains Resources for tax reporting purposes.
40
SELECTED HISTORICAL CONSOLIDATED AND COMBINED FINANCIAL AND OTHER DATA
The following table summarizes the consolidated and combined statements of
income and combined balance sheets data for our business since January 1, 1997.
These data have been derived from (i) the audited combined statements of income
for our business for each of the years ended December 31, 2001, 2000, and 1999
and combined balance sheets for our business as of December 31, 2001 and 2000,
(ii) the unaudited combined statements of income for our business for each of
the years ended December 31, 1998 and 1997 and combined balance sheets for our
business as of December 31, 1999, 1998 and 1997 and (iii) the unaudited
consolidated statements of income and balance sheets of our business as of and
for each of the nine months ended September 30, 2002 and 2001. You should read
this information in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and our historical combined
financial statements and notes included elsewhere in this prospectus. The
information set forth below is not necessarily indicative of our future results.
Nine Months Ended
September 30, Year Ended December 31,
------------------ ------------------------------------------------
2002 2001 2001 2000 1999 1998 1997
-------- -------- -------- -------- -------- -------- --------
(In thousands)
Statement of Income Data:
Revenues:
Oil and liquids................... $129,563 $133,957 $174,895 $126,434 $102,390 $ 81,416 $ 81,381
Gas............................... 7,130 26,870 28,771 16,017 5,095 4,091 3,805
Other operating revenues.......... 27 468 473 -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Total revenues............... 136,720 161,295 204,139 142,451 107,485 85,507 85,186
-------- -------- -------- -------- -------- -------- --------
Costs and expenses:
Production expenses............... 56,826 47,995 63,795 56,228 50,527 42,823 36,571
General and administrative........ 7,326 7,074 10,210 6,308 4,367 3,218 2,724
Depreciation, depletion and
amortization..................... 21,262 16,999 24,105 18,859 13,329 13,901 10,453
Reduction of carrying cost of oil
and gas properties(1)............ -- -- -- -- -- 42,920 --
-------- -------- -------- -------- -------- -------- --------
Total costs and
expenses.................... 85,450 72,068 98,110 81,395 68,223 102,862 49,748
-------- -------- -------- -------- -------- -------- --------
Income (loss) from operations....... 51,270 89,227 106,029 61,056 39,262 (17,355) 35,438
Expenses of terminated public
equity offering.................. (1,700) -- -- -- -- -- --
Interest expense.................. (14,427) (12,942) (17,411) (15,885) (14,912) (8,828) (5,113)
Interest and other income......... 114 459 463 343 87 74 88
-------- -------- -------- -------- -------- -------- --------
Income (loss) before income
taxes and cumulative effect of
accounting change.................. 35,257 76,744 89,081 45,514 24,437 (26,109) 30,413
Income tax (expense) benefit
Current........................... (5,660) (5,180) (6,014) (2,431) (505) (4,435) (10,916)
Deferred.......................... (8,097) (24,443) (28,374) (14,334) (4,827) 11,510 (1,364)
-------- -------- -------- -------- -------- -------- --------
Income (loss) before cumulative
effect of accounting change........ 21,500 47,121 54,693 28,749 19,105 (19,034) 18,133
Cumulative effect of accounting
change, net of tax benefit(2)...... -- (1,522) (1,522) -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)................... $ 21,500 $ 45,599 $ 53,171 $ 28,749 $ 19,105 $(19,034) $ 18,133
======== ======== ======== ======== ======== ======== ========
Earnings Per Share Basic and
Diluted:
Income (loss) before
cumulative effect of
accounting change................ $0.89 $ 1.95 $ 2.26 $ 1.19 $ 0.79 $ (0.79) $ 0.75
Cumulative effect of accounting
change........................... -- (0.06) (0.06) -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)................... $ 0.89 $ 1.89 $ 2.20 $ 1.19 $ 0.79 $ (0.79) $ 0.75
======== ======== ======== ======== ======== ======== ========
41
As of September 30, As of December 31,
------------------ --------------------------------------------------------
2002 2001 2001 2000 1999 1998 1997
-------- -------- -------- -------- ---------- ----------- -----------
(In thousands)
Balance Sheet Data:
Cash and cash equivalents..... $ 766 $ 13 $ 13 $ 536 $ 5,075 $ 138 $ 207
Working capital............... (50,500) 932 932 (6,861) 16,169 (12,148) (7,142)
Total assets.................. 541,056 516,755 516,755 401,035 360,964 277,792 239,712
Total debt.................... 288,525 1,533 236,694 227,040 240,172 180,483 122,331
Stockholder's/combined
owners' equity............... 120,127 180,087 180,087 111,032 82,283 63,177 85,776
Other Financial Data:
Ratios of earnings to fixed
charges(3)................. 3.0 5.8 5.2 3.1 2.1 --(4) 4.6
- --------
(1) Noncash charge related to a ceiling test write-down of the capitalized
costs of our proved oil and gas properties due to low oil prices at
December 31, 1998.
(2) Cumulative effect of adopting Statement of Financial Accounting Standards
No. 133--"Accounting for Derivatives," or SFAS 133.
(3) We have computed the ratios of earnings to fixed charges by dividing
earnings by fixed charges. For this purpose, "earnings" consist of income
before income taxes and the cumulative effect of accounting changes and
fixed charges. "Fixed charges" consist of interest expense, capitalized
interest and that portion of annual rental expenses we have deemed to
represent the interest factor.
(4) In 1998 earnings were insufficient to cover fixed charges by $29.2 million.
42
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
General
We are an independent oil and gas company primarily engaged in the upstream
activities of acquiring, exploiting, developing and producing oil and gas in
the United States. We are 100% owned by Plains Resources Inc. Our core areas of
operation are:
. onshore California, primarily in the LA Basin, and offshore California in
the Point Arguello unit; and
. the Illinois Basin in southern Illinois and Indiana.
We follow the full cost method of accounting whereby all costs associated
with property acquisition, exploration, exploitation and development activities
are capitalized. Our revenues are derived from the sale of oil, gas and natural
gas liquids. We recognize revenues when our production is sold and title is
transferred. Our revenues are highly dependent upon the prices of, and demand
for, oil and gas. Historically, the markets for oil and gas have been volatile
and are likely to continue to be volatile in the future. The prices we receive
for our oil and gas and our levels of production are subject to wide
fluctuations and depend on numerous factors beyond our control, including
supply and demand, economic conditions, foreign imports, the actions of OPEC,
political conditions in other oil-producing countries, and governmental
regulation, legislation and policies. Under the SEC's full cost accounting
rules, we review the carrying value of our proved oil and gas properties each
quarter. These rules generally require that we price our future oil and gas
production at the oil and gas prices in effect at the end of each fiscal
quarter to determine a ceiling value of our properties. The rules require a
write-down if our capitalized costs exceed the allowed "ceiling." We have had
no write-downs due to these ceiling test limitations since 1998. Given the
volatility of oil and gas prices, it is likely that our estimate of discounted
future net revenues from proved oil and gas reserves will fluctuate in the near
term. If oil and gas prices decline significantly in the future, write-downs of
our oil and gas properties could occur. Write-downs required by these rules do
not directly impact our cash flows from operating activities. Decreases in oil
and gas prices have had, and will likely have in the future, an adverse effect
on the carrying value of our proved reserves and our revenues, profitability
and cash flow.
To manage our exposure to commodity price risks, we use various derivative
instruments to hedge our exposure to oil sales price fluctuations. Our hedging
arrangements provide us protection on the hedged volumes if oil prices decline
below the prices at which these hedges are set. However, if oil prices
increase, ceiling prices in our hedges may cause us to receive less revenues on
the hedged volumes than we would receive in the absence of hedges. We do not
currently have any gas hedges. Gains and losses from hedging transactions are
recognized as revenues when the associated production is sold.
Our oil and gas production expenses include salaries and benefits of field
personnel, electric costs, maintenance costs, production, ad valorem and
severance taxes, and other costs necessary to operate our producing properties.
Depletion of capitalized costs of producing oil and gas properties is provided
using the units of production method based upon proved reserves. For the
purposes of computing depletion, proved reserves are redetermined as of the end
of each year and on an interim basis when deemed necessary. General and
administrative expenses consist primarily of salaries and related benefits of
administrative personnel, office rent, systems costs and other administrative
costs. We estimate that as a result of the reorganization and spin-off our
annual general and administrative expenses will increase by approximately $5.3
million over the amount reported for the year ended December 31, 2001
reflecting the incremental costs of operating as a separate, publicly-held
company.
Tax expense and effective tax rates have been calculated based on the tax
sharing agreement covering all the members of the consolidated group on a
combined basis for such periods.
43
Corporate Reorganization and Terminated Initial Public Offering
Under the terms of a Master Separation Agreement between us and Plains
Resources, on July 3, 2002 Plains Resources contributed to us: (i) 100% of the
capital stock of its wholly owned subsidiaries Arguello Inc., Plains Illinois,
Inc., PMCT Inc. and Plains Resources International Inc.; and (ii) all amounts
payable to it by us and our subsidiary companies. These transactions are
referred to as the "reorganization". In addition, in September 2002 Plains
Resources made: (i) a $5.0 million cash contribution to us; and (ii) a $7.2
million contribution to us in the form of a promissory note payable, both as
part of the working capital for upstream assets contributed to us. The
promissory note bears interest at 2.5% and is due on December 15, 2002. The
contribution of the amounts payable to Plains Resources, the cash contribution
and the contribution of the promissory note are all reflected in Stockholder's
Equity. In addition, Plains Resources may contribute up to $42.8 million to us
before the spin-off.
On June 21, 2002 we filed a registration statement on Form S-1 with the SEC
for the initial public offering, or the IPO, of our common stock. We terminated
the IPO in October 2002, primarily due to market conditions. As a result, costs
and expenses of $1.7 million incurred in connection with the IPO were charged
to expense during the third quarter of 2002. We estimate that additional
charges of $0.7 to $0.8 million will occur in the fourth quarter of 2002.
Financings
On July 3, 2002, we and Plains E&P Company, our wholly owned subsidiary
that has no material assets and was formed for the sole purpose of being a
corporate co-issuer of certain of our indebtedness, issued in a private
offering, at an issue price of 98.376%, $200.0 million of Series A notes that
are subject to the exchange offer contemplated by this prospectus. The Series A
notes are our unsecured general obligations, are subordinated in right of
payment to all of our existing and future senior indebtedness and are jointly
and severally guaranteed on a full, unconditional basis by all of our existing
and future domestic restricted subsidiaries. Also on July 3, 2002 we entered
into a $300.0 million revolving credit facility with a $225.0 million borrowing
base.
The net proceeds from the Series A notes, $195.3 million after deducting
issue discount and underwriting fees, and $117.6 million initially borrowed
under our credit facility were used: (i) to make a $312.0 million cash
distribution to Plains Resources; and (ii) to pay $0.9 million in fees related
to the PXP credit facility. Plains Resources used the proceeds from the cash
distribution to retire its outstanding 10.25% senior subordinated notes and all
amounts outstanding under its revolving credit facility. Our guarantees of
Plains Resources' debt facilities were terminated when it retired such
obligations.
For a complete discussion of these transactions and the terms and
conditions of the Series A notes and our credit facility, see "Liquidity and
Capital Resources--Debt".
Purchase of Additional Interest in Point Arguello Unit
In August 2002 we acquired an additional 26.3% working interest in the
Point Arguello unit and the various partnerships owning the related
transportation, processing and marketing infrastructure. The seller retained
responsibility for certain abandonment costs, including: (1) removing,
dismantling and disposing of the existing offshore platforms; (2) removing and
disposing of all pipelines; and (3) removing, dismantling, disposing and
remediating all existing onshore facilities. We assumed the seller's share of
the costs of plugging the wells and flushing the lines. As consideration for
receiving the transferred properties and assuming the obligations described
above, we received $2.4 million in cash for the sale and $3.0 million as our
share of revenues less costs for the period from April 1 to July 30, 2002. This
transaction doubled our working interest in the Point Arguello unit to 52.6%.
44
Results of Operations
The following table reflects the components of our oil and gas sales prices
and sets forth our operating revenues and costs and expenses on a BOE basis:
Nine Months
Ended
September 30, Year Ended December 31,
-------------- ----------------------
2002 2001 2001 2000 1999
------ ------ ------ ------ ------
Average oil sales price ($/Bbl)
Average NYMEX....................... $25.45 $27.81 $26.01 $30.25 $19.25
Hedging gain (loss)................. (1.25) (1.03) 0.03 (9.51) (1.06)
Differential........................ (4.06) (4.66) (4.76) (4.22) (3.73)
------ ------ ------ ------ ------
Net realized........................ $20.14 $22.12 $21.28 $16.52 $14.46
====== ====== ====== ====== ======
Average gas sales price ($/Mcf)...... $ 2.81 $10.75 $ 8.58 $ 5.26 $ 1.61
====== ====== ====== ====== ======
Average sales price per BOE.......... $19.94 $24.85 $23.20 $17.46 $14.13
Average production expenses per BOE.. 8.29 7.41 (7.27) (6.89) (6.64)
------ ------ ------ ------ ------
Gross margin per BOE................. 11.65 17.44 15.93 10.57 7.49
G&A per BOE.......................... (1.07) (1.09) (1.16) (0.77) (0.57)
------ ------ ------ ------ ------
Gross profit per BOE................. $10.58 16.35 $14.77 $ 9.80 $ 6.92
====== ====== ====== ====== ======
DD&A per BOE (oil and gas properties) $ 3.04 $ 2.58 $ 2.70 $ 2.25 $ 1.72
Comparison of Nine Months Ended September 30, 2002 to Nine Months Ended
September 30, 2001
Operating revenues. Our operating revenues decreased 15%, or $24.6
million, to $136.7 million for the nine months ended September 30, 2002 from
$161.3 million for the nine months ended September 30, 2001. The decrease was
primarily due to lower realized prices for oil and gas that reduced revenues by
$32.3 million. Higher volumes increased revenues by $8.2 million.
Our daily oil sales volumes increased 6%, or 1.4 MBbls, to 23.6 MBbls per
day for the nine months ended September 30, 2002 from 22.2 MBbls for the nine
months ended September 30, 2001 primarily due to the additional interest we
acquired in the Point Arguello Unit. Our daily gas sales volumes increased 2%,
or 0.1 MMcf, to 9.3 MMcf per day for the nine months ended September 30, 2002
from 9.2 MMcf for the nine months ended September 30, 2001.
Our average realized price for oil and natural gas liquids decreased 9%, or
$1.98, to $20.14 per Bbl for the nine months ended September 30, 2002 from
$22.12 per Bbl for the nine months ended September 30, 2001. The average NYMEX
oil price decreased 8%, or $2.36, to $25.45 per Bbl for the nine months ended
September 30, 2002 from $27.81 per Bbl for the nine months ended September 30,
2001. An increase in our hedging cost per barrel, from $1.03 per barrel for the
nine months ended September 30, 2001 to $1.25 per barrel for the same period in
2002 was partially offset by a 13%, or $0.60 per Bbl improvement in location
and quality differentials over the same periods. The average realized price for
gas decreased 74%, or $7.94, to $2.81 per Mcf for the nine months ended
September 30, 2002 from $10.75 per Mcf in 2001. Gas prices were unusually high
in 2001, particularly in California.
Production expenses. Our production expenses increased 18%, or $8.8
million, to $56.8 million for the nine months ended September 30, 2002 from
$48.0 million for the nine months ended
45
September 30, 2001. On a per unit basis, production expenses increased 12%, or
$0.88 per BOE, to $8.29 per BOE for the nine months ended September 30, 2002
from $7.41 per BOE for the nine months ended September 30, 2001. Production
expenses for 2001 were reduced by approximately $0.34 per BOE as a result of
nonrecurring credits (primarily the sale of certain California emissions
credits). Excluding these credits, production expenses increased 7% per BOE
during the period, primarily due to higher electricity costs in California and
our increased ownership percentage in the Point Arguello Unit.
Depreciation, depletion and amortization. DD&A increased 25%, or $4.3
million, to $21.3 million for the nine months ended September 30, 2002 from
$17.0 million for the nine months ended September 30, 2001, primarily due to an
increase in the oil and gas DD&A rate of $3.04 per BOE for the nine months
ended September 30, 2002 from $2.58 per BOE for the nine months ended September
30, 2001. The increase was primarily due to the increase in costs subject to
DD&A as a result of our 2001 capital program.
Expenses of terminated public equity offering. In conjunction with the
termination of our proposed public equity offering we expensed costs incurred
as of September 30, 2002 of $1.7 million.
Interest expense. Our interest expense increased 11%, or $1.5 million, to
$14.4 million for the nine months ended September 30, 2002 from $12.9 million
for the nine months ended September 30, 2001, reflecting higher debt balances
during 2002, offset slightly by lower interest rates.
Income tax expense. Our income tax expense decreased $15.9 million to
$13.8 million for the nine months ended September 30, 2002 from $29.6 million
for the nine months ended September 30, 2001. The decrease was primarily due to
decreases in pre-tax income. An increase in our overall effective tax rate from
38.6% for the nine months ended September 30, 2001 to 39.0% for the nine months
ended June 30, 2002 partially offset the effect of the decrease in pre-tax
income. Our currently payable effective tax rate was 30.6% for the nine months
ended September 30, 2002 as compared to 6.7% for the nine months ended
September 30, 2001. The increased currently payable effective rate in 2002
primarily reflects lower expenditures that are expensed for tax purposes and
capitalized for financial reporting purposes.
Comparison of Year Ended December 31, 2001 to Year Ended December 31, 2000
Operating revenues. Our operating revenues increased 43%, or $61.6
million, to $204.1 million in 2001 from $142.5 million in 2000. The increase
primarily reflects higher realized oil and gas prices. Increased prices
contributed $46.7 million in additional revenues, and increased sales volumes
contributed $14.9 million.
Our daily oil sales volumes increased 8%, or 1.6 MBbls, to 22.5 MBbls in
2001 from 20.9 MBbls in 2000. Our daily gas sales volumes increased 11%, or 0.9
MMcf, to 9.2 MMcf in 2001 from 8.3 MMcf in 2000. Production increases were
primarily attributable to the continuing development of our onshore California
properties.
Our average realized price for oil increased 29%, or $4.76, to $21.28 per
Bbl in 2001 from $16.52 per Bbl in 2000. The average NYMEX oil price decreased
14%, or $4.24, to $26.01 per Bbl in 2001 from $30.25 per Bbl in 2000. The NYMEX
decrease was more than offset by a $9.54 per Bbl increase in our hedging
margin. The average realized price for gas increased 63%, or $3.32, to $8.58
per Mcf in 2001 from $5.26 per Mcf in 2000. Gas prices were unusually high in
2001, particularly in California.
Production expenses. Our production expenses increased 13%, or $7.6
million, to $63.8 million in 2001 from $56.2 million in 2000. Expenses for 2001
were reduced by $2.2 million due to the
46
sale of California emission credits. Excluding the credits, on a BOE basis
production expenses increased 9%, or $0.63, to $7.52 per BOE in 2001 from $6.89
per BOE in 2000. The increase is primarily due to increased volumes and higher
electricity costs in California.
General and administrative expense. Our G&A expense increased 62%, or $3.9
million, to $10.2 million in 2001 from $6.3 million in 2000. This increase was
primarily due to a $3.7 million increase in G&A expenses allocated by Plains
Resources. The increase in Plains Resources' G&A expenses was primarily due to
costs related to its 2001 corporate reorganization.
Depreciation, depletion and amortization. Our DD&A expense increased 28%,
or $5.2 million, to $24.1 million in 2001 from $18.9 million in 2000, as our
oil and gas DD&A rate increased 20%, or $0.45, to $2.70 per BOE in 2001 from
$2.25 per BOE in 2000. DD&A is affected by many factors, including production
levels, costs incurred in the acquisition, exploitation and development of
proved reserves and estimates of proved reserve quantities and future
development costs. The increase in our DD&A rate in 2001 was primarily due to
our capital program resulting in higher costs being subject to DD&A and, to a
lesser extent, to higher estimated future development costs.
Interest expense. Our interest expense increased 10%, or $1.5 million, to
$17.4 million in 2001 from $15.9 million in 2000, reflecting higher amounts
owed to Plains Resources which were partially offset by lower interest rates.
Income tax expense. Our income tax expense increased 105%, or $17.6
million, to $34.4 million in 2001 from $16.8 million in 2000. The increase was
primarily due to the increase in our operating income. Our effective tax rate
was 38.6% in 2001 compared to 36.8% in 2000.
Cumulative effect. The cumulative effect of accounting change recognized
for the year ended December 31, 2001 was for the adoption of Statement of
Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities," as amended.
Comparison of Year Ended December 31, 2000 to Year Ended December 31, 1999
Operating revenues. Our operating revenues increased 33%, or $35.0
million, to $142.5 million in 2000 from $107.5 million in 1999. The increase
was primarily due to higher realized oil and gas prices. Increased prices
contributed $25.3 million in additional revenues and increased sales volumes
contributed $9.7 million.
Our daily oil sales volumes increased 8%, or 1.5 MBbls, to 20.9 MBbls in
2000 from 19.4 MBbls in 1999. The volume increase is primarily due to a full
year of production from our offshore California property, which was acquired in
mid-1999. Our daily gas sales volumes decreased 4%, or 0.4 MMcf, to 8.3 MMcf in
2000 from 8.7 MMcf in 1999.
Our average realized price for oil increased 14%, or $2.06, to $16.52 per
Bbl in 2000 from $14.46 per Bbl in 1999. The average NYMEX oil price increased
57%, or $11.00, to $30.25 per Bbl in 2000 from $19.25 per Bbl in 1999. We did
not participate in the full amount of this increase, as hedges that we put into
place in the latter part of 1999, when oil prices were significantly lower,
decreased our realized price by $9.51 per Bbl in 2000. The average realized
price for gas increased 227%, or $3.65, to $5.26 per Mcf in 2000 from $1.61 per
Mcf in 1999.
Production expenses. Our production expenses increased 11%, or $5.7
million, to $56.2 million in 2000 from $50.5 million in 1999. Increased volumes
accounted for $3.8 million of the increase. On a BOE basis, production expenses
increased 4%, or $0.25, to $6.89 per BOE in 2000
47
from $6.64 per BOE in 1999, primarily reflecting a full year of production from
our offshore California property, increased gas fuel costs and higher oilfield
service costs.
General and administrative expense. Our G&A expense increased 44%, or $1.9
million, to $6.3 million in 2000 from $4.4 million in 1999. This increase was
primarily due to an increase in the number of employees in the latter part of
1999 and an increase in G&A expenses allocated by Plains Resources.
Depreciation, depletion and amortization. Our DD&A expense increased 41%,
or $5.6 million, to $18.9 million in 2000 from $13.3 million in 1999, as our
oil and gas DD&A rate increased 31%, or $0.53, to $2.25 per BOE in 2000 from
$1.72 per BOE in 1999. DD&A is affected by many factors, including production
levels, costs incurred in the acquisition, exploitation and development of
proved reserves and estimates of proved reserve quantities and future
development costs. The increase in our DD&A rate in 2000 was primarily due to
higher estimated future development costs. This increase reflects a doubling of
our proved undeveloped reserves from the beginning of 1999 to the end of 2000.
Interest expense. Our interest expense increased 7%, or $1.0 million, to
$15.9 million in 2000 from $14.9 million in 1999, primarily reflecting higher
interest rates.
Income tax expense. Our income tax expense increased 214%, or $11.4
million, to $16.7 million in 2000 from $5.3 million in 1999. Our income tax
expense in 1999 was reduced by $3.8 million as a result of the reversal of a
valuation allowance established with respect to the deferred tax benefit
related to the $42.9 million reduction on carrying costs of oil and gas
properties recognized in 1998. Excluding this benefit, our income tax expense
for 1999 was $9.1 million. Our effective tax rate was 36.8% in 2000 compared to
37.2% in 1999.
Liquidity and Capital Resources
Financing Activities
Historically, our primary sources of liquidity have been cash generated
from our operations and financing activity through our parent, Plains
Resources. We believe that we have sufficient liquidity through our cash from
operations and borrowing capacity under our revolving credit facility to meet
our short-term and long-term normal recurring operating needs, debt service
obligations, contingencies and anticipated capital expenditures.
On July 3, 2002 we and Plains E&P Company, our wholly owned subsidiary that
has no material assets and was formed for the sole purpose of being a corporate
co-issuer of certain of our indebtedness, issued $200.0 million of Series A
notes. The Series A notes are our unsecured general obligations, are
subordinated in right of payment to all of our existing and future senior
indebtedness and are jointly and severally guaranteed on a full, unconditional
basis by all of our existing and future domestic restricted subsidiaries. On
July 3, 2002 we also entered into a $300.0 million revolving credit facility
with a borrowing base of $225.0 million.
We distributed the net proceeds of $195.3 million from the Series A notes
and $116.7 million in initial borrowings under our credit facility to Plains
Resources, which used:
. $287.0 million to redeem its 10.25% senior subordinated notes on August
2, 2002; and
. $25.0 million to repay the amounts outstanding under its credit facility.
Our guarantees of Plains Resources debt facilities were terminated when it
retired such obligations.
48
At September 30, 2002 we had a working capital deficit of approximately
$50.5 million. Approximately $24.4 million of the working capital deficit is
attributable to the fair value of our hedges. In accordance with SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities", the fair value
of all derivative instruments is recorded on the balance sheet. Gains and
losses on hedging instruments are included in oil and gas revenues in the
period that the related volumes are delivered. The hedge agreements provide for
monthly settlement based on the differential between the agreement price and
actual NYMEX oil price. Cash received for sale of physical production will be
based on actual market prices and will generally offset any gains or losses on
the hedge instruments. The remaining working capital deficit will be financed
through cash flow and borrowings under our credit facility.
As of September 30, 2002 we had $90.7 million outstanding under our $300.0
million revolving credit facility which we entered into on July 3, 2002. The
credit facility provides for a borrowing base of $225.0 million that will be
reviewed every six months, with the lenders and us each having the right to one
annual interim unscheduled redetermination, and adjusted based on our oil and
gas properties, reserves, other indebtedness and other relevant factors, and
matures in 2005. Additionally, the credit facility contains a $30.0 million
sub-limit on letters of credit (of which $5.2 million had been issued as of
September 30, 2002). To secure borrowings, we pledged 100% of the shares of
stock of our domestic subsidiaries and gave mortgages covering 80% of the total
present value of its domestic oil and gas properties.
Amounts borrowed under the credit facility bear an annual interest rate, at
our election, equal to either: (i) the Eurodollar rate, plus from 1.375% to
1.75%; or (ii) the greatest of (1) the prime rate, as determined by JPMorgan
Chase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the federal
funds rate, plus 0.5%; plus an additional 0.125% to 0.5% for each of (1)-(3).
The amount of interest payable on outstanding borrowings is based on (1) the
utilization rate as a percentage of the total amount of funds borrowed under
the credit facility to the borrowing base and (2) our long-term debt rating.
Commitment fees and letter of credit fees under the credit facility are based
on the utilization rate and long-term debt rating. Commitment fees range from
0.375% to 0.5% of the unused portion of the borrowing base. Letter of credit
fees range from 1.375% to 1.75%. The issuer of any letter of credit receives an
issuing fee of 0.125% of the undrawn amount. Our domestic subsidiaries
unconditionally guarantee payment of borrowings under the credit facility.
The credit facility contains negative covenants that limit our ability, as
well as the ability of our subsidiaries, among other things, to incur
additional debt, pay dividends on stock, make distributions of cash or
property, change the nature of their business or operations, redeem stock or
redeem subordinated debt, make investments, create liens, enter into leases,
sell assets, sell capital stock of subsidiaries, create subsidiaries, guarantee
other indebtedness, enter into agreements that restrict dividends from
subsidiaries, enter into certain types of swap agreements, enter into gas
imbalance or take-or-pay arrangements, merge or consolidate and enter into
transactions with affiliates. In addition, the credit facility requires us to
maintain a current ratio, which includes availability, of at least 1.0 to 1.0
and a ratio of total debt to earnings before interest, depreciation, depletion,
amortization and income taxes of no more than 4.5 to 1.0.
The notes are our unsecured general obligations, are subordinated in right
of payment to all of our existing and future senior indebtedness and are
jointly and severally guaranteed on a full, unconditional basis by all of our
existing and future domestic restricted subsidiaries. The indenture governing
the notes contains covenants that limit our ability, as well as the ability of
our subsidiaries, among other things, to incur additional indebtedness, make
certain investments, make restricted payments, sell assets, enter into
agreements containing dividends and other payment restrictions affecting
subsidiaries, enter into transactions with affiliates, create liens, merge,
consolidate and
49
transfer assets and enter into different lines of business. In the event of a
change of control, as defined in the indenture, we will be required to make an
offer to repurchase the notes at 101% of the principal amount thereof, plus
accrued and unpaid interest to the date of the repurchase. The indenture
governing the notes will permit the spin-off and the spin-off will not, in
itself, constitute a change of control for purposes of the indenture.
The notes are not redeemable until July 1, 2007. On or after that date they
are redeemable, at our option, at 104.375% of the principal amount for the
twelve-month period ending June 30, 2008, at 102.917% of the principal amount
for the twelve-month period ending June 30, 2009, at 101.458% of the principal
amount for the twelve-month period ending June 30, 2010 and at 100% of the
principal amount thereafter. In each case, accrued interest is payable to the
date of redemption.
We have been assigned a Ba3 senior implied rating and the notes have been
assigned a B2 rating by Moody's Investor Service Inc. We have also been
assigned a BB- corporate credit rating, on credit watch with negative
implications, by Standard and Poor's Corp. All of these ratings are below
investment grade. As a result, at times we may have difficulty accessing
capital markets or raising capital on favorable terms.
As the owner of 100% of our capital stock, Plains Resources has made an
aggregate of $5.0 million of cash contributions to us since the date of our
reorganization. In addition, on September 30, 2002, Plains Resources
contributed a promissory note payable by Plains Resources to us in the amount
of $7.2 million. Such promissory note bears interest at the rate of 2.5%. These
contributions were part of the working capital for the upstream assets
contributed to us. In addition, Plains Resources may contribute up to $42.8
million to us before the spin-off.
Capital Requirements
During 2001, we spent $125.8 million on acquisition, exploration and
development costs, compared to $70.5 million and $59.2 million in 2000 and
1999, respectively. The capital expenditure expansion in late 2000 and 2001
reflects the initial results of field studies and other analyses that were
initiated in 1999 and were designed to advance some of the more technically
challenging projects that exist within our property base. The 2001 capital
expenditures incorporate several multi-year projects that, in the aggregate,
are designed to generate year-over-year production increases in both 2001 and
2002. As a result of the multi-year benefit that we believe the 2001
investments will deliver, we estimate that we will be able to increase
production volumes in 2002 and reduce capital spending approximately 41% from
the 2001 level.
We intend to make aggregate capital expenditures of approximately $74.0
million in 2002. In addition, we intend to continue to pursue the acquisition
of underdeveloped producing properties. We believe that we will have sufficient
cash flow from operating activities and from borrowings under our new credit
facility to fund our planned capital expenditures.
During 2002, we expect to spend approximately $63.0 million on maintaining,
developing and exploiting our oil and gas properties and pursuing acquisition
opportunities. We expect approximately $46.0 million of these capital
expenditures will be for exploitation projects in onshore California. The 2002
capital program incorporates the results of various analyses and field studies
and includes our drilling approximately 88 total wells, including 8 injection
wells and numerous injection realignment related workovers. In addition, our
2002 estimated capital expenditures include $11.0 million of capitalized
interest and general and administrative costs allocable directly to
acquisition, exploitation
50
and development activities. During the nine months ended September 30, 2002
capital expenditures for these activities were $53.6 million, including
capitalized interest and general and administrative costs.
Under our spin-off agreements with Plains Resources, Plains Resources
provides us with various management services related to operational management,
tax, accounting services, payroll services, legal services, employee benefit
services, insurance services and financial services. We are required to
reimburse Plains Resources for its costs of providing such services, not to
exceed $30 million in the aggregate. In addition, we have entered into various
other agreements with Plains Resources relating to allocating our and Plains
Resources assets and liabilities, including tax liabilities, amongst each other
and providing for mutual indemnification with respect to those assets and
liabilities. For a further discussion of these agreements, please see "Certain
Transactions" on page 87.
Commitments and Contingencies
At September 30, 2002, the aggregate amounts of contractually obligated
payment commitments for the next five years are as follows (in thousands):
2002 2003 2004 2005 2006 Thereafter
- ---- ---- ---- ------- ---- ----------
Long-term debt.. $-- $511 $511 $90,700 $-- $196,803
Operating leases 11 13 -- -- -- --
--- ---- ---- ------- --- --------
$11 $524 $511 $90,700 $-- $196,803
=== ==== ==== ======= === ========
The long-term debt amounts consist principally of amounts due under our
credit facility and our Series A notes.
Although we maintain an inspection program designed to prevent and, as
applicable, to detect and address releases of crude oil into the environment
from our upstream operations, we may experience such releases in the future, or
discover releases that were previously unidentified. Damages and liabilities
incurred due to any future environmental releases from our assets may
substantially affect our business.
Under the amended terms of an asset purchase agreement with respect to
certain of our onshore California properties, commencing with the year
beginning January 1, 2000, and each year thereafter, we are required to plug
and abandon 20% of the then remaining inactive wells, which currently aggregate
approximately 149. To the extent we elect not to plug and abandon the number of
required wells, we are required to escrow an amount equal to the greater of
$25,000 per well or the actual average plugging cost per well in order to
provide for the future plugging and abandonment of such wells. In addition, we
are required to expend a minimum of $600,000 per year in each of the ten years
beginning January 1, 1996, and $300,000 per year in each of the succeeding five
years to remediate oil contaminated soil from existing well sites, provided
there are remaining sites to be remediated. In the event we do not expend the
required amounts during a calendar year, we are required to contribute an
amount equal to 125% of the actual shortfall to an escrow account. We may
withdraw amounts from the escrow account to the extent we expend excess amounts
in a future year. Through September 30, 2002, we have not been required to make
contributions to an escrow account.
In connection with the acquisitions of our interest in the Point Arguello
field, offshore California, we assumed our 52.6% share of (1) plugging and
abandoning all existing well bores, (2) removing conductors, (3) flushing
hydrocarbons from all lines and vessels and (4) removing/abandoning all
structures, fixtures and conditions created subsequent to closing. The seller
retained the obligation for all other abandonment costs, including but not
limited to (1) removing, dismantling and disposing of the
51
existing offshore platforms, (2) removing and disposing of all existing
pipelines and (3) removing, dismantling, disposing and remediation of all
existing onshore facilities.
Although we obtained environmental studies on our properties in California
and Illinois and we believe that such properties have been operated in
accordance with standard oil field practices, certain of the fields have been
in operation for more than 90 years, and current or future local, state and
federal environmental laws and regulations may require substantial expenditures
to comply with such rules and regulations. In connection with the purchase of
certain of our onshore California properties, we received a limited indemnity
for certain conditions if they violate applicable local, state and federal
environmental laws and regulations in effect on the date of such agreement. We
believe that we do not have any material obligations for operations conducted
prior to our acquisition of the properties, other than our obligation to plug
existing wells and those normally associated with customary oil field
operations of similarly situated properties. There can be no assurance that
current or future local, state or federal rules and regulations will not
require us to spend material amounts to comply with such rules and regulations
or that any portion of such amounts will be recoverable under the indemnity.
Consistent with normal industry practices, substantially all of our crude
oil and natural gas leases require that, upon termination of economic
production, the working interest owners plug and abandon non-producing
wellbores, remove tanks, production equipment and flow lines and restore the
wellsite. We have estimated that at December 31, 2001 the costs to perform
these tasks was approximately $19.3 million, net of salvage value and other
considerations.
As is common within the industry, we have entered into various commitments
and operating agreements related to the exploration and development of and
production from proved crude oil and natural gas properties and the marketing,
transportation, terminalling and storage of crude oil. It is management's
belief that such commitments will be met without a material adverse effect on
our financial position, results of operations or cash flows.
On September 18, 2002 Stocker Resources Inc., or Stocker, our general
partner before we converted from a limited partnership to a corporation, filed
a declaratory judgment action against Commonwealth Energy Corporation (doing
business as electricAmerica), or Commonwealth, in the Superior Court of Orange
County, California relating to the termination of an electric service contract
between Stocker and Commonwealth. Pursuant to the agreement, Commonwealth had
agreed to supply Stocker with electricity and Stocker had obtained a $1.5
million performance bond in favor of Commonwealth to secure its payment
obligations under the agreement. Stocker terminated the contract in accordance
with its terms and Commonwealth notified Stocker of its intent to draw upon the
performance bond. Stocker is seeking a declaratory judgment that it was
entitled to terminate the contract and that Commonwealth has no basis for
proceeding against Stocker's related performance bond. Also on September 18,
2002, Stocker was named a defendant in an action brought by Commonwealth in the
Superior Court of Orange County, California for breach of the electric service
contract. Commonwealth alleges that Stocker breached the terms of the contract
by the termination and its implied covenant of good faith and fair dealing and
is seeking unspecified damages. Under the master separation agreement, we are
required to indemnify Stocker and Plains Resources for damages Plains Resources
or Stocker incur as a result of this action. At this time we are not in a
position to express a judgment concerning the potential exposure or likely
outcome of this matter. We understand that Stocker intends to defend its rights
vigorously in this matter.
In the ordinary course of our business, we are a claimant and/or defendant
in various other legal proceedings. We do not believe that the outcome of these
legal proceedings, individually or in the aggregate, will have a materially
adverse effect on our financial condition, results of operations or cash flows.
52
Industry Concentration
Financial instruments which potentially subject us to concentrations of
credit risk consist principally of accounts receivable with respect to our oil
and gas operations and derivative instruments related to our hedging
activities. PAA is the exclusive marketer/purchaser for all of our equity oil
production. This concentration has the potential to impact our overall exposure
to credit risk, either positively or negatively, in that PAA may be affected by
changes in economic, industry or other conditions. We do not believe the loss
of PAA as the exclusive purchaser of our equity production would have a
material adverse affect on our results of operations. We believe PAA could be
replaced by other purchasers under contracts with similar terms and conditions.
The contract counterparties for our derivative commodity contracts are all
major financial institutions with Standard & Poor's ratings of A or better.
Three of the financial institutions are participating lenders in the PXP credit
facility, with one such counterparty holding contracts that represent
approximately 32% of the fair value of all of our open positions at September
30, 2002.
There are a limited number of alternative methods of transportation for our
production. Substantially all of our oil and gas production is transported by
pipelines, trucks and barges owned by third parties. The inability or
unwillingness of these parties to provide transportation services to us for a
reasonable fee could result in our having to find transportation alternatives,
increased transportation costs or involuntary curtailment of a significant
portion of our oil and gas production which could have a negative impact on
future results of operations or cash flows.
Critical Accounting Policies and Factors that May Affect Future Results
Based on the accounting policies which we have in place, certain factors
may impact our future financial results. The most significant of these factors
and their effect on certain of our accounting policies are discussed below.
Commodity pricing and risk management activities. Prices for oil and gas
have historically been volatile. Decreases in oil and gas prices from current
levels will adversely affect our revenues, results of operations, cash flows
and proved reserves. If the industry experiences significant prolonged future
price decreases, this could be materially adverse to our operations and our
ability to fund planned capital expenditures.
Periodically, we enter into hedging arrangements relating to a portion of
our oil production to achieve a more predictable cash flow, as well as to
reduce our exposure to adverse price fluctuations. Hedging instruments used are
typically fixed price swaps and collars and purchased puts and calls. While the
use of these types of hedging instruments limits our downside risk to adverse
price movements, we are subject to a number of risks, including instances in
which the benefit to revenues is limited when commodity prices increase. For a
further discussion concerning our risks related to oil and gas prices and our
hedging programs, see "--Quantitative and Qualitative Disclosures about Market
Risks".
Write-downs under full cost ceiling test rules. Under the SEC's full cost
accounting rules we review the carrying value of our proved oil and gas
properties each quarter. Under these rules, capitalized costs of proved oil and
gas properties (net of accumulated depreciation, depletion and amortization,
and deferred income taxes) may not exceed a "ceiling" equal to:
. the standardized measure (including, for this test only, the effect of
any related hedging activities); plus
. the lower of cost or fair value of unproved properties not included in
the costs being amortized (net of related tax effects).
53
These rules generally require that we price our future oil and gas
production at the oil and gas prices in effect at the end of each fiscal
quarter and require a write-down if our capitalized costs exceed this
"ceiling," even if prices declined for only a short period of time. We have had
no write-downs due to these ceiling test limitations since 1998. Given the
volatility of oil and gas prices, it is likely that our estimate of discounted
future net revenues from proved oil and gas reserves will change in the near
term. If oil and gas prices decline significantly in the future, even if only
for a short period of time, write-downs of our oil and gas properties could
occur. Write-downs required by these rules do not directly impact our cash
flows from operating activities.
Oil and gas reserves. The proved reserve information included in this
prospectus is based on estimates prepared by outside engineering firms.
Estimates prepared by others may be higher or lower than these estimates.
Estimates of proved reserves may be different from the actual quantities of
oil and gas recovered because such estimates depend on many assumptions and are
based on operating conditions and results at the time the estimate is made. The
actual results of drilling and testing, as well as changes in production rates
and recovery factors, can vary significantly from those assumed in the
preparation of reserve estimates. As a result, such factors have historically,
and can in the future, cause significant upward and downward revisions to
proved reserve estimates.
You should not assume that PV-10 is the current market value of our
estimated proved oil and gas reserves. In accordance with SEC requirements, we
base the estimated discounted future net revenues from proved reserves on
prices and costs on the date of the estimate. Actual future prices and costs
may be materially higher or lower than the prices and costs as of the date of
the estimate.
A large portion of our reserve base (approximately 93% at December 31,
2001) is comprised of oil properties that are sensitive to oil price
volatility. Historically, we have experienced significant upward and downward
revisions to our reserves volumes and values as a result of changes in year-end
oil and gas prices and the corresponding adjustment to the projected economic
life of such properties. Prices for oil and gas are likely to continue to be
volatile, resulting in future downward and upward revisions to our reserve base.
Our rate of recording DD&A is dependent upon our estimate of proved
reserves including future development and abandonment costs as well as our
level of capital spending. If the estimates of proved reserves decline, the
rate at which we record DD&A expense increases, reducing our net income. This
decline may result from lower market prices, which may make it uneconomic to
drill for and produce higher cost fields. The decline in proved reserve
estimates may impact the outcome of the "ceiling" test discussed above. In
addition, increases in costs required to develop our reserves would increase
the rate at which we record DD&A expense. We are unable to predict changes in
future development costs as such costs are dependent on the success of our
exploitation and development program, as well as future economic conditions.
Operating risks and insurance coverage. Our operations are subject to all
of the risks normally incident to the exploration for and the production of oil
and gas, including well blowouts, cratering, explosions, spills of oil, gas or
well fluids, fires, pollution and releases of toxic gas, each of which could
result in damage to or destruction of oil and gas wells, production facilities
or other property, or injury to persons. Our operations in California,
including transportation of oil by pipelines within the city and county of Los
Angeles, are especially susceptible to damage from earthquakes and involve
increased risks of personal injury, property damage and marketing interruptions
because of the population density of southern California. Although we maintain
insurance coverage considered to be customary in the industry, we are not fully
insured against some risks, either because insurance is not available or
because of high premium costs. We maintain coverage for earthquake damages in
54
California but this coverage may not provide for the full effect of damages
that could occur and we may be subject to additional liabilities. The
occurrence of a significant event that is not fully insured against could have
a material adverse effect on our financial position. Our insurance does not
cover every potential risk associated with operating our pipelines, including
the potential loss of significant revenues. Consistent with insurance coverage
generally available to the industry, our insurance policies provide limited
coverage for losses or liabilities relating to pollution, with broader coverage
for sudden and accidental occurrences.
Environmental matters. As an owner or lessee and operator of oil and gas
properties, we are subject to various federal, state, and local laws and
regulations relating to discharge of materials into, and protection of, the
environment. These laws and regulations may, among other things, impose
liabilities on us for the cost of pollution clean-up resulting from operations,
subject us to liability for pollution damages, and require suspension or
cessation of operations in affected areas. We maintain insurance coverage,
which we believe is customary in the industry, although we are not fully
insured against all environmental risks. We have established policies for
continuing compliance with environmental laws and regulations and have made and
will continue to make expenditures in our efforts to comply with these
requirements, which we believe are necessary business costs in the oil and gas
industry.
Although we obtained environmental studies on our properties in California
and the Illinois Basin, and we believe that these properties have been operated
in accordance with standard oil field practices, certain of the fields have
been in operation for over 90 years, and current or future federal, state and
local environmental laws and regulations may require substantial expenditures
to remediate our properties or otherwise comply with these rules and
regulations. While we do not believe that the cost of remediation and other
compliance with current federal, state or local environmental laws and
regulations will have a material adverse effect on our capital expenditures,
results of operations or competitive position; there is no assurance that
changes in or additions to these laws or regulations will not have such an
impact.
Consistent with normal industry practices, substantially all of our oil and
gas leases require that, upon termination of economic production, the working
interest owners plug and abandon non-producing wellbores, remove tanks,
production equipment and flow lines and restore the wellsite. Based on our
year-end 2001 reserve report, the cost to perform these tasks is approximately
$19.3 million, net of salvage value and other considerations. These estimated
amortized costs are included in expenses through the unit-of-production method
as a component of accumulated DD&A. Results from operations for 2001, 2000 and
1999 include $0.5 million, $0.2 million and $0.2 million, respectively, of
expense associated with these estimated future costs.
We estimate our 2002 expenditures related to plugging, abandonment and
remediation to be approximately $3.0 million. Due to the long-life of our
onshore reserve base we do not expect our cash outlays on plugging, abandonment
and remediation for these properties to increase significantly from this amount
for the next several years. Based on our year-end 2001 reserve reports, we
estimate our abandonment costs for the 52.6% interest we own in the offshore
Point Arguello field to approximate $14.7 million. Timing of abandonment of
this field depends of various factors, including oil prices and the success of
our exploitation projects. For a discussion of our specific contractual
obligations to incur plugging, abandonment and remediation costs, please see
"Plugging, Abandonment and Remediation Obligations" beginning on page 74.
Recent Accounting Pronouncements
In June 2001 Statement of Accounting Standards, or SFAS, No. 143,
"Accounting for Asset Retirement Obligations" was issued. SFAS No. 143 requires
entities to record the fair value of a liability
55
for an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
After recording, the asset retirement cost will be allocated to expense using a
systematic and rational method. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. We are currently assessing the impact of SFAS
No. 143 and at this time we cannot reasonably estimate the effect of this
statement on our consolidated financial position, results of operations or cash
flows.
In April 2002 SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and
64. Amendment of FASB Statement No. 13, and Technical Corrections", was issued.
SFAS 145 rescinds SFAS 4 and SFAS 64 related to classification of gains and
losses on debt extinguishment such that most debt extinguishment gains and
losses will no longer be classified as extraordinary. SFAS 145 also amends SFAS
13 with respect to sales leaseback transactions. The provisions of SFAS 145
have no effect on our financial statements.
In July 2002 SFAS No. 146, "Accounting For Costs Associated with Exit or
Disposal Activities" was issued. SFAS 146 is effective for exit or disposal
activities initiated after December 31, 2002 and does not require previously
issued financial statements to be restated. We will account for exit or
disposal activities initiated after December 31, 2002 in accordance with the
provisions of SFAS 146.
Qualitative and Quantitative Disclosures About Market Risks
We are exposed to various market risks, including volatility in oil and gas
commodity prices and interest rates. Although we have routinely hedged a
substantial portion of our oil production and intend to continue this practice,
substantial future oil and gas price declines would adversely affect our
overall results, and therefore our liquidity. Furthermore, low oil and gas
prices could affect our ability to raise capital on favorable terms. Decreases
in the prices of oil and gas have had, and could have in the future, an adverse
effect on the carrying value of our proved reserves and our revenues,
profitability and cash flow. To manage our exposure, we monitor current
economic conditions and our expectations of future commodity prices and
interest rates when making decisions with respect to risk management. We do not
enter into derivative transactions for speculative trading purposes.
Substantially all of our derivative contracts are exchanged or traded with
major financial institutions and the risk of credit loss is considered remote.
SFAS No. 133. For purposes of our combined financial statements, on
January 1, 2001 we implemented SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138, or
SFAS 133. Under SFAS 133, all derivative instruments are recorded on the
balance sheet at fair value. If the derivative does not qualify as a hedge or
is not designated as a hedge, the gain or loss on the derivative is recognized
currently in earnings. To qualify for hedge accounting, the derivative must
qualify either as a fair value hedge, cash flow hedge or foreign currency
hedge. Currently, we use only cash flow hedges and the remaining discussion
will relate exclusively to this type of derivative instrument. If the
derivative qualifies for hedge accounting, the gain or loss on the derivative
is deferred in accumulated Other Comprehensive Income, or OCI, a component of
our stockholders' equity, to the extent the hedge is effective.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. Hedge accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in OCI related to cash flow
hedges for which hedge accounting has been discontinued remain unchanged until
the related product has been delivered. If it is probable that a hedged
forecasted transaction will not occur, deferred gains or losses on the hedging
instrument are recognized in earnings immediately.
56
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured on a quarterly basis.
This process includes specific identification of the hedging instrument and the
hedged item, the nature of the risk being hedged and the manner in which the
hedging instrument's effectiveness will be assessed. At the inception of the
hedge and on an ongoing basis, we assess whether the derivatives used in
hedging transactions are highly effective in offsetting changes in cash flows
of hedged items. As of September 30, 2002 all open positions related to
production from our oil and gas properties qualified for hedge accounting.
Unrealized gains and losses on hedging instruments reflected in OCI, and
adjustments to carrying amounts on hedged volumes, are included in oil and gas
revenues in the period that the related volumes are delivered. Gains and losses
of hedging instruments that represent hedge ineffectiveness, as well as any
amounts excluded from the assessment of hedge effectiveness, are recognized
currently in oil and gas revenues. For purposes of our combined financial
statements, effective October 2001 we implemented Derivatives Implementation
Group, Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness
of a Purchased Option Used in a Cash Flow Hedge", or DIG Issue G20, which
provides guidance for assessing the effectiveness on total changes in an
option's cash flows rather than only on changes in the option's intrinsic
value. Implementation of DIG Issue G20 has reduced earnings volatility since it
allows us to include changes in the time value of purchased options and collars
in the assessment of hedge effectiveness. Time value changes were previously
recognized in current earnings since we excluded them from the assessment of
hedge effectiveness. Oil and gas revenues for the year ended December 31, 2001
include a $3.1 million non-cash loss related to the ineffective portion of the
cash flow hedges representing the fair value change in the time value of
options for the nine months before the implementation of DIG Issue G20.
We utilize various derivative instruments to hedge our exposure to price
fluctuations on oil sales. The derivative instruments consist primarily of
cash-settled oil option and swap contracts entered into with financial
institutions. We do not currently have any gas hedges. We also use interest
rate swaps to manage the interest rate exposure on our credit facility.
On January 1, 2001, in accordance with the transition provisions of SFAS
133, we recorded a gain of $7.0 million in OCI representing the cumulative
effect of an accounting change to recognize at fair value all cash flow
derivatives. We recorded cash flow hedge derivative assets and liabilities of
$9.7 million and $4.2 million, respectively, and a net-of-tax non-cash charge
of $1.5 million was recorded in earnings as a cumulative effect adjustment.
At December 31, 2001, OCI consisted of $26.6 million ($15.9 million, net of
tax) of unrealized gains on our open crude oil hedging instruments. As oil
prices increased significantly during the first nine months of 2002 the fair
value of our open crude oil hedging positions decreased $51.0 million ($30.3
million after tax). At September 30, 2002, OCI consisted of $24.4 million
($14.4 million after tax) of unrealized losses on our open crude oil hedging
instruments and $0.3 million ($0.2 million, net of tax) loss related to our
interest rate swap. At September 30, 2002 the assets and liabilities related to
our open crude oil hedging instruments were included in current assets ($0.2
million), other assets ($2.1 million), current liabilities ($24.9 million),
other long-term liabilities ($1.8 million) and deferred income taxes (a tax
benefit of $10.0 million).
During the first nine months of 2002, $7.5 million ($4.6 million net of
tax) in losses from the settlement of crude oil hedging instruments were
reclassified from OCI and charged to income as a reduction of oil sales
revenues. Oil sales revenues for the period have also been reduced by a $0.6
million non-cash expense related to the amortization of option premiums. As of
September 30, 2002, $14.6 million of deferred net losses on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
the next twelve-month period.
57
Commodity price risk. As of October 31, 2002, we had the following open oil
hedge positions with respect to our oil properties:
Bbls per Day
---------------------
2002
4th Qtr 2003 2004
------- ------ ------
Puts:
Average price $22.00/Bbl -- 2,000 --
Calls:
Average price $35.17/Bbl 9,000 -- --
Average price $27.04/Bbl -- 2,000 --
Swaps:
Average price $24.22/Bbl 20,000 -- --
Average price $23.36/Bbl -- 15,250 --
Average price $23.53/Bbl -- -- 12,500
Assuming estimated fourth quarter 2002 production levels are held constant
in subsequent periods as of September 30, 2002 our hedge positions result in us
having hedged approximately 78% of production for the fourth quarter of 2002,
approximately 68% of production for 2003 and approximately 49% of production
for 2004. Location and quality differentials attributable to our properties and
the cost of the hedges are not included in the foregoing prices. Because of the
quality and location of our oil production these adjustments will reduce our
net price per Bbl.
The agreements provide for monthly cash settlement based on the
differential between the agreement price and the actual NYMEX price. Gains or
losses are recognized in the month of related production and are included in
oil and gas sales revenues. These contracts resulted in a decrease in revenues
of $8.1 million and $6.3 million for the nine months ended September 30, 2002
and 2001, respectively, as well as an increase (decrease) in revenues of $0.3
million, $(72.8) million and $(7.5) million for the years ended December 31,
2001, 2000 and 1999, respectively. As of September 30, 2002 we had an
unrealized loss of $14.6 million, net of tax, with respect to these contracts.
The estimated fair value of the hedges is included in our balance sheet as of
September 30, 2002.
The fair value of outstanding oil derivative commodity instruments and the
change in fair value that would be expected from a 10% price decrease are shown
in the table below (in millions):
As of September 30,
-------------------------------------------
2002 2001
---------------------- --------------------
Fair Effect of 10% Fair Effect of 10%
Value Price Decrease Value Price Decrease
------ -------------- ----- --------------
Swaps and options contracts $(24.2) $30.1 $12.5 $21.8
The fair value of the swaps and option contracts are estimated based on
quoted prices from independent reporting services compared to the contract
price of the swap, and approximate the gain or loss that would have been
realized if the contracts had been closed out at quarters end. All hedge
positions offset physical positions exposed to the cash market. None of these
offsetting physical positions are included in the above table. Price risk
sensitivities were calculated by assuming an across-the-board 10% decrease in
price regardless of term or historical relationships between the contractual
price of the instruments and the underlying commodity price. In the event of an
actual 10% change in prompt month oil prices, the fair value of our derivative
portfolio would typically change less than that shown in the table due to lower
volatility in out-month prices.
The contract counterparties for our derivative commodity contracts are all
major financial institutions with Standard & Poor's ratings of A or better.
Three of the financial institutions are participating lenders in
58
our revolving credit facility, with one counterparty holding contracts that
represent approximately 32% of the fair value of all open positions as of
September 30, 2002.
Our management intends to continue to maintain hedging arrangements for a
significant portion of our production. These contracts may expose us to the
risk of financial loss in certain circumstances. Our hedging arrangements
provide us protection on the hedged volumes if oil prices decline below the
prices at which these hedges are set, but ceiling prices in our hedges may
cause us to receive less revenues on the hedged volumes than we would receive
in the absence of hedges.
Interest rate risk. Our credit facility is sensitive to market
fluctuations in interest rates. We use interest rate swaps to hedge underlying
debt obligations. These instruments hedge specific debt issuances and qualify
for hedge accounting. The interest rate differential is reflected as an
adjustment to interest expense over the life of the instruments. We have
entered into an interest rate swap for an aggregate notional principal amount
of $7.5 million that fixes the interest rate on that amount of borrowing under
our credit facility at 3.9% plus the LIBOR margin set forth in our credit
facility. The swap expires in October 2004.
59
BUSINESS
Overview
We are an independent oil and gas company primarily engaged in the upstream
activities of acquiring, exploiting, developing and producing oil and gas in
the United States. We are 100% owned by Plains Resources Inc. Our core areas of
operation are:
. onshore California, primarily in the LA Basin, and offshore California in
the Point Arguello unit; and
. the Illinois Basin in southern Illinois and Indiana.
We own a 100% working interest in and operate all of our properties, except
for offshore California, in which we own a 52.6% working interest and where we
are the operator. Our reserves are generally mature but underdeveloped, have
produced significant volumes since initial discovery and have significant
estimated remaining reserves. We opportunistically hedge portions of our oil
production to manage our exposure to commodity price risk.
The following table sets forth information with respect to our oil and gas
properties as of and for the year ended December 31, 2001:
California
--------------- Illinois Basin
Onshore Offshore and Other Total
------- -------- -------------- ------
(Dollars in millions)
Proved reserves
MMBOE........................... 211.8 5.0 22.5 239.3
Percent oil..................... 93% 98% 98% 93%
Proved developed reserves (MMBOE) 112.0 3.8 13.3 129.1
Production (MBOE)................ 6,347 1,431 1,000 8,778
PV-10/(1)/....................... $577.7 $ 6.9// $ 58.6 $643.2
Standardized measure/(2)/........ $384.5
- --------
(1) Based on year-end 2001 spot market prices of $19.84 per Bbl of oil and
$2.58 per Mcf of gas. The PV-10 and standardized measure have been reduced
to reflect the abandonment costs of certain properties. PV-10 represents
the standardized measure before deducting estimated future income taxes.
(2) Estimated future income taxes are calculated on a combined basis using the
statutory income tax rate, accordingly, the standardized measure is
presented in total only.
During the five-year period ended December 31, 2001 we drilled 561
development wells, 558 of which were successful. During this period, we
incurred aggregate oil and gas acquisition, exploitation, development and
exploration costs of $442.9 million, resulting in proved reserve additions of
177.9 MMBOE, at an average reserve replacement cost of $2.49 per BOE, which we
believe to be among the lowest of our peer group. During that five-year period,
which we believe is a useful period for measurement since our reserve
replacement costs have historically fluctuated on a year to year basis,
approximately 99% of our oil and gas capital expenditures were for acquisition,
exploitation and development activities. During that same period, the average
replacement cost for large domestic exploration and production companies was
$6.57 per barrel.
Competitive Strengths
Quality Asset Base With Long Reserve Life. We had estimated total proved
reserves of 239.3 MMBOE as of December 31, 2001, of which 93% was comprised of
oil and 54% was proved
60
developed. We have a reserve life of over 27 years and a proved developed
reserve life of over 14 years. We believe our long-lived, low production
decline reserve base combined with our active hedging strategy should provide
us with relatively stable and recurring cash flow. As of December 31, 2001 and
based on year-end 2001 spot market prices of $19.84 per Bbl of oil and $2.58
per Mcf of gas, our reserves had a PV-10 of $643.2 million and a standardized
measure of $384.5 million.
Efficient Operations With 100% Operatorship. We own a 100% working
interest in and operate all of our properties, except for offshore California,
in which we own a 52.6% working interest and where we are the operator. As a
result, we benefit from economies of scale and control the level, timing and
allocation of substantially all of our capital expenditures and expenses. We
believe this gives us more flexibility than many of our peers to
opportunistically pursue exploitation and development projects relating to our
properties.
Large Exploitation and Development Inventory. We have a large inventory of
projects in our core areas that we believe will support at least five years of
exploitation and development activity. Over the last five years, we have
achieved a high success rate on these types of projects, drilling a total of
561 development wells with a 99.5% success rate. In addition, we have completed
numerous other production enhancement projects, such as recompletions,
workovers and upgrades. The results of these activities over the last five
years have been additions to proved reserves, excluding reserves added through
acquisition activities, totaling 120.6 MMBOE, or approximately 332% of
cumulative net production for this period. Reserve replacement costs, excluding
acquisitions, have averaged approximately $3.17 per BOE for the same period.
Experienced and Proven Management and Operations Team. Our executive
management team has an average of 20 years of experience in the oil and gas
industry. Our Chief Executive Officer is James Flores, who founded Flores &
Rucks Incorporated, a predecessor of Ocean Energy, Inc., and was President and
Chief Executive Officer of Ocean Energy from July 1995 until March 1999. Mr.
Flores served as Chairman of the Board of Ocean Energy from March 1999 until
January 2000, and as Vice Chairman from January 2000 until January 2001. The
executive management of Plains Resources is supported by a core team of 23
technical and operating managers who have worked with our properties for many
years and have an average of 22 years of experience in the oil and gas industry.
Strategy
Our strategy is to continue to grow our cash flow from operations and to
use this cash flow to increase our proved developed reserves and production,
acquire additional underdeveloped oil and gas properties and make other
strategic acquisitions. We intend to implement our strategy as follows:
Continue Exploitation and Development of Current Asset Base. We believe
that we have a proven track record of exploiting underdeveloped properties to
increase reserves and cash flow. We focus on implementing improved production
practices and recovery techniques, and relatively low-risk development
drilling. An example of our success in exploiting underdeveloped properties can
be found in our Montebello field located in the LA Basin. Since our acquisition
of this field in March 1997, our exploitation and development activities have
resulted in an increase in our net average production from approximately 930
BOE per day at the time of acquisition to approximately 2,500 BOE per day
during the first nine months of 2002, representing a compound annual growth
rate of over 20%.
Pursue Additional Growth Opportunities. We believe we can continue our
strong reserve and production growth through the exploitation and development
of our existing inventory of projects relating to our properties. We also
intend to be opportunistic in pursuing selective acquisitions of oil or gas
properties or exploration projects, for example, during periods of weak
commodity prices. We will
61
consider opportunities located in our current core areas of operation as well
as projects in other areas in North America that meet our investment criteria.
Maintain Long-Term Hedging Program. We actively manage our exposure to
commodity price fluctuations by hedging significant portions of our oil
production through the use of swaps, collars and purchased puts and calls. The
level of our hedging activity depends on our view of market conditions,
available hedge prices and our operating strategy. Under our hedging program,
we typically hedge approximately 70-75% of our production for the current year,
40-50% of our production for the next year and up to 25% of our production for
the following year. For example, assuming estimated fourth quarter 2002
production levels are held constant in subsequent periods as of September 30,
2002 our hedge positions result in us having hedged approximately 78% of
production for the fourth quarter of 2002, approximately 68% of production for
2003 and approximately 49% of production for 2004.
Recent Developments
Spin-off
Our parent is Plains Resources Inc., which, in addition to owning us, owns
an aggregate 25% ownership interest in PAA, including 44% of the general
partner of PAA. PAA is a publicly traded master limited partnership that is
engaged in the midstream activities of marketing, transportation and
terminalling of oil and marketing liquified petroleum gas. Plains Resources
also owns interests in oil and gas properties in Florida, which included 17.3
MMBOE of proved oil reserves as of December 31, 2001.
On May 22, 2002 Plains Resources received a favorable private letter ruling
from the IRS, which was supplemented on November 5, 2002, stating that, for
United States federal income tax purposes, a distribution by Plains Resources
of our capital stock owned by it to its stockholders will generally be tax-free
to both Plains Resources and its stockholders. We expect the spin-off to occur
within 30 days of the date of this prospectus. The indenture governing the
notes will permit the spin-off and the spin-off will not, in itself, constitute
a "change of control" for purposes of the indenture.
The spin-off will, among other things:
. allow Plains Resources and us to focus corporate strategies and
management teams for each business; and
. simplify Plains Resources' and our corporate structure.
The spin-off is also expected to allow Plains Resources to obtain cost
savings through improved access to capital markets for its midstream affiliate,
Plains All American Pipeline, L.P.
62
Reorganization and Terminated Initial Public Offering
Under the terms of a Master Separation Agreement between us and Plains
Resources, on July 3, 2002 Plains Resources contributed to us: (i) 100% of the
capital stock of its wholly owned subsidiaries Arguello Inc., Plains Illinois,
Inc., PMCT Inc. and Plains Resources International Inc.; and (ii) all amounts
payable to it by us and our subsidiary companies. These transactions are
referred to as the "reorganization". In addition, in September 2002 Plains
Resources made: (i) a $5.0 million cash contribution to us; and (ii) a $7.2
million contribution to us in the form of a promissory note payable, both as
part of the working capital for the upstream assets contributed to us. The
promissory note bears interest at 2.5% due on December 15, 2002. The
contribution of the amounts payable to Plains Resources, the cash contribution
and the contribution of the promissory note are all reflected in Stockholder's
Equity. In addition, Plains Resources may contribute up to $42.8 million to us
before the spin-off.
On June 21, 2002 we filed a registration statement on Form S-1 with the SEC
for the initial public offering, or the IPO, of our common stock. We terminated
the IPO in October 2002, primarily due to market conditions. As a result, costs
and expenses of $1.7 million incurred in connection with the IPO were charged
to expense during the third quarter of 2002. We estimate that additional
charges of $0.7 to $0.8 million will occur in the fourth quarter of 2002.
Financings
On July 3, 2002 we and Plains E&P Company, our wholly owned subsidiary that
has no material assets and was formed for the sole purpose of being a corporate
co-issuer of certain of our indebtedness, issued $200.0 million of Series A
notes. The notes are our unsecured general obligations, are subordinated in
right of payment to all of our existing and future indebtedness and are jointly
and severally guaranteed on a full and unconditional basis by all of our
existing and future domestic restricted subsidiaries.
On July 3, 2002 we also entered into a $300.0 million revolving credit
facility. The credit facility provides for a borrowing base of $225.0 million
that will be reviewed every six months, with the lenders and us each having the
right to one annual interim unscheduled redetermination, and adjusted based on
our oil and gas properties, reserves, other indebtedness and other relevant
factors, and matures in 2005. As of September 30, 2002 we had $90.7 million
outstanding under this credit facility. Additionally, the credit facility
contains a $30.0 million sub-limit on letters of credit (of which $5.2 million
had been issued as of September 30, 2002). To secure borrowings, we pledged
100% of the shares of stock of our domestic subsidiaries and gave mortgages
covering 80% of the total present value of our domestic oil and gas properties.
We distributed the net proceeds of $195.3 million from the Series A notes
and $116.7 million in initial borrowings under our credit facility to Plains
Resources, which used:
. $287.0 million to redeem its 10.25% senior subordinated notes on August
2, 2002; and
. $25.0 million to repay the amounts outstanding under its credit facility.
Purchase of Additional Point Arguello Interest
In August 2002 we acquired an additional 26.3% working interest in the
Point Arguello unit and the various partnerships owning the related
transportation, processing and marketing infrastructure. The seller retained
responsibility for certain abandonment costs, including: (1) removing,
dismantling and disposing of the existing offshore platforms; (2) removing and
disposing of all pipelines; and (3) removing, dismantling, disposing and
remediating all existing onshore facilities. We assumed the seller's share of
the costs of plugging the wells and flushing the lines. As consideration for
receiving the transferred properties and assuming the obligations described
above, we received $2.4 million in cash for the sale and $3.0 million as our
share of revenues less costs for the period from April 1, to July 30, 2002.
This transaction doubled our working interest in the Point Arguello unit to
52.6%.
63
Oil and Gas Reserves
The following tables set forth certain information with respect to our
reserves based upon reserve reports prepared by the independent petroleum
consulting firms of Netherland, Sewell & Associates, Inc. and Ryder Scott
Company in 2001, and H.J. Gruy and Associates, Inc., Netherland, Sewell &
Associates, Inc. and Ryder Scott Company in 2000 and 1999. The reserve volumes
and values were determined under the method prescribed by the SEC, which
requires the application of year-end prices for each year, held constant
throughout the projected reserve life.
Year Ended December 31,
------------------------------
2001 2000 1999
-------- ---------- ----------
(Dollars in thousands)
Oil (Mbbls):
Proved developed.... 119,248 105,679 100,758
Proved undeveloped.. 104,045 98,708 94,455
-------- ---------- ----------
Total.............. 223,293 204,387 195,213
======== ========== ==========
Gas (MMcf):
Proved developed.... 59,101 52,184 49,255
Proved undeveloped.. 37,116 41,302 41,618
-------- ---------- ----------
Total.............. 96,217 93,486 90,873
======== ========== ==========
Total (MBOE)........ 239,329 219,968 210,359
======== ========== ==========
PV-10:(1)
Proved developed.... $454,095 $ 982,752 $ 628,451
Proved undeveloped.. 189,125 321,430 477,907
-------- ---------- ----------
Total.............. $643,220 $1,304,182 $1,106,358
======== ========== ==========
Standardized measure $384,467 $ 789,438 $ 727,286
======== ========== ==========
- --------
(1) Based on year-end spot market prices of: (a) $19.84 per Bbl of oil and
$2.58 per Mcf of gas for 2001; (b) $26.80 per Bbl of oil and $13.70 per Mcf
of gas for 2000; and (c) $25.60 per Bbl of oil and $2.37 per Mcf of gas for
1999. PV-10 represents the standardized measure before deducting estimated
future income taxes.
There are numerous uncertainties inherent in estimating quantities and
values of proved reserves, and in projecting future rates of production and
timing of development expenditures. Many of the factors that impact these
estimates are beyond our control. Reservoir 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, engineering and geological
interpretation, and judgment. Because all reserve estimates are to some degree
speculative, the quantities of oil and gas that are ultimately recovered,
production and operating costs, the amount and timing of future development
expenditures, and future oil and gas sales prices may all differ from those
assumed in these estimates. In addition, different reserve engineers may make
different estimates of reserve quantities and cash flows based upon the same
available data. Therefore, the PV-10 shown above represents estimates only and
should not be construed as the current market value of the estimated oil and
gas reserves attributable to our properties.
In accordance with SEC guidelines, the reserve engineers' estimates of
future net revenues from our properties, and the present value of the
properties, are made using oil and gas sales prices in effect as of the dates
of such estimates and are held constant throughout the life of the properties,
except where the guidelines permit alternate treatment, including the use of
fixed and determinable contractual price escalations but excluding the effect
of any hedges we have in place. The prices used in our reserve reports as of
December 31, 2001 of $15.31 per Bbl of oil and $2.56 per Mcf of gas reflect the
year-end spot market prices of $19.84 per Bbl of oil and $2.58 per Mcf of gas,
as adjusted for variations based on location and quality of oil. Historically,
the prices for oil and gas have been volatile and are likely to continue to be
volatile in the future.
64
Exploitation and Development
Exploitation strategy. We implement our exploitation plan with respect to
our properties by:
. enhancing product price realizations;
. optimizing production practices;
. realigning and expanding injection processes;
. drilling wells; and
. performing stimulations, recompletions, artificial lift upgrades and
other operating margin and reserve enhancements.
After we acquire a property, we may also seek to increase our interest in
the property by acquiring nearby acreage, pursuing farm-in drilling
arrangements and purchasing minority interests in the property.
By implementing our exploitation plan, we seek to increase cash flows and
enhance the value of our asset base. In doing so, we add to and enhance our
proved reserves. During the five-year period ended December 31, 2001 our
additions to proved reserves totaled 120.6 MMBOE, or approximately 332% of
cumulative net production for this period. We added these reserves at an
aggregate average cost of $3.17 per BOE, excluding reserves added as a result
of our acquisition activities. Reserve additions related solely to our
acquisition activities totaled 57.3 MMBOE and were added at an aggregate
average cost of $1.06 per BOE.
We believe that our properties in our core areas hold potential for
additional increases in production, reserves and cash flow. In that regard, as
a result of our 2002 capital program and preliminary 2003 capital program, we
currently expect to achieve a 5% to 10% growth rate from our properties in
2003. However, we can give no assurance that increases will be achieved.
During 2002, we expect to spend approximately $63.0 million maintaining,
developing and exploiting our oil and gas properties and pursuing acquisition
opportunities. We expect approximately $46.0 million of these capital
expenditures will be for exploitation projects in onshore California. The 2002
capital program incorporates the results of various analyses and field studies
and includes our drilling approximately 88 total wells, including 8 injection
wells and numerous injection realignment related workovers. During the nine
months ended September 30, 2002 capital expenditures for these activities were
$47.3 million.
Exploitation projects. The following table sets forth information with
respect to our oil and gas properties (dollars in millions):
Onshore California Properties
-----------------------------------
Arroyo Offshore Illinois Basin
LA Basin Montebello Grande Mt. Poso California and other
-------- ---------- ------ -------- ---------- --------------
(Dollars in thousands)
Year(s) discovered............ 1924-66 1917 1906 1926 1981 1905
Year acquired................. 1992 1997 1997 1998 1999 1995
Proved reserves at acquisition
(MMBOE)..................... 17.7 23.3 19.9 7.7 6.4 17.3
As of December 31, 2001:
Proved reserves MMBOE......... 114.1 27.6 60.8 9.3 5.0 22.5/(2)/
Percent oil.................. 91% 97% 93% 100% 98% 98%
Proved developed reserves
(MMBOE)..................... 79.9 15.5 12.0 4.6 3.8 13.3
PV-10/(1)/.................... $ 357.7 $71.4 $126.1 $22.5 $ 6.9 $58.6
65
(1) Based on year-end 2001 spot market prices of $19.84 per Bbl of oil and
$2.58 per Mcf of gas. PV-10 represents the standardized measure before
deducting estimated future income taxes. Our standard measure at December
31, 2001 was $384.5 million. The PV-10 and standardized measure have been
reduced to reflect the abandonment costs of certain properties.
(2) 21.1 MMBOE of these reserves are in the Illinois Basin and the remaining
reserves are attributed to other properties we hold in the United States.
Onshore California
LA Basin. In 1992 we acquired from Chevron U.S.A., Inc. substantially all
of its producing oil properties in the LA Basin. These interests included the
Inglewood, East Beverly Hills, San Vicente and South Salt Lake fields.
Following the initial acquisition we expanded our holdings in this area by
acquiring additional interests within the existing fields, including all of
Texaco Exploration and Production, Inc.'s interest in its Vickers lease, which
further consolidated our holdings in the Inglewood field. We refer to all of
our properties in the LA Basin acquired before 1997 collectively as the "LA
Basin properties". We hold a 100% working interest in the LA Basin properties.
The LA Basin properties consist of oil reserves discovered at various times
between 1924 and 1966. We have performed various exploitation activities,
including drilling additional production and injection wells, returning
previously marginal wells to economic production, optimizing pre-existing
waterflood operations, initiating new waterfloods, optimizing artificial lift,
increasing the capacity and efficiency of facilities, upgrading facilities to
maintain regulatory compliance, reducing unit production expenses and improving
marketing margins. Additionally, we continuously update and perform technical
studies to identify new investment opportunities on these properties. Through
these acquisition and exploitation activities, our net average daily production
from this area has increased from approximately 6,700 BOE per day in 1992 to
12,300 BOE per day in the first nine months of 2002.
In December 1995, we negotiated an agreement with a unit of ChevronTexaco
to remediate sections of our LA Basin properties impacted by prior drilling and
production operations. Under this agreement, ChevronTexaco agreed to
investigate contamination at the LA Basin properties and potentially remediate
specific areas contaminated with hazardous substances, such as volatile organic
substances and heavy metals, and we agreed to excavate and remediate
nonhazardous oil contaminated soils. We are obligated to construct and operate,
for the next eight years, at least a five-acre parcel of land as bioremediation
cells for oil contaminated soils designated for excavation and treatment by
ChevronTexaco. Although we believe that we do not have any material obligations
for operations conducted before our acquisition of the properties from
ChevronTexaco other than our obligation to plug existing wells and those
normally associated with customary oil field operations of similarly situated
properties (such as our agreement with ChevronTexaco described above), these
amounts may not be recoverable from ChevronTexaco, either under our agreement
or the limited indemnity from ChevronTexaco contained in the original purchase
agreement.
In 2001 we spent $66.8 million on capital projects on the LA Basin
properties, the most significant of which were drilling 42 production and 15
injection wells. In 2002 we expect to spend $34.0 million on capital projects,
which will include drilling 22 production wells and four injection wells,
performing numerous recompletions and workovers, and modifying various
production and injection facilities.
We are also assessing the application of 3-D seismic technology to further
evaluate the unproved reserves in our LA Basin properties. We expect to shoot
the 3-D survey in 2003, interpretation of the data should occur in 2003 and any
drilling based on the results may take place in late 2003 and in 2004 and 2005.
This will be the first application of 3-D seismic technology in an onshore LA
Basin Field. Also in the Inglewood Field, we have initiated a 20-well
evaluation program using cased hole
66
resistivity logging technology. This technology potentially identifies
commercially producible sands behind casing in older wells. Furthermore, we
expect these analyses to provide us with a more complete understanding of the
field thereby potentially allowing us to improve the waterflood program.
Finally, we are considering alternatives to procuring electricity for the field
such as a self or cogeneration facility.
Montebello. In March 1997 we expanded our operations in the LA Basin by
acquiring Chevron USA's interest in the Montebello field, which included a 100%
working interest (99.2% net revenue interest) in 55 producing oil wells and
related facilities and approximately 450 acres of surface fee land. Our net
average daily production from this field has increased from 930 BOE per day at
the time of acquisition to 2,500 BOE per day in the first nine months of 2002.
Since the acquisition, we have drilled a total of 48 producing wells and 22
injection wells. During 2000, we evaluated the field reservoir information and
prepared a comprehensive waterflood development plan. In 2001 we spent
$13.0 million on capital projects in the Montebello field, the most significant
of which was drilling 17 production and three injection wells. In 2002 we
expect to spend $10.0 million on capital projects, which include drilling 12
production wells and six injection wells, performing numerous workovers and
increasing the capacity of the production and injection facilities.
Arroyo Grande. In November 1997 we acquired a 100% working interest (94%
net revenue interest) in the Arroyo Grande field located in San Luis Obispo
County, California, from subsidiaries of Shell Oil Company. We also acquired
surface and related development rights to approximately 1,000 acres included in
the 1,500-acre producing unit. The field is primarily under continuous steam
injection and, at our acquisition date, was producing approximately 1,600 BOE
per day (approximately 1,500 BOE net to our interest) of 14 degree API gravity
oil from 70 wells. Since acquiring this property, we have drilled additional
wells to downsize the injection patterns in the currently developed area from
five acres to one and a quarter acres to accelerate recoveries, and realigned
steam injection within these areas to increase the efficiency of the recovery
process. We also curtailed steam injection by about 50% immediately following
the acquisition due to low oil prices. Although oil prices subsequently
rebounded, we maintained injection at this low rate pending our analysis of the
saturation inputs provided by the infill drilling program, and in 2001 due to
excessive gas fuel costs. As a result, base volumes declined considerably, but
this decline was offset by the wells we drilled to downsize the injection
patterns.
In 2001 we spent $10.6 million on capital projects in the Arroyo Grande
field, the most significant of which was drilling 19 production and 11
injection wells and installing a gas processing facility to reduce third-party
fuel gas purchases. During 2002 we reduced capital expenditures to $1.0 million
to allow time to assess the results of the 2001 drilling program and prepare to
expand our steam flood in 2003-2004. We are also reviewing a plan to optimize
steam handling and produced water disposal during 2002. Our net average daily
production from this field was approximately 1,900 BOE per day during the first
nine months of 2002.
Mt. Poso. During 1998 we acquired the Mt. Poso field from Aera Energy LLC.
The Mt. Poso field is located near Bakersfield, California, in Kern County.
When we acquired the field, it was producing 900 BOE per day of 15 to 17 degree
API gravity oil and added 7.7 MMBOE to our proved reserves. Since acquisition,
we have undertaken an aggressive recompletion and drilling program targeting
the Pyramid Hills formation, completing a 107-well drilling program in
2000-2001. In 2001 we spent $10.3 million on capital projects in the Mt.Poso
field, the most significant of which was drilling 43 production wells and
recompleting 38 wells. During 2002 we reduced capital expenditures as we will
focus on optimizing operating costs, including the installation of electrical
generation facilities, and reviewing past drilling results to identify future
drilling potential. In 2002 we expect to spend $1.0 million on capital projects
to optimize our producing infrastructure. Our net average daily production from
this field was 1,600 BOE during the first nine months of 2002.
67
Offshore California
Point Arguello. In July 1999 we acquired Chevron USA's 26.3% working
interest in the Point Arguello unit and the various partnerships owning the
related transportation, processing and marketing infrastructure. We are the
operator for the Point Arguello unit which consists of three offshore
platforms. Chevron USA retained responsibility for certain abandonment costs,
including: (1) removing, dismantling and disposing of the existing offshore
platforms; (2) removing and disposing of all existing pipelines; and (3)
removing, dismantling, disposing and remediating all existing onshore
facilities. We assumed Chevron USA's 26.3% share of all other abandonment costs.
In 2001 we spent $5.6 million on capital projects in the Point Arguello
unit, the most significant of which was drilling six production wells and a
number of recompletion and stimulation workovers. In 2002 we expect to spend
$7.0 million on capital projects, which includes drilling three development
wells and converting five wells to electric submersible lift systems, and
various recompletions and stimulations.
In August 2002 we acquired an additional 26.3% working interest from
subsidiaries of Phillips Petroleum Company in the Point Arguello unit and the
various partnerships owning the related transportation, processing and
marketing infrastructure with effect from April 1, 2002. The seller retained
responsibility for certain abandonment costs, including: (1) removing,
dismantling and disposing of the existing offshore platforms; (2) removing and
disposing of all pipelines; and (3) removing, dismantling, disposing and
remediating all existing onshore facilities. We assumed the seller's share of
the costs of plugging the wells and flushing the lines. As consideration for
receiving the transferred properties and assuming the obligations described
above we received $2.4 million. In addition, we received $3.0 million as our
share of revenues less costs for the period from April 1 to July 30, 2002.
Final determination of this amount and certain other purchase price adjustments
will be made within six months of the closing date. This transaction doubled
our working interest in the Point Arguello unit to 52.6%.
At the time we acquired our interest in Point Arguello, our net average
daily production from this unit was 5,200 BOE. During the first nine months of
2002 our net average daily production was 4,200 BOEs including the interest
acquired effective August 1, 2002.
Rocky Point. Part of one of our leases in the Point Arguello unit is
partially unitized in the Rocky Point unit, which is adjacent to the Point
Arguello unit. As a result, we are the operator and have an agreement that
entitles us to participate with at least a 52.6% working interest in the
development of the Rocky Point unit. We are particularly interested in this
unit because five exploratory wells were drilled into it in 1983-1984, and
these wells tested at 3,500, 1,629, 1,100, 604 and 120 Bbls per day.
Accordingly, we are currently seeking regulatory approval to allow near-term
development of our lease in the Rocky Point unit by drilling extended-reach
wells from the Point Arguello platforms. While we must obtain a larger rig and
several regulatory permits and other agreements among the working interest
owners, we believe that if we resolve these issues, we may be able to drill in
the Rocky Point unit. There can be no assurance, however, that any such
drilling can or will occur or that we will recover economic quantities of oil
and gas from the Rocky Point unit. The other two leases that compose the Rocky
Point unit are subject to litigation between the federal government and the
state of California concerning the state's ability to review MMS approvals of
lease suspensions for consistency with the state's Coastal Management Program
and cannot be developed until the resolution of such litigation.
Other Offshore California. Similar to Rocky Point, portions of two other
nearby undeveloped offshore units, Sword and Bonito, could be developed by
extended reach wells originating from the Point Arguello unit platforms. We
have no interest in Sword unit and an approximate 2.6% interest in Bonito unit.
To develop the Sword or Bonito units from the Point Arguello platforms, the
Sword and
68
Bonito unit owners would have to secure all necessary permits and regulatory
approvals and reach a commercial agreement for the use of the Point Arguello
infrastructure. In addition, currently the Sword and Bonito units are subject
to litigation between the federal government and the state of California
concerning the state's ability to review MMS approvals of lease suspensions for
consistency with the state's Coastal Management Program and cannot be developed
until the resolution of such litigation. There can be no assurance, however,
that such development will occur. We are not the operator of the Sword or
Bonito units.
Illinois Basin
In December 1995 we acquired our properties in the Illinois Basin from
Marathon Oil Company, which produced an average of 2,700 Bbls of oil per day in
2001 and accounted for 11% of our total sales volumes. In 2001 we spent $9.5
million on capital projects in the Illinois Basin, the most significant of
which was drilling 42 production and nine injection wells and various water
injection realignment projects. In 2002, we expect to spend $7.0 million on
capital projects, which include drilling 37 development wells. In addition, we
are continuing to evaluate the feasibility and potential implementation of a
pilot program to field test an alkaline-surfactant enhanced oil recovery
process. Our production from the Illinois Basin averaged 2,600 Bbls of oil per
day in the first nine months of 2002.
Other
Our 2001 capital expenditures includes $9.9 million of capitalized interest
and general and administrative costs allocable directly to acquisition,
exploitation and development activities. Our 2002 estimated capital
expenditures include $11.0 million of capitalized interest and general and
administrative costs allocable directly to acquisition, exploitation and
development activities and $3.0 million attributable to other projects.
Exploration and acquisition expenditures
The following table summarizes the costs incurred during the last three
years for our exploitation and development, exploration and acquisition
activities.
Year Ended December 31,
------------------------
2001 2000 1999
-------- ------- -------
(In thousands)
Exploitation and development costs $123,778 $68,186 $54,996
Exploration costs................. 286 293 796
Property acquisition costs:
Unproved properties.............. 44 73 879
Proved properties................ 1,645 1,953 2,496
-------- ------- -------
Total............................. $125,753 $70,505 $59,167
======== ======= =======
Exploitation and development costs include expenditures of $58.5 million in
2001, $20.6 million in 2000 and $10.7 million in 1999 related to the
development of proved undeveloped reserves included in our proved oil and gas
reserves at the beginning of each year. Our year-end 2001 standardized measure
includes future development costs related to proved undeveloped reserves of
$25.5 million in 2002, $58.9 million in 2003 and $45.2 million in 2004.
69
Production and Sales
The following table presents information with respect to oil and gas
production attributable to our properties, the revenues we derived from the
sale of this production, average sales prices we received and our average
production expenses during the nine months ended September 30, 2002 and 2001,
and the years ended December 31, 2001, 2000 and 1999.
Nine Months
Ended September 30, Year Ended December 31,
------------------- --------------------------
2002 2001 2001 2000 1999
-------- -------- -------- -------- --------
Production:
Oil (MBbls)............................. 6,433 6,057 8,219 7,654 7,081
Gas (MMcf).............................. 2,540 2,499 3,355 3,042 3,163
Total (MBOE)............................ 6,856 6,473 8,778 8,161 7,608
Oil and gas revenues (In thousands):
Oil..................................... $129,563 $133,957 $174,895 $126,434 $102,390
Gas..................................... 7,130 26,870 28,771 16,017 5,095
Other/(1)/.............................. 27 468 473 -- --
-------- -------- -------- -------- --------
Total revenues....................... $136,720 $161,295 $204,139 $142,451 $107,485
======== ======== ======== ======== ========
Average realized prices (hedged):
Oil..................................... $ 20.14 $ 22.12 $ 21.28 $ 16.52 $ 14.46
Gas ($/Mcf)............................. 2.81 10.75 8.58 5.26 1.61
BOE..................................... 19.94 24.85 23.20 17.46 14.13
Expenses ($/BOE):
Average production expenses............. $ 8.29 $ 7.41 $ 7.27 $ 6.89 $ 6.64
General and administrative.............. 1.07 1.09 1.16 0.77 0.57
Depletion, depreciation and amortization 3.04 2.58 2.70 2.25 1.72
- --------
(1) Other revenues represents electricity related sales.
Pursuant to an oil marketing agreement, PAA is the exclusive purchaser of
all of our equity oil production. Plains Resources owns a 25% interest in PAA.
Product Markets and Major Customers
Our revenues are highly dependent upon the prices of, and demand for, oil
and gas. Historically, the markets for oil and gas have been volatile and are
likely to continue to be volatile in the future. The prices we receive for our
oil and gas production and the levels of our production are subject to wide
fluctuations and depend on numerous factors beyond our control, including
seasonality, economic conditions, foreign imports, political conditions in
other oil-producing and gas-producing countries, the actions of OPEC, and
domestic government regulation, legislation and policies. Decreases in oil and
gas prices have had, and could have in the future, an adverse effect on the
carrying value of our proved reserves and our revenues, profitability and cash
flow.
To manage our exposure to commodity price risks, we use various derivative
instruments to hedge our exposure to price fluctuations on oil sales. Our
hedging arrangements provide us protection on the hedged volumes if oil prices
decline below the prices at which these hedges are set. However, ceiling prices
in our hedges may cause us to receive less revenues on the hedged volumes than
we would receive in the absence of hedges. We do not currently have any gas
hedges.
Deregulation of gas prices has increased competition and volatility of gas
prices. Prices received for our gas are subject to seasonal variations and
other fluctuations. All of our gas production is currently sold under various
arrangements at spot indexed prices.
70
Substantially all of our oil and gas production is transported by
pipelines, trucks and barges owned by third parties. The inability or
unwillingness of these parties to provide transportation services to us for a
reasonable fee could result in our having to find transportation alternatives,
increased transportation costs or involuntary decreases in a significant
portion of our oil and gas production.
Pursuant to an oil marketing agreement, PAA is the exclusive purchaser of
all of our equity oil production. The marketing agreement provides that PAA
will purchase for resale at market prices all of our equity oil production. We
pay PAA a marketing and administration fee of $0.20 per barrel and reimburse
PAA for its reasonable expenses incurred in transporting or exchanging our oil.
We have agreed to renegotiate the marketing and administration fee in good
faith every three years. Under the marketing agreement, PAA has also agreed to,
upon our request and reimbursement for its reasonable expenses, market certain
of our gas and gas liquids and negotiate our gas purchase agreements. If we
were to lose PAA as the exclusive purchaser of our equity production, we
believe PAA could be replaced by other purchasers under contracts with similar
terms and conditions. However, PAA's role as the exclusive purchaser for all of
our equity oil production does have the potential to impact our overall
exposure to credit risk, either positively or negatively, in that PAA may be
affected by changes in economic, industry or other conditions.
Productive Wells and Acreage
As of December 31, 2001 we had working interests in 2,057 gross (2,031 net)
active producing oil wells. The following table sets forth information with
respect to our developed and undeveloped acreage as of December 31, 2001.
December 31, 2001
---------------------------------
Developed Acres Undeveloped Acres
--------------- -----------------
Gross Net Gross Net/(1)/
------ ------ ------- -------
Onshore California...... 8,889 8,844 8,928 5,296
Offshore California/(2)/ 15,326 4,033 41,720 1,449
Illinois and other/(3)/. 17,777 15,482 69,360 49,101
------ ------ ------- ------
Total.................. 41,992 28,359 120,008 55,846
====== ====== ======= ======
- --------
(1) Less than 10% of total net undeveloped acres are covered by leases that
expire from 2002 through 2004.
(2) Excludes 1,632 undeveloped acres (net) that we have the right to acquire
under an option agreement.
(3) Includes 53,022 gross undeveloped acres and 42,505 net undeveloped acres
that will be transferred to us in accordance with the terms of the
separation agreement.
Drilling Activities
Information with regard to our developmental well drilling activities during
the years ended December 31, 2001, 2000 and 1999 is set forth below:
Year Ended December 31,
-----------------------------------
2001 2000 1999
----------- ----------- -----------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Development wells:
Oil............... 168.0 163.4 156.0 154.0 105.0 105.0
Gas............... -- -- -- -- -- --
Dry............... 1.0 1.0 2.0 2.0 -- --
----- ----- ----- ----- ----- -----
Total.......... 169.0 164.4 158.0 156.0 105.0 105.0
===== ===== ===== ===== ===== =====
71
Real Estate
We currently own surface and mineral rights in the following tracts of real
property, portions of which are used in our oil and gas operations:
Approximate
Property Location acreage
-------- -------- -----------
Inglewood.... Los Angeles County, California 40
Montebello... Los Angeles County, California 450
Arroyo Grande San Luis Obispo County, California 1,045
Mt. Poso..... Kern County, California 1,230
Gaviota...... Santa Barbara County, California 160
In the course of our business, certain of our properties may be subject to
easements or other incidental property rights and legal requirements that may
affect the use and enjoyment of our property. For instance, 183 of our acres in
the Montebello field have been designated as California Coastal Sage Scrub.
Title to Properties
Our properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other burdens, including
other mineral encumbrances and restrictions. We do not believe that any of
these burdens materially interfere with our use of the properties in the
operation of our business.
We believe that we have generally satisfactory title to or rights in all of
our producing properties. As is customary in the oil and gas industry, we make
minimal investigation of title at the time we acquire undeveloped properties.
We make title investigations and receive title opinions of local counsel only
before we commence drilling operations. We believe that we have satisfactory
title to all of our other assets. Although title to our properties is subject
to encumbrances in certain cases, we believe that none of these burdens will
materially detract from the value of our properties or from our interest
therein or will materially interfere with our use in the operation of our
business.
Competition
Our competitors include major integrated oil and gas companies and numerous
independent oil and gas companies, individuals and drilling and income
programs. Many of our larger competitors possess and employ financial and
personnel resources substantially greater than ours. These competitors are able
to pay more for productive oil and gas properties and exploratory prospects and
to define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. Our ability to acquire
additional properties and to discover reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. In addition, there is
substantial competition for capital available for investment in the oil and gas
industry.
Regulation
Our operations are subject to extensive regulations. Many federal, state
and local departments and agencies are authorized by statute to issue, and have
issued, laws and regulations binding on the oil and gas industry and its
individual participants. The failure to comply with these rules and regulations
can result in substantial penalties. The regulatory burden on the oil and gas
industry increases our cost of doing business and, consequently, affects our
profitability. However, we do not believe that we are affected in a
significantly different manner by these laws and regulations than are
72
our competitors. Due to the myriad of complex federal, state and local
regulations that may affect us directly or indirectly, you should not rely on
the following discussion of certain laws and regulations as an exhaustive
review of all regulatory considerations affecting our operations.
OSHA. We are subject to the requirements of the federal Occupational
Safety and Health Act, as amended, or OSHA, and comparable state statutes that
regulate the protection of the health and safety of workers. In addition, the
OSHA hazard communication standard, the United States Environmental Protection
Agency community-right-to-know regulations, and similar state statutes require
that we maintain certain information about hazardous materials used or produced
in our operations and that we provide this information to our employees, state
and local government authorities and citizens. We believe that our operations
are in substantial compliance with OSHA requirements, including general
industry standards, record keeping requirements and monitoring of occupational
exposure to regulated substances.
MMS. Our oil and gas operations on offshore leases located in federal
waters are regulated by the MMS. The MMS has broad authority over these
operations. It must approve and grant permits in connection with our drilling
and development plans. Additionally, the MMS has promulgated regulations
requiring offshore production facilities to meet stringent engineering and
construction specifications restricting the flaring or venting of gas,
governing the plugging and abandonment of wells and controlling the removal of
production facilities. Under certain circumstances, the MMS may require the
suspension or termination of any of our operations on federal leases, as
discussed in "Risk Factors-- Governmental agencies and other bodies, including
those in California, might impose regulations that increase our costs and may
terminate or suspend our operations," and has proposed regulations that would
permit it to expel unsafe operators from offshore operations. The MMS has also
established rules governing the calculation of royalties and the valuation of
oil produced from federal offshore leases and regulations regarding costs for
gas transportation. Delays in the approval of plans and issuance of permits by
the MMS because of staffing, economic, environmental or other reasons could
adversely affect our operations.
Regulation of production. The production of oil and gas is subject to
regulation under a wide range of federal and state statutes, rules, orders and
regulations. State and federal statutes and regulations require permits for
drilling operations, drilling bonds and reports concerning operations. The
states in which we own and operate properties have regulations governing
conservation matters, including provisions for the unitization or pooling of
oil and gas properties, the establishment of maximum rates of production from
oil and gas wells and the regulation of the spacing, plugging and abandonment
of wells. Many states also restrict production to the market demand for oil and
gas, and several states have indicated interest in revising applicable
regulations. These regulations limit the amount of oil and gas we can produce
from our wells and limit the number of wells or the locations at which we can
drill. Also, each state generally imposes an ad valorem, production or
severance tax with respect to production and sale of oil, gas and natural gas
liquids within its jurisdiction.
Pipeline regulation. We have pipelines to deliver our production to sales
points. Our pipelines are subject to regulation by the United States Department
of Transportation with respect to the design, installation, testing,
construction, operation, replacement, and management of pipeline facilities. In
addition, we must permit access to and copying of records, and must make
certain reports and provide information, as required by the Secretary of
Transportation. The states in which we have pipelines have comparable
regulations. Some of our pipelines related to the Point Arguello unit are also
subject to regulation by the Federal Energy Regulatory Commission, or FERC. We
believe that our pipeline operations are in substantial compliance with
applicable requirements.
Sale of gas. The FERC regulates interstate gas pipeline transportation
rates and service conditions. Although the FERC does not regulate gas producers
such as us, the agency's actions are
73
intended to foster increased competition within all phases of the gas industry.
To date, the FERC's pro-competition policies have not materially affected our
business or operations. It is unclear what impact, if any, future rules or
increased competition within the gas industry will have on our gas sales
efforts.
The FERC, the United States Congress or state regulatory agencies may
consider additional proposals or proceedings that might affect the gas
industry. We cannot predict when or if these proposals will become effective or
any effect they may have on our operations. We do not believe, however, that
any of these proposals will affect us any differently than other gas producers
with which we compete.
Environmental. Our operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to safety,
health and environmental protection, including the generation, storage,
handling, emission and transportation of materials and the discharge of
materials into the environment. Other statutes that provide protection to
animal and plant species and which may apply to our operations include, but are
not necessarily limited to, the Marine Mammal Protection Act, the Marine
Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination
Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act
and the National Historic Preservation Act. These laws and regulations may
require the acquisition of a permit or other authorization before construction
or drilling commences and for certain other activities, limit or prohibit
construction, drilling and other activities on certain lands lying within
wilderness or wetlands and other protected areas; and impose substantial
liabilities for pollution resulting from our operations. The permits required
for various of our operations are subject to revocation, modification and
renewal by issuing authorities.
As with our industry generally, our compliance with existing and
anticipated laws and regulations increases our overall cost of business,
including our capital costs to construct, maintain, upgrade and close equipment
and facilities. Although these regulations affect our capital expenditures and
earnings, we believe that they do not affect our competitive position because
our competitors that comply with such laws and regulations are similarly
affected, except as discussed in "Risk Factors--Environmental liabilities could
adversely affect our financial condition". Environmental laws and regulations
have historically been subject to change, and we are unable to predict the
ongoing cost to us of complying with these laws and regulations or the future
impact of these laws and regulations on our operations. If a person violates
these environmental laws and regulations and any related permits, they may be
subject to significant administrative, civil and criminal penalties,
injunctions and construction bans or delays. If we were to discharge
hydrocarbons or hazardous substances into the environment, we could, to the
extent the event is not insured, incur substantial expense, including both the
cost to comply with applicable laws and regulations and claims made by
neighboring landowners and other third parties for personal injury and property
damage. For additional information, see "Risk Factors--Environmental
liabilities could adversely affect our financial condition".
Permits. Our operations are subject to various federal, state and local
regulations that include requiring permits for the drilling of wells,
maintaining bonding and insurance requirements to drill, operate, plug and
abandon, and restore the surface associated with our wells, and regulating the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled, the plugging and
abandonment of wells, the disposal of fluids and solids used in connection with
our operations and air emissions associated with our operations. Also, we have
permits from the city and county of Los Angeles, California, the city of Culver
City, California, the county of Kern, California, and the county of Santa
Barbara, California to operate crude oil, natural gas and related pipelines and
equipment that run within the boundaries of these governmental entities.
Plugging, Abandonment and Remediation Obligations
Under the amended terms of an asset purchase agreement with respect to
certain of our onshore California properties, commencing with the year
beginning January 1, 2000, and each year thereafter,
74
we are required to plug and abandon 20% of the then remaining inactive wells,
which currently aggregate approximately 149. To the extent we elect not to plug
and abandon the number of required wells, we are required to escrow an amount
equal to the greater of $25,000 per well or the actual average plugging cost
per well in order to provide for the future plugging and abandonment of such
wells. In addition, we are required to expend a minimum of $600,000 per year in
each of the ten years beginning January 1, 1996, and $300,000 per year in each
of the succeeding five years to remediate oil contaminated soil from existing
well sites, provided there are remaining sites to be remediated. If we do not
expend the required amounts during a calendar year, we are required to
contribute an amount equal to 125% of the actual shortfall to an escrow
account. We may withdraw amounts from the escrow account to the extent we
expend excess amounts in a future year. Through September 30, 2002, we have not
been required to make contributions to an escrow account.
In connection with the acquisitions of our interests in the Point Arguello
field, offshore California, we assumed our 52.6% share of (1) plugging and
abandoning all existing well bores, (2) removing conductors, (3) flushing
hydrocarbons from all lines and vessels and (4) removing/abandoning all
structures, fixtures and conditions created subsequent to closing. The sellers
retained the obligation for all other abandonment costs, including but not
limited to (1) removing, dismantling and disposing of the existing offshore
platforms, (2) removing and disposing of all existing pipelines and (3)
removing, dismantling, disposing and remediation of all existing onshore
facilities.
Although we obtained environmental studies on our properties in California
and Illinois and we believe that such properties have been operated in
accordance with standard oil field practices, certain of the fields have been
in operation for more than 90 years, and current or future local, state and
federal environmental laws and regulations may require substantial expenditures
to comply with such rules and regulations. In connection with the purchase of
certain of our onshore California properties, we received a limited indemnity
for certain conditions if they violate applicable local, state and federal
environmental laws and regulations in effect on the date of such agreement. We
believe that we do not have any material obligations for operations conducted
prior to our acquisition of the properties, other than our obligation to plug
existing wells and those normally associated with customary oil field
operations of similarly situated properties. Current or future local, state or
federal rules and regulations may require us to spend material amounts to
comply with such rules and regulations or that any portion of such amounts will
be recoverable under the indemnity.
Consistent with normal industry practices, substantially all of our oil and
gas leases require that, upon termination of economic production, the working
interest owners plug and abandon non-producing wellbores, remove tanks,
production equipment and flow lines and restore the wellsite. We have estimated
that at December 31, 2001 the costs to perform these tasks was approximately
$19.3 million, net of salvage value and other considerations.
Legal Proceedings
In the ordinary course of our business, we are a claimant or defendant in
various legal proceedings. We do not believe that the outcome of these legal
proceedings, individually or in the aggregate, will have a material adverse
effect on our financial condition, results of operations or cash flows.
On September 18, 2002 Stocker Resources Inc., or Stocker, our general
partner before we converted from a limited partnership to a corporation, filed
a declaratory judgment action against Commonwealth Energy Corporation (doing
business as electricAmerica), or Commonwealth, in the Superior Court of Orange
County, California relating to the termination of an electric service contract
between Stocker and Commonwealth. Pursuant to the agreement, Commonwealth had
agreed to supply Stocker with electricity and Stocker had obtained a $1.5
million performance bond in favor of
75
Commonwealth to secure its payment obligations under the agreement. Stocker
terminated the contract in accordance with its terms and Commonwealth notified
Stocker of its intent to draw upon the performance bond. Stocker is seeking a
declaratory judgment that it was entitled to terminate the contract and that
Commonwealth has no basis for proceeding against Stocker's related performance
bond. Also on September 18, 2002, Stocker was named a defendant in an action
brought by Commonwealth in the Superior Court of Orange County, California for
breach of the electric service contract. Commonwealth alleges that Stocker
breached the terms of the contract by the termination and its implied covenant
of good faith and fair dealing and is seeking unspecified damages. Under the
master separation agreement described on pages 87-89, we will be required to
indemnify Stocker for damages it incurs as a result of this action. We
understand that Stocker intends to defend its rights vigorously in this matter.
Employees
As of September 30, 2002 we had 244 full-time employees, 204 of whom were
field personnel involved in oil and gas producing activities. In addition, we
use the services of 57 employees through a management agreement with Plains
Resources. We believe our relationship with our employees is good. None of our
or Plains Resources' employees is represented by a labor union.
Effective October 1, 2002 Plains Resources hired 53 field personnel who
were formerly employed at our Illinois Basin operations on a contract basis.
These employees will become our employees after the spin-off. None of these
employees is represented by a labor union.
76
MANAGEMENT
Our Executive Officers and Directors
Except for Stephen A. Thorington, our Executive Vice President and Chief
Financial Officer, all of the individuals who perform the day-to-day financial,
administrative, and accounting functions for us, as well as those who are
responsible for directing and controlling us, are currently employed by Plains
Resources. In addition, a portion of our operational employees, generally those
associated with our Arguello unit and Illinois Basin operations, are also
employed by Plains Resources. Under a transition services agreement between us
and Plains Resources, Plains Resources charges us for these services, which
require substantially all of these persons' working time. The transition
services will expire when the spin-off is completed. See "Certain Transactions".
The following table sets forth certain information as of the date of this
prospectus regarding our executive officers and directors. They hold office
until their successors are duly elected and qualified, or until their earlier
death, removal or resignation from office.
Name Age Title
---- --- -----
James C. Flores...... 43 Chairman of the Board, Chief Executive Officer and a
Director
John T. Raymond...... 32 President and Chief Operating Officer
Stephen A. Thorington 46 Executive Vice President and Chief Financial Officer
Timothy T. Stephens.. 50 Executive Vice President--Administration, Secretary
and General Counsel
Cynthia Feeback...... 45 Senior Vice President--Accounting and Treasurer
Thomas M. Gladney.... 49 Senior Vice President of Operations
Jerry L. Dees........ 62 Director
Tom H. Delimitros.... 62 Director
John H. Lollar....... 63 Director
The following biographies describe the business experience of our executive
officers and directors:
James C. Flores, Chairman of the Board, Chief Executive Officer and a
Director since September 2002. He also has been Plains Resources' Chairman of
the Board and Chief Executive Officer since May 2001. He was President and
Chief Executive Officer of Ocean Energy, Inc., an oil and gas company, from
July 1995 until March 1999, and a director of Ocean Energy, Inc. from 1992
until March 1999. In March 1999 Ocean Energy, Inc. was merged into Seagull
Energy Corporation, which was the surviving corporation of the merger, and
which was renamed Ocean Energy, Inc. Mr. Flores served as Chairman of the Board
of the new Ocean Energy, Inc. from March 1999 until January 2000, and as Vice
Chairman from January 2000 until January 2001. From January 2001 to May 2001
Mr. Flores managed various private investments.
John T. Raymond, President and Chief Operating Officer since September
2002. He also has been Plains Resources' President and Chief Operating Officer
since November 2001. Previously, he was its Executive Vice President and Chief
Operating Officer from May 2001 to November 2001. In addition, Mr. Raymond
served as Director of Corporate Development of Kinder Morgan, Inc. from January
2000 to May 2001, and as Vice President of Corporate Development of Ocean
Energy, Inc. from April 1998 to January 2000. Mr. Raymond also served as Vice
President of Howard Weil Labouisse Friedrichs, Inc., an energy investment
company, from 1992 to April 1998. In addition, Mr. Raymond is a director of
Plains All American GP LLC, which is the general partner of Plains AAP.
Stephen A. Thorington, Executive Vice President and Chief Financial Officer
since September 2002. Previously, he was Senior Vice President--Finance and
Corporate Development
77
of Ocean Energy, Inc. from July 2001 to September 2002 and Senior Vice
President--Finance, Treasury and Corporate Development of Ocean Energy, Inc.
from March 1999 to July 2001. He also served as Vice President, Finance and
Treasurer of Seagull Energy Corporation from May 1996 to March 1999. Mr.
Thorington served as a Managing Director of Chase Securities, Inc. from April
1994 to May 1996.
Timothy T. Stephens, Executive Vice President--Administration, Secretary
and General Counsel since September 2002. He also has been Plains Resources'
Executive Vice President--Administration, Secretary and General Counsel since
May 2001. From March 2000 to May 2001 Mr. Stephens practiced as a private
business consultant to various clients. In February 1998 Mr. Stephens was hired
by the board of directors of Abacan Resources Corporation, an oil and gas
company, to help the company overcome significant financial difficulties. He
served as Chairman, President and Chief Executive Officer of Abacan until March
2000 when the company, after a two-year restructuring, was placed into
statutory receivership with the agreement of its senior creditor. Previously,
Mr. Stephens was President of Seven Seas Petroleum from February 1995 to May
1997, and Vice President of Enron Capital & Trade Resources Corp. from July
1991 to February 1995.
Cynthia Feeback, Senior Vice President--Accounting and Treasurer since
September 2002. She also has been Plains Resources' Senior Vice
President--Accounting and Treasurer since July 2001. She was its Vice
President--Accounting and Assistant Treasurer from May 1999 to July 2001, and
its Assistant Treasurer, Controller and Principal Accounting Officer from May
1998 to May 1999. Previously, Ms. Feeback served as its Controller and
Principal Accounting Officer from 1993 to 1998, Controller from 1990 to 1993,
and Accounting Manager from 1988 to 1990.
Thomas M. Gladney, Senior Vice President of Operations since September
2002. He also has been Plains Resources' Senior Vice President of Operations
since November 2001. He was President of Arguello, Inc., a subsidiary of ours,
from December 1999 to November 2001. From July 1999 to December 1999 he served
as a Project Manager for Torch Energy Services, a contract operating services
company. From January 1999 to June 1999 he served as a Project Manager for
Venoco Inc., an oil and gas company. From September 1998 to January 1999 he was
a self-employed engineering services consultant. From 1992 to September 1998 he
was Offshore Operations Manager for Oryx Energy Company. Previously, he served
as Gulf Coast Reserve Development Manager of Oryx Energy/Sun E&P from 1988 to
1992.
Jerry L. Dees, Director since September, 2002. He also has been a director
of Plains Resources since 1997 and will likely continue in that role until the
spin-off. He retired in 1996 as Senior Vice President, Exploration and Land,
for Vastar Resources, Inc. (previously ARCO Oil and Gas Company), a position he
had held since 1991. From 1987 to 1991 he was Vice President of Exploration and
Land for ARCO Alaska, Inc., and from 1985 to 1987 he held various positions as
Exploration Manager of ARCO. From 1980 to 1985 Mr. Dees was Manager of
Exploration Geophysics for Cox Oil and Gas Producers.
Tom H. Delimitros, Director since September, 2002. He also has been a
director of Plains Resources since 1998. He has been a General Partner of AMT
Venture Funds, a venture capital firm, since 1989. He is also a director of
Tetra Technologies, Inc., a publicly-traded energy services company. He
currently serves as Chairman for two privately-owned companies--ImageLinks,
Inc., and InterCorp International Inc.--both of which sell products and
services to energy companies. Previously, he has served as President and CEO
for Magna Corporation, (now Baker Petrolite, a unit of Baker Hughes). From 1983
to 1988, Mr. Delimitros was a General Partner of Sunwestern Investment Funds
and Senior Vice President of Sunwestern Management, Inc.
John H. Lollar, Director since September, 2002. He also has been a
director of Plains Resources since 1995. He has been the Managing Partner of
Newgulf Exploration L.P. since
78
December 1996. He is also a director of Lufkin Industries, Inc., a
manufacturing firm. Mr. Lollar was Chairman of the Board, President and Chief
Executive Officer of Cabot Oil & Gas Corporation from 1992 to 1995, and
President and Chief Operating Officer of Transco Exploration Company from 1982
to 1992.
After the spin-off, in addition to their employment with us, we expect that
Mr. Flores will continue as Chairman of the Board of Plains Resources and Mr.
Raymond will be Chief Executive Officer of Plains Resources. Also after the
spin-off, we expect that our other officers will no longer be employed by
Plains Resources and will be our full-time employees and Messrs. Dees,
Delimitros and Lollar will no longer serve as directors of Plains Resources.
BOARD OF DIRECTORS
Our bylaws authorize a board of directors consisting of at least three
members, with the exact number of directors being a number (not less than
three) that may be determined from time to time by resolution of our board of
directors. Our board of directors consists of four members, Messrs. Flores,
Dees, Delimitros and Lollar. Our directors are elected to hold office until our
next annual shareholder meeting and until his or her successor is duly elected
and qualified, or until his or her earlier death, resignation or removal.
COMMITTEES OF THE BOARD OF DIRECTORS
Our board of directors has established an audit committee, a compensation
committee and a nominating and corporate governance committee. Our board may
establish other committees from time to time to facilitate our management.
Our audit committee currently consists of Messrs. Dees, Delimitros and
Lollar, with Mr. Delimitros acting as chairman. Our audit committee selects our
independent auditors to be engaged by us, reviews the plan, scope and results
of our annual audit, and reviews our internal controls and financial management
policies with our independent auditors. All of the members of our audit
committee are non-employee directors. Our board of directors, in its business
judgment, has determined that all current members of our audit committee are
"independent" as defined in Sections 303.01(B)(2)(a) and (3) of the NYSE
listing standards.
Our compensation committee currently consists of Messrs. Dees, Delimitros
and Lollar, with Mr. Lollar acting as chairman. Our compensation committee
establishes guidelines and standards relating to the determination of executive
compensation, reviews executive compensation policies and recommends to our
entire board compensation for our executive officers and key employees. Our
compensation committee also administers our equity compensation plan and
determines the number of shares covered by, and terms of, grants to executive
officers and key employees. All of the members of our compensation committee
are non-employee directors.
Our nominating and corporate governance committee currently consists of
Messrs. Dees, Delimitros and Lollar, with Mr. Dees acting as chairman. Our
nominating and corporate governance committee identifies and evaluates
candidates for election as directors, nominates the slate of directors for
election by our stockholders, and develops and recommends to our board our
corporate governance principles.
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COMPENSATION
Compensation of Directors
We will pay each of our non-employee directors an annual retainer of
$25,000, each non-employee committee chairperson an annual retainer of $2,000,
an attendance fee of $3,000 for each board meeting attended in person, an
attendance fee of $1,000 for each committee meeting attended in person and an
attendance fee of $500 for each board or committee meeting attended
telephonically, and we will reimburse all directors for reasonable expenses
they incur while attending board and committee meetings.
Any non-employee director may elect to receive a grant of shares of our
common stock in lieu of the annual retainer fees as a board member and
chairperson and attendance fees for board meetings (except telephonic meetings
or other meetings attended by the director telephonically). The number of
shares is determined by dividing the fee amount by the closing price per share
of our common stock on the last trading day before we become obligated to pay
the fee.
In addition, each year on the day after the date of our annual stockholders
meeting, each non-employee director is entitled to receive a fully vested stock
option to purchase 10,000 shares of our common stock for a ten year term at an
exercise price equal to the closing price of our common stock on the meeting
date.
Mr. Flores receives, and any other of our officers who serve as directors
in the future will receive, no separate compensation for service on our board
of directors.
Executive Compensation
Plains Resources paid all the compensation of its officers during 1999,
2000 and 2001. Under the transition services agreement between Plains Resources
and us, we reimburse Plains Resources for costs incurred to provide us with
management services, including general and administrative expenses and other
employee costs.
Option Grants in 2001
We did not grant any options or stock appreciation rights to our executive
officers in 2001.
Option Exercises and Option Values in 2001
None of our executive officers held options to purchase our common stock as
of the end of, or exercised options to purchase our common stock during 2001.
2002 Stock Incentive Plan
We adopted our 2002 stock incentive plan on September 18, 2002 and amended
it effective November 20, 2002 to "divide it" into three plans: the 2002 stock
incentive plan; the rollover stock incentive plan; and the transition stock
incentive plan. The 2002 plan provides for the grant of stock options
(including incentive stock options, as defined in Section 422 of the Code, and
non-qualified stock options) and other awards (including performance units,
performance shares, share awards, restricted stock, restricted stock units, and
stock appreciation rights, or SARs) to our directors, officers and employees,
individuals to whom we have extended written offers of employment, and our
consultants and advisors. Our compensation committee, which is comprised of
"non-employee directors" within the meaning of Rule 16b-3 of the Securities
Exchange Act of 1934, or the Exchange Act, administers the 2002 plan. 500,000
shares of our common stock are subject to issuance under the 2002 plan. Our
compensation committee may grant options and SARs on such terms, including
vesting and payment forms, as it deems appropriate in its discretion, however,
no option or SAR may be
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exercised more than 10 years after its grant, and the purchase price for
incentive stock options and non-qualified stock options may not be less than
100% of the fair market value of our common stock on the date of grant. Our
compensation committee may grant restricted stock awards, restricted stock
units, share awards, performance units and performance shares on such terms and
conditions as it may in its discretion decide. Unless terminated earlier by our
board of directors, the 2002 plan will terminate on September 18, 2012.
Upon the occurrence of an event constituting a "change in control" (as
defined in the 2002 plan) of us, all options and SARs will become immediately
exercisable in full for the remainder of their terms. In addition, in such an
event, unless otherwise determined by our compensation committee and set forth
in the agreement governing the award, performance units will become immediately
vested and restrictions on stock granted pursuant to restricted stock awards
and restricted stock units will lapse.
The spin-off will not be a change of control under our 2002 plan.
Our board does not intend to make any grants under the 2002 plan unless it
is approved by our stockholders. The grants as described herein under the
rollover plan and the transition plan were not made under the 2002 plan.
Rollover Stock Incentive Plan
We adopted the rollover plan by splitting it off from the 2002 plan. The
purpose of the rollover plan is to govern the SARs issued in the spin-off
pursuant to the terms of the employee matters agreement as described on pages
89-90 and the restricted stock award of our common stock to be issued to Mr.
Thorington pursuant to the spin-off as a result of his restricted stock award
of 45,000 shares of Plains Resources common stock, which is described on page
84.
The maximum number of shares of our common stock with respect to which the
rollover SARs will be granted and with respect to Mr. Thorington's restricted
stock award will not exceed 4,000,000. If any portion of any of the rollover
SARs or Mr.Thorington's restricted stock award is forfeited, the shares with
respect to which they were granted will not be available for further grants.
Upon the occurrence of an event constituting a "change in control," all
rollover SARs will become immediately exercisable in full for the remainder of
their terms. In addition, the restrictions on Mr. Thorington's restricted stock
award will lapse. The spin-off will not constitute a change in control under
the rollover plan.
Transition Stock Incentive Plan
We adopted the transition plan by splitting it off from the 2002 plan. The
purpose of the transition plan is to make one-time grants of 75,000 shares of
restricted stock to Mr. Flores, 60,000 shares of restricted stock to Mr.
Raymond, and 30,000 shares of restricted stock to Mr. Stephens and a grant of
300,000 SARs to Mr. Thorington in accordance with their respective employment
agreements with us (which are discussed below).
The maximum number of shares of our common stock with respect to which
grants will be made under the transition plan will not exceed 465,000. If any
of the shares covered by any of the grants are forfeited, the forfeited shares
will not be available for further grants.
Upon the occurrence of an event constituting a "change in control," all
restrictions governing the grants of restricted stock will lapse and any
unvested SARs will become immediately exercisable in full for the remainder of
their terms. The spin-off will not constitute a change in control under the
transition plan.
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Employment Agreements and Change-in-Control Arrangements
James C. Flores. On September 19, 2002 we entered into an employment
agreement with Mr. Flores as our Chairman of the Board and Chief Executive
Officer, which will not be effective until the spin-off occurs. If the spin-off
date does not occur by May 23, 2003, the agreement will not become effective.
The agreement has an initial term of five years beginning on its effective
date, although it may be terminated earlier under certain circumstances. At the
end of the initial five-year term and, if such term is extended, each
subsequent term, the agreement will be subject to a one-year extension if we
and Mr. Flores agree to new compensation terms ninety days before the end of
the applicable term.
Pursuant to the employment agreement, beginning on its effective date, Mr.
Flores will be entitled to a base salary of $400,000 and will be eligible for a
target bonus of $400,000, subject to the attainment of performance goals. Also,
Mr. Flores has been granted an award of 75,000 restricted shares of our common
stock, which will vest over three equal annual installments beginning on the
first anniversary of the date of grant, which will be the date of our spin-off.
As a result of his employment with Plains Resources, Mr. Flores received an
option under the Plains Resources' 2001 stock incentive plan to purchase
1,000,000 shares of Plains Resources common stock at an exercise price of
$23.00 per share. At the time of the spin-off, pursuant to our employee matters
agreement with Plains Resources, which is discussed on pages 89-90, this
performance option will "split" such that Mr. Flores will receive (1) an option
to purchase 1,000,000 shares of Plains Resources common stock and (2) stock
appreciation rights, or SARs, with respect to 1,000,000 shares of our common
stock. The $23.00 exercise price of his existing Plains Resources option will
also be "split" between the new Plains Resources option and the SARs based on
the following relative amounts: the closing price (with dividend) of Plains
Resources common stock on the spin-off date less the closing price (on a
"when-issued" basis) of our common stock on the spin-off date, both as reported
on the NYSE, and such closing price of our common stock. The vesting terms will
remain unchanged. As a result, the SARs will become vested and exercisable on
the first to occur of:
. May 7, 2006;
. with respect to one-half of the shares subject to the SARs, a period of
10 trading days out of 20 consecutive trading days upon which the closing
price of our common stock equals or exceeds 150% of the SARs exercise
price;
. with respect to all shares subject to the SARs, a period of 10 trading
days out of 20 consecutive trading days upon which the closing price of
our common stock equals or exceeds 200% of the SARs exercise price;
. termination of Mr. Flores's employment by us for any reason other than
cause (as defined in the employment agreement) or because of Mr. Flores's
death or resignation or by Mr. Flores for good reason (as defined in the
employment agreement);
. a change in control (as defined in the employment agreement) of us; or
. any such time that Mr. Flores is not a member of our board of directors.
In February 2002, Mr. Flores was granted an option to purchase 125,000 shares
of Plains Resources common stock at an exercise price of $23.71 per share,
which vests over three equal annual installments beginning on the first
anniversary of the date of grant. This option will also "split" as discussed
above and the vesting terms would remain unchanged.
Under the employment agreement, Mr. Flores will also be entitled to all of
the employee benefits, fringe benefits and perquisites we provide to other
senior executives and we will reimburse him for monthly country club fees.
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Mr. Flores's employment agreement provides that if his employment is
terminated by us without cause, by Mr. Flores's death or disability, or by Mr.
Flores for good reason, we will pay him a lump sum amount equal to three times
the sum of his base salary and last earned annual bonus (or his target bonus if
his termination date occurs before a bonus amount has been determined for the
first calendar year of his employment). Also, Mr. Flores and his dependents
will be entitled to continued health insurance benefits for a period of three
years made "whole" on a net after-tax basis and all of Mr. Flores' equity-based
awards will become immediately exercisable and payable in full.
Under the employment agreement, if benefits to which Mr. Flores becomes
entitled are considered "excess parachute payments" under Section 280G of the
Code, then Mr. Flores will be entitled to an additional payment from us in an
amount equal to the excise tax imposed by Section 4999 of the Code or any
interest or penalties with respect to such excise tax (excluding any income tax
or employment tax imposed upon the additional payment).
John T. Raymond. On September 19, 2002 we entered into an employment
agreement with Mr. Raymond as our President and Chief Operating Officer, which
will not be effective until the spin-off occurs. If the spin-off does not occur
by May 23, 2003, the agreement will not become effective. The agreement has an
initial term of five years beginning on its effective date, although it may be
terminated earlier under certain circumstances. At the end of the initial
five-year term and, if such term is extended, each subsequent term, the
agreement will be subject to a one-year extension if we and Mr. Raymond agree
to new compensation terms ninety days before the end of the applicable term.
Pursuant to the employment agreement, beginning on its effective date, Mr.
Raymond will be entitled to a base salary of $350,000 and will be eligible for
a target bonus of $350,000, subject to the attainment of performance goals.
Also, Mr. Raymond has been granted an award of 60,000 restricted shares of our
common stock, which will vest over three equal annual installments beginning on
the first anniversary of the date of grant, which will be the date of our
spin-off.
As a result of his employment with Plains Resources, Mr. Raymond received
an option under the Plains Resources' 2001 stock incentive plan to purchase
300,000 shares of Plains Resources common stock at an exercise price of $25.26
per share. At the time of the spin-off, pursuant to our employee matters
agreement with Plains Resources, this option will "split" such that Mr. Raymond
will receive (1) an option to purchase 300,000 shares of Plains Resources
common stock and (2) SARs with respect to 300,000 shares of our common stock.
The $25.26 exercise price of his existing Plains Resources option will also be
"split" between the new Plains Resources option and the SARs based on the
following relative amounts: the closing price (with dividend) of Plains
Resources common stock on the spin-off date less the closing price (on a
"when-issued" basis) of our common stock on the spin-off date, both as reported
on the NYSE, and such closing price of our common stock. The vesting terms will
remain unchanged. As a result, 100,000 of the SARs will become vested and
exercisable on the first to occur of:
. May 16, 2006;
. with respect to one-half of the shares subject to the 100,000 SARs, a
period of 10 trading days out of 20 consecutive trading days upon which
the closing price of our common stock equals or exceeds 150% of the SARs
exercise price;
. with respect to all shares subject to the 100,000 SARs, a period of 10
trading days out of 20 consecutive trading days upon which the closing
price of our common stock equals or exceeds 200% of the SARs exercise
price;
. termination of Mr. Raymond's employment by us for any reason other than
cause (as defined in our 2002 plan) or because of Mr. Raymond's death or
resignation or by Mr. Raymond for good reason (as defined in the related
stock option agreement); or
. a change in control (as defined in our 2002 plan) of us.
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The remaining 200,000 SARs would continue to have a five-year term and will
vest in three equal annual installments which began on May 17, 2002. In
February 2002, Mr. Raymond was granted an option to purchase 175,000 shares of
Plains Resources common stock at an exercise price of $23.71 per share, which
vests over three equal annual installments beginning on the first anniversary
of the date of grant. This option will also "split" as discussed above and the
vesting terms will remain unchanged.
Under this employment agreement, Mr. Raymond will also be entitled to all
of the employee benefits, fringe benefits and perquisites provided by us to
other senior executives and will be reimbursed by us for monthly country club
fees.
Mr. Raymond's employment agreement provides that if his employment is
terminated by us without cause (as defined in the employment agreement), by Mr.
Raymond's death or disability, or by Mr. Raymond for good reason (as defined in
the employment agreement), we will pay him a lump sum amount equal to two times
the sum of his base salary and last earned annual bonus (or his target bonus if
the termination date occurs before a bonus amount has been determined for the
first calendar year of his employment). Also, Mr. Raymond and his dependents
will be entitled to continued health insurance benefits for a period of three
years made "whole" on a net after-tax basis and all of Mr. Raymond's
equity-based awards will become immediately exercisable and payable in full.
Under the employment agreement, if benefits to which Mr. Raymond becomes
entitled are considered "excess parachute payments" under Section 280G of the
Code, then Mr. Raymond will be entitled to an additional payment from us in an
amount equal to the excise tax imposed by Section 4999 of the Code or any
interest or penalties with respect to such excise tax (excluding any income tax
or employment tax imposed upon the additional payment).
Stephen A. Thorington. We entered into an employment agreement with Mr.
Thorington on August 20, 2002. Pursuant to this agreement, Mr. Thorington will
serve for an initial term of five years beginning on September 3, 2002. At the
end of the initial five-year term and, if such term is extended, each
subsequent term, the agreement is subject to a one-year extension if we and Mr.
Thorington agree to new compensation terms before the end of the applicable
term. Mr. Thorington's employment agreement provides for a base salary of
$300,000 per year and a target annual bonus of $300,000, subject to the
attainment of performance goals. In addition, pursuant to the employment
agreement, Mr. Thorington received a $350,000 signing bonus and has been
granted effective on the spin-off date SARs with respect to 300,000 shares of
our common stock at an exercise price equal to the closing price (on a
"when-issued" basis) of our common stock on the spin-off date as reported on
the NYSE. These SARs vest over three equal annual installments beginning on
September 3, 2003. We will also reimburse Mr. Thorington for initial and
monthly downtown luncheon club fees.
In addition, Mr. Thorington was granted by Plains Resources an award of
45,000 restricted shares of Plains Resources common stock, which will vest over
three equal annual installments beginning on September 3, 2003. These
restricted shares are issued and outstanding, and Mr. Thorington is entitled to
vote these shares and receive dividends paid on these shares, which dividends
will be held in custody by us and paid to Mr. Thorington as the restricted
shares vest. As a result, at the time of the spin-off, Mr. Thorington will
receive 45,000 restricted shares of our common stock pursuant to the spin-off,
but the shares will still be subject to the same vesting terms as his
restricted Plains Resources common stock. If the spin-off does not occur by May
22, 2003, then Mr. Thorington will become Executive Vice President and Chief
Financial Officer of Plains Resources, with the same terms of employment as
outlined in the employment agreement, except that his SARs will be replaced
with options covering the same number of shares of Plains Resources common
stock, with an exercise price equal to the closing price per share of Plains
Resources common stock on September 3, 2002.
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If Mr. Thorington's employment is terminated by us without cause, by Mr.
Thorington's death, or if a change of control (as defined in our 2002 plan)
occurs, we will pay him a lump sum amount equal to two times the sum of his
base salary and last earned annual bonus (or his target bonus if the
termination date occurs before the end of the first calendar year of his
employment). Also, Mr. Thorington will be entitled to health insurance benefits
for up to two years after termination, subject to mitigation if he becomes
entitled to health benefits under another plan, and his SARs will automatically
vest.
Timothy T. Stephens. On September 19, 2002 we entered into an employment
agreement with Mr. Stephens, which will not be effective until the spin-off
occurs. If the spin-off does not occur by May 23, 2003, the agreement will not
become effective. The agreement has an initial term of five years beginning on
its effective date. At the end of the initial five-year term and, if such term
is extended, each subsequent term, the agreement will be subject to a one-year
extension if we and Mr. Stephens agree to new compensation terms before the end
of the applicable term. Mr. Stephens will be entitled to a base salary of
$275,000 per year and a target annual bonus of $275,000, subject to the
attainment of performance goals. Also, Mr. Stephens has been granted an award
of 30,000 restricted shares of our common stock, which will vest over three
equal annual installments beginning on the first anniversary of the date of
grant, which will be the date of our spin-off. We will also reimburse Mr.
Stephens for initial and monthly downtown luncheon club fees.
As a result of Mr. Stephens' employment with Plains Resources, Mr. Stephens
received an option under the Plains Resources 2001 stock incentive plan to
purchase 250,000 shares of Plains Resources common stock at an exercise price
of $25.26 per share. In February 2002, Mr. Stephens was granted an option to
purchase 60,000 shares of Plains Resources common stock at an exercise price of
$23.71 per share. The Plains Resources board of directors has accelerated the
vesting of these options effective immediately before the spin-off. At the time
of the spin-off, pursuant to our employee matters agreement with Plains
Resources, these options will "split" such that Mr. Stephens will receive (1)
an option to purchase 310,000 shares of Plains Resources common stock and (2)
SARs with respect to 310,000 shares of our common stock all of which will be
fully vested. The exercise prices of his existing Plains Resources stock
options will also be "split" between the new Plains Resources option and the
SARs based on the following relative amounts: the closing price (with dividend)
of Plains Resources common stock on the spin-off date less the closing price
(on a "when-issued" basis) of our common stock on the spin-off date, both as
reported on the NYSE, and such closing price of our common stock.
If Mr. Stephens' employment is terminated by us without cause, by Mr.
Stephens' death, or if a change of control (as defined in our 2002 plan)
occurs, we will pay him a lump sum amount equal to two times the sum of his
base salary and last earned annual bonus (or his target bonus if the
termination date occurs before the end of the first calendar year of his
employment). Also, Mr. Stephens will be entitled to health insurance benefits
for up to two years after termination, subject to mitigation if he becomes
entitled to health benefits under another plans, and all of his equity-based
awards will become fully exercisable.
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Other. In the event of certain corporate transactions, changes in control
of us, or changes in the composition of our board of directors under certain
circumstances, all options, SARs, and restricted stock awards granted to our
executive officers will become exercisable on an accelerated schedule pursuant
to our 2002 plan, rollover plan and transition plan. To the extent not already
exercisable, these options, SARs, and restricted stock awards generally will
become fully exercisable upon a change of control of us resulting from:
. a change in the composition of our board of directors pursuant to which
incumbent directors or their designated successors cease to constitute at
least two-thirds of our board;
. subject to certain exceptions, the acquisition of securities by a person
after which that person beneficially owns 50% or more of the voting power
of our outstanding stock; or
. subject to certain exceptions, approval by our stockholders of a merger,
consolidation or reorganization involving us, a complete liquidation or
dissolution of us, or an agreement for the sale of all or substantially
all of our assets.
The spin-off will not be a change of control under our 2002 plan, rollover
plan or transition plan.
PRINCIPAL STOCKHOLDER
As of the date of this prospectus, 100% of our outstanding equity interest
is owned directly by Plains Resources.
Plains Resources currently intends to spin us off to its stockholders and
has obtained an IRS private letter ruling that would allow the spin-off to
occur, for United States federal income tax purposes, as a generally tax-free
transaction subject to compliance with the terms of the private letter ruling.
To benefit from the private letter ruling, the spin-off would need to occur
within twelve months of the date of the ruling, or by May 21, 2003. The
spin-off is subject to many factors, and we cannot provide any assurance that
the spin-off will occur.
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CERTAIN TRANSACTIONS
Our Relationship With PAA
Plains Resources owns approximately 25% of PAA, including 44% of the
general partner of PAA. We are party to the following agreements with PAA and
Plains Resources:
. an omnibus agreement that provides (1) that we cannot engage in oil
storage, terminalling, gathering, marketing or transportation activities
in any state in the continental United States for any person other than
us and (2) for the resolution of certain conflicts arising from our
engaging in these activities, or with respect to marketing, at all.
. a marketing agreement that provides that PAA will purchase all of our
equity oil production at market prices for a fee of $0.20 per Bbl. For
the purchase of oil under the agreement, including the royalty share of
production, in 2001, 2000 and 1999 PAA paid $202.1 million, $222.7
million and $114.6 million, respectively; and
. a letter agreement that provides that, if our marketing agreement with
PAA terminates before the termination of PAA's oil sales agreement with
Tosco Refining Co. pursuant to which PAA sells to Tosco all of the oil
from our Arroyo Grande property it purchases from us, PAA will continue
to purchase our equity production from our Arroyo Grande property under
the same terms as our marketing agreement with PAA until the Tosco
agreement terminates.
Master Separation Agreement
Overview. To effect our separation from Plains Resources, we entered into a
master separation agreement on July 3, 2002 with Plains Resources simultaneous
with entering into our financing. The master separation agreement provides for
the separation of substantially all of the upstream assets and liabilities of
Plains Resources, other than its Florida operations. The master separation
agreement provides for, among other things:
. the separation;
. an initial public offering;
. the spin-off;
. corporate governance provisions related to us;
. cross-indemnification provisions;
. allocation of fees related to these transactions between us and Plains
Resources;
. other provisions governing our relationship with Plains Resources,
including mandatory dispute arbitration, sharing information,
confidentiality and other covenants;
. a noncompetition provision; and
. us entering into the ancillary agreements discussed below with Plains
Resources.
Separation. To effect the separation, on July 3, 2002, Plains Resources
transferred to us assets and liabilities related to Plains Resources' upstream
business other than its Florida operations, including the capital stock of
Arguello Inc., Plains Illinois Inc., PMCT, Inc. and Plains Resources
International Inc., miscellaneous upstream assets and related hedging
agreements. We assumed the liabilities associated with the transferred assets
and businesses. At a future date before the spin-off, Plains Resources will
transfer to us additional assets and liabilities, including remaining upstream
agreements and permits that require consent to transfer and office furniture
and equipment, and we will sublease a portion of Plains Resources' office
space. Except as set forth in the master separation
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agreement, no party is making any representation or warranty as to the assets
or liabilities transferred as a part of the separation, and all assets are
being transferred on an "as is, where is" basis.
Plains Resources has agreed to take such further actions as we may
reasonably request to more effectively complete the transfers of assets and
liabilities described above, to protect and enjoy all rights and benefits
Plains Resources had with respect thereto and as otherwise appropriate to carry
out the transactions contemplated by the master separation agreement.
Reorganization. The master separation agreement provides for an internal
reorganization within Plains Resources, including:
. our conversion into a Delaware corporation; and
. before the spin-off, the merger of Stocker Resources, Inc. (our general
partner before we converted from a limited partnership to a corporation)
into Plains Resources.
Spin-off. The master separation agreement provides for the spin-off
distribution by Plains Resources of our common stock held by it. Plains
Resources is not obligated to effect the spin-off. If Plains Resources decides
to effect the spin-off, each holder of Plains Resources common stock on the
record date would receive a pro rata share of the total shares of our common
stock held by Plains Resources.
Corporate governance. The master separation agreement contains several
provisions regarding our corporate governance. First, as long as Plains
Resources owns shares representing at least a majority of our voting power,
Plains Resources will have the right to designate for nomination by our board
of directors, or a nominating committee of the board, a majority of the members
of our board. If Plains Resources' beneficial ownership of our common stock is
reduced to a level below 50% of our voting power but is at least 20% of our
voting power, Plains Resources will have the right to designate for nomination
a number of directors proportionate to its voting power.
Indemnification. The master separation agreement provides for
cross-indemnities intended to place sole financial responsibility on us for all
liabilities associated with the current and historical businesses and
operations we conduct after giving effect to the separation, regardless of the
time those liabilities arise, and to place sole financial responsibility for
liabilities associated with Plains Resources' other businesses with Plains
Resources and its other subsidiaries. The master separation agreement also
contains indemnification provisions under which we and Plains Resources each
indemnify the other with respect to breaches by the indemnifying party of the
master separation agreement or any of the ancillary agreements described below.
We agree to indemnify Plains Resources and its other subsidiaries against
liabilities arising from misstatements or omissions in the various offering
documents for this offering or the spin-off including related prospecti or in
documents to be filed with the SEC in connection therewith, except for
information regarding Plains Resources provided by Plains Resources for
inclusion in such documents. Plains Resources agrees to indemnify us against
liabilities arising from misstatements or omissions in the various offering
documents for this offering or the spin-off, including related prospecti or in
documents to be filed with the SEC in connection therewith if such information
was provided by Plains Resources.
The master separation agreement contains a general release under which we
will release Plains Resources and its subsidiaries, affiliates, successors and
assigns, and Plains Resources will release us from any liabilities arising from
events between us on the one hand, and Plains Resources or its subsidiaries on
the other hand, occurring on or before the separation, including events in
connection with activities to implement the separation, this offering and the
spin-off. The general release does not apply to obligations under the master
separation agreement or any ancillary agreement, to liabilities transferred to
us, to future transactions between us and Plains Resources, or to specified
contractual arrangements.
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Fees. We will bear all out-of-pocket costs of the transfers of assets and
liabilities in connection with the separation, including costs for providing
notices of the transfers, costs for transferring licenses, permits or
franchises or for issuing new licenses, permits or franchises in our name, fees
or costs for the assignment or transfer of any agreements or contracts, and any
recording or other fees, taxes or charges incurred in connection with
transferring real property.
Except as noted above or otherwise specifically addressed in the master
separation agreement or an ancillary agreement, we shall bear the out-of-pocket
costs associated with preparing and consummating the transactions contemplated
by the master separation agreement, the ancillary agreements, the separation,
this offering and the spin-off.
Other provisions. The master separation agreement also provides for: (1)
mandatory arbitration to settle disputes between us and Plains Resources and
its subsidiaries; (2) exchange of information between Plains Resources and us
for purposes of conducting our operations, meeting regulatory requirements,
responding to regulatory or judicial proceedings, meeting SEC filing
requirements, and other reasons; (3) coordination of the conduct of our annual
audits and quarterly reviews so that we may both file our annual and quarterly
reports in a timely manner; (4) preservation of legal privileges and (5)
maintaining confidentiality of each other's information.
In addition, we and Plains Resources agree to use reasonable efforts to
amend the omnibus agreement with PAA to terminate the noncompetition provisions
therein and to enter into a new oil marketing agreement with PAA so that the
agreement only applies to us and to add a definite term to the agreement, and
other amendments.
Non-competition. The master separation agreement provides that for a
period of three years, (1) Plains Resources and its subsidiaries will be
prohibited from engaging in or acquiring any business engaged in any of the
"upstream" activities of acquiring, exploiting, developing, exploring for and
producing oil and gas in any state in the United States (except Florida), and
(2) we will be prohibited from engaging in any of the "midstream" activities of
marketing, gathering, transporting, terminalling and storing oil and gas
(except to the extent any such activities are ancillary to, or in support of,
any of our upstream activities.)
Ancillary agreements. The master separation agreement sets forth the
related agreements that we will enter into with Plains Resources, including:
. employee matters agreement;
. tax allocation agreement;
. intellectual property agreement;
. Plains Exploration & Production transition services agreement;
. Plains Resources transition services agreement; and
. technical services agreement.
Employee Matters Agreement
We entered into the employee matters agreement with Plains Resources. The
employee matters agreement does not address the treatment of Messrs. Flores,
Raymond and Stephens, whom we call the executives, except with respect to the
treatment of their existing options to acquire Plains Resources common stock.
Other employees. The employee matters agreement provides that those
employees who will work for us after the spin-off will be transferred to us
immediately before the spin-off. Neither their
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transfer nor the spin-off will be treated as a termination of their employment
for purposes of any benefits under any plans.
Stock options and restricted stock awards. Under the employee matters
agreement, as a result of the spin-off, all outstanding options to acquire
Plains Resources common stock at the time of the spin-off would be "split" into
(1) an equal number of options to acquire Plains Resources common stock and (2)
an equal number of stock appreciation rights, or SARs, with respect to our
common stock.
The exercise price for the original Plains Resources stock options would
also be "split" between the new Plains Resources stock options and the SARs
based on the following relative amounts: the closing price (with dividend) of
Plains Resources common stock on the spin-off date less the closing price (on a
"when-issued" basis) of our common stock on the spin-off date, both as reported
on the NYSE, and such closing price of our common stock.
Also, unless otherwise provided for in the agreement governing the
restricted stock award, at the time of the spin-off all restricted stock awards
for Plains Resources common stock would be "split" into (1) restricted stock
awards for an equal number of shares of Plains Resources common stock and
(2) restricted stock awards for an equal number of shares of our common stock.
All recipients of our SARs and restricted stock awards would receive the
benefit of prior service credit at Plains Resources and would have the same
amount of vesting as they had under their related Plains Resources stock
options and restricted stock awards, and vesting terms would remain unchanged.
Also, an employee's or a director's service with us would count towards the
vesting of their "split" Plains Resources stock options and restricted stock
awards even though the employee is no longer employed by Plains Resources or
the director no longer serves at Plains Resources. Likewise, with respect to
employees and directors who stay with Plains Resources, their service at Plains
Resources will count towards the vesting of their SARs even though they are not
employed by us or do not serve on our board of directors.
Unless a person is employed by or serves as a director for both Plains
Resources and us, termination of employment or service as a director for any
reason at either company will count as termination for the same reason at the
other company for purposes of vesting and termination of options, SARs, and
restricted stock awards. If a person is employed by or serves as a director for
both Plains Resources and us, termination for any reason at one company will
not count as termination at the other company.
Other plans. The employee matters agreement provides that (1) before the
spin-off, we will establish a nonqualified deferred compensation plan for
certain executive officers and, to the extent that any of the executives are
participants in the Plains Resources deferred compensation plan, the related
assets and liabilities under the Plains Resources plan would be transferred to
our plan, (2) on or before the spin-off, Plains Resources would transfer its
401(k) plan and welfare benefit plans to us and would form a similar 401(k)
plan and similar welfare benefit plans, and (3) at the time of the spin-off, we
will establish plans that mirror the fringe benefits and company policies of
Plains Resources.
Other. Under the employee matters agreement, Plains Resources would retain
liability for all incurred but not reported claims occurring before the
spin-off, and we will be liable for all claims incurred on or after the
spin-off related to our employees.
Tax Allocation Agreement
On July 3, 2002, we entered into the tax allocation agreement, which we and
Plains Resources amended and restated on November 20, 2002. This agreement
provides that, until the spin-off, we will
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continue to be included in Plains Resources' consolidated federal income tax
group, and our federal income tax liability will be included in the
consolidated federal income tax liability of Plains Resources. The amount of
taxes that we will pay or receive with respect to consolidated or combined
returns of Plains Resources in which we are included generally will be
determined by multiplying our net taxable income included in the Plains
Resources consolidated tax return by the highest marginal tax rate applicable
to the income. Plains Resources will not be required to pay us for the use of
our tax attributes that come into existence before the spin-off until such time
as we would otherwise be able to utilize such attributes.
Under the agreement, until the spin-off, Plains Resources will:
. continue to have all the rights of a parent of a consolidated group;
. have sole and exclusive responsibility for the preparation and filing of
consolidated federal and consolidated or combined state, local and
foreign income tax returns (or amended returns) although we may be
required to assist in certain circumstances; and
. have the power, in its sole discretion, to contest or compromise any
asserted tax adjustment or deficiency and to file, litigate or compromise
any claim for refund relating to these returns; provided, that (1) with
the consent of Plains Resources, we may participate in any proceedings
contesting any proposed adjustment related to our activities and (2)
Plains Resources will not accept or offer any settlement of issues
related to our tax liabilities without our consent, which will not be
unreasonably withheld.
If Plains Resources decides not to contest a proposed adjustment relating
to our activities, we may at our expense contest the adjustment, but we may not
settle or compromise any issues related to the tax liabilities of Plains
Resources.
In general, the agreement provides that we will be included in Plains
Resources' consolidated group for federal income tax purposes until the time of
the spin-off. Each member of a consolidated group is jointly and severally
liable for the federal income tax liability of each other member of the
consolidated group. Accordingly, although this agreement allocates tax
liabilities between us and Plains Resources during the period in which we are
included in Plains Resources' consolidated group, we could be liable if any
federal tax liability is incurred, but not discharged, by any other member of
Plains Resources' consolidated group. In addition, to the extent Plains
Resources' net operating losses are used in the consolidated return to offset
our taxable income from operations during the period January 1, 2002 through
the spin-off, we will reimburse Plains Resources for the reduction in our
federal income tax liability resulting from the utilization of such net
operating losses, but such reimbursement shall not exceed $3 million exclusive
of any interest accruing under the agreement.
Under the terms of this agreement, we agree to indemnify Plains Resources
if the spin-off is not tax-free to Plains Resources as a result of various
actions taken by us or with respect to our failure to take various actions.
In addition, we will agree that, during the three-year period following the
spin-off, without the prior written consent of Plains Resources, we will not
engage in transactions that could adversely affect the tax treatment of the
spin-off unless we obtain a supplemental tax ruling from the IRS or a tax
opinion acceptable to Plains Resources of nationally recognized tax counsel to
the effect that the proposed transaction would not adversely affect the tax
treatment of the spin-off or provide adequate economic security to Plains
Resources to ensure we would be able to comply with our obligation under this
agreement. We may not be able to control some of these events that could
trigger this indemnification obligation.
We also agree to be liable for transfer taxes associated with the transfer
of assets and liabilities in connection with the separation and the spin-off.
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Intellectual Property Agreement
On July 3, 2002 we entered into the intellectual property agreement, which
provides that Plains Resources will transfer to us ownership and all rights
associated with certain trade names, trademarks, service marks and associated
goodwill, including Arguello, Plains, Plains Energy, Plains E&P, Plains
Exploration & Production, Plains Illinois, Plains Petroleum, Plains Resources,
Plains Resources International, PLX, PMCT, Stocker Resources and the Plains
logo. In addition, we will grant to Plains Resources a full license to use
certain trade names including Plains Energy and Plains Resources, referred to
as the Plains Marks, subject to certain limitations. These licenses are not
transferable or assignable without our written consent, except that Plains
Resources may grant its subsidiaries sublicenses to use the Plains Marks.
Plains Resources will not attempt to register a trade name or trademark
that incorporates or is confusingly similar to the Plains Marks. Also, if
Plains Resources develops new trademarks using the name "Plains," it must first
obtain our written approval. We will own such new trademarks and they will be
considered subject to the terms of this agreement.
The intellectual property agreement provides that Plains Resources will
conform the nature and quality of its products and services offered in
connection with the Plains Marks to our reasonable design and quality
standards. Further, Plains Resources will use the Plains Marks only in
connection with its business.
Plains Exploration & Production Transition Services Agreement
On July 3, 2002 we entered into the Plains Exploration & Production
transition services agreement, which provides that Plains Resources will
provide us the following services, on an interim basis:
. management services, including managing our operations, evaluating
investment opportunities for us, overseeing our upstream activities, and
staffing;
. tax services, including preparing tax returns and preparing financial
statement disclosures;
. accounting services, including maintaining general ledgers, preparing
financial statements and working with our auditors;
. payroll services, including payment processing and complying with
regulations relating to payroll services;
. insurance services, including maintaining for the interim period the
existing insurance that Plains Resources provides for us;
. employee benefits services, including administering and maintaining the
employee benefit plans that cover our employees;
. legal services, including typical and customary legal services; and
. financial services, including helping us raise capital, preparing budgets
and executing hedges.
Plains Resources will charge us its costs of providing such services
monthly but that charge may not exceed $30.0 million in the aggregate during
the term of the agreement.
In addition, we and Plains Resources may identify additional services that
Plains Resources will provide to us under this agreement in the future. The
terms and costs of these additional services will be mutually agreed upon by us
and Plains Resources. Plains Resources may allow one of its subsidiaries or a
qualified third party to provide the services under this agreement, but Plains
Resources will be responsible for the performance of the services. To the
extent that Plains Resources
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personnel who traditionally have provided services contemplated by the
transition services agreement have been or are transferred to a similar
position with us, Plains Resources will be relieved of its obligations to
provide such services to us.
Plains Resources will be obligated to provide the services with
substantially the same degree of care as it employs for its own operations.
Plains Resources may change the manner in which it provides the services so
long as it deems such change to be necessary or desirable for its own
operations.
This transition services agreement provides that Plains Resources will not
be liable to us with respect to the performance of the services, except in the
case of gross negligence or willful misconduct in providing the services.
Plains Resources will indemnify us for any liabilities arising from such gross
negligence or misconduct. We will indemnify Plains Resources for any
liabilities arising directly from the performance of the services by Plains
Resources, except for liabilities caused by gross negligence or willful
misconduct of Plains Resources. Plains Resources will disclaim all warranties
and makes no representations as to the quality, suitability or adequacy of the
services provided.
Plains Resources will provide the services until the spin-off, unless we
and Plains Resources decide to terminate the agreement earlier. We and Plains
Resources may agree to extend this agreement to up to 180 days following the
spin-off and thereafter for a period as mutually agreed.
Plains Resources Transition Services Agreement
On July 3, 2002 we entered into the Plains Resources transition services
agreement, under which we will provide Plains Resources the following services
on an interim basis beginning on a date to be determined by both us and Plains
Resources upon the transfer by Plains Resources of substantially all of its
employees to us:
. tax services, including preparing tax returns and preparing financial
statement disclosures;
. accounting services, including maintaining general ledgers, preparing
financial statements and working with Plains Resources auditors;
. payroll services, including payment processing and complying with
regulations relating to payroll services;
. employee benefits services, including administering and maintaining the
employee benefit plans that cover Plains Resources' employees;
. legal services, including typical and customary legal services; and
. financial services, including helping Plains Resources raise capital,
preparing budgets and executing hedges.
The services provided by us under the Plains Resources transition services
agreement and the services provided by Plains Resources under the Plains
Exploration & Production transition services agreement are substantially
similar, except that:
. the Plains Resources transition services agreement will not become
effective unless and until the spin-off occurs;
. the Plains Resources transition services agreement does not cover
management services, insurance services or operational services;
. the tax services provided under the Plains Resources transition services
agreement are not subject to the tax allocation agreement discussed on
pages 90-91; and
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. the legal services provided under the Plains Exploration & Production
transition services agreement include legal services that have been
historically provided for it and its subsidiaries by Plains Resources.
We will charge Plains Resources on a monthly basis our costs of providing
such services.
In addition, we and Plains Resources may identify additional services that
we will provide to Plains Resources under this agreement in the future. The
terms and costs of these additional services will be mutually agreed upon by us
and Plains Resources. We may allow one of our subsidiaries or a qualified third
party to provide the services under this agreement, but we will be responsible
for the performance of the services.
We will be obligated to provide the services with substantially the same
degree of care as we employ for our own operations. We may change the manner in
which we provide the services so long as we deem such change to be necessary or
desirable for our own operations.
This transition services agreement provides that we will not be liable to
Plains Resources with respect to the performance of the services, except in the
case of gross negligence or willful misconduct in providing the services. We
will indemnify Plains Resources for any liabilities arising from such gross
negligence or misconduct. Plains Resources will indemnify us for any
liabilities arising directly from our performance of the services, except for
liabilities caused by our gross negligence or willful misconduct. We will
disclaim all warranties and make no representations as to the quality,
suitability or adequacy of the services provided.
We will provide the services for 180 days, unless we and Plains Resources
decide to terminate the agreement earlier. We and Plains Resources may agree to
extend this agreement beyond the 180 day period if necessary or desirable.
Technical Services Agreement
On July 3, 2002 we entered into the technical services agreement, which
provides that, beginning on a date to be determined by us and Plains Resources,
we will provide Calumet Florida certain engineering and technical support
services required to support operation and maintenance of the oil and gas
properties owned by Calumet, including geological, geophysical, surveying,
drilling and operations services, environmental and other governmental or
regulatory compliance related to oil and gas activities and other oil and gas
engineering services as requested, and accounting services.
Plains Resources will reimburse us for our costs to produce these services.
In addition, we and Plains Resources may identify additional services that
we will provide to Plains Resources under this agreement in the future. The
terms and costs of these additional services will be mutually agreed upon by us
and Plains Resources. We may allow one of our subsidiaries or a qualified third
party to provide the services under this agreement, but we will be responsible
for the performance of the services.
We and Plains Resources may agree to specific performance metrics that we
must meet. Where no metrics are provided, we will (1) perform the services in
accordance with the policies and procedures in effect before this agreement,
(2) exercise the same care and skill as we exercise in performing similar
services for our subsidiaries, and (3) in cases where there is common
personnel, equipment or facilities for services provided to our subsidiaries
and Plains Resources, not favor Plains Resources or our subsidiaries over the
other. We may change the manner in which we provide the services so long as we
are making similar changes to the services we are providing to our
subsidiaries. We are not obligated to provide any service to the extent it is
impracticable as a result of causes outside of our control.
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The technical services agreement provides that we will not be liable to
Plains Resources or Calumet with respect to the performance of the services,
except in the case of gross negligence or willful misconduct in providing the
services. We will indemnify Plains Resources and Calumet for any liabilities
arising from such gross negligence or misconduct. Plains Resources will
indemnify us for any liabilities arising directly from the performance of the
services, except for liabilities caused by our gross negligence or willful
misconduct. We disclaim all warranties and make no representations as to the
quality, suitability or adequacy of the services provided.
We will provide the services until (1) Calumet is no longer a subsidiary of
Plains Resources, (2) Calumet transfers substantially all of its assets to a
person that is not a subsidiary of Plains Resources, (3) the third anniversary
of the date of this agreement or (4) when all the services are terminated as
provided in the agreement. Plains Resources may terminate the agreement as to
some or all of the services at any time by giving us at least 90 days' written
notice.
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DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS
On July 3, 2002, we entered into a $300.0 million revolving credit facility
with JPMorgan Chase Bank as sole administrative agent. As of September 30, 2002
we had $90.7 million outstanding under the credit facility. The credit facility
provides for an initial borrowing base of $225.0 million that will be reviewed
every six months, with the lenders and us each having the right to one annual
interim unscheduled redetermination, and adjusted based on our oil and gas
properties, reserves, other indebtedness and other relevant factors, and
matures in 2005. Additionally, the credit facility contains a $30.0 million
sub-limit on letters of credit (of which $5.2 million had been issued as of
September 30, 2002). Amounts borrowed under this credit facility bear an annual
interest rate, at our election, equal to either:
. the Eurodollar rate, plus from 1.375% to 1.75%; or
. the greatest of (1) the prime rate, as determined by JPMorgan Chase Bank,
(2) the certificate of deposit rate, plus 1.0%, or (3) the federal funds
rate, plus 0.5%; plus an additional 0.125% to 0.5% for each of (1)-(3).
The amount of interest payable on outstanding borrowings is based on (1)
the utilization rate as a percentage of the total amount of funds borrowed
under the credit facility to the borrowing base and (2) our long-term debt
rating. Commitment fees and letter of credit fees under the credit facility are
based on our utilization rate and long-term debt rating. Commitment fees range
from 0.375% to 0.5% of the unused portion of the borrowing base. Letter of
credit fees range from 1.375% to 1.75%. The issuer of any letter of credit
receives an issuing fee of 0.125% of the undrawn amount. Our domestic
subsidiaries unconditionally guarantee our payment of borrowings under the
credit facility. Additionally, to secure our borrowing, we pledged 100% of the
shares of stock of our domestic subsidiaries and gave mortgages covering 80% of
the total present value of our domestic oil and gas properties. The credit
facility contains negative covenants that limit our ability as well as the
ability of our subsidiaries, among other things, to:
. incur additional debt;
. pay dividends on stock;
. make distributions of cash or property;
. change the nature of our business or operations;
. redeem stock or redeem subordinated debt;
. make investments;
. create liens;
. enter into leases;
. sell assets;
. sell capital stock of subsidiaries;
. create subsidiaries;
. guarantee other indebtedness;
. enter into agreements that restrict dividends from subsidiaries;
. enter into certain types of swap agreements;
. enter into gas imbalance or take-or-pay arrangements;
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. merge or consolidate; and
. enter into transactions with affiliates.
In addition, the credit facility requires us to maintain:
. a current ratio (which includes availability) of at least 1.0 to 1.0; and
. a ratio of total debt to earnings before interest, depreciation,
depletion, amortization, exploration expenses and income taxes of no more
than 4.5 to 1.0.
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DESCRIPTION OF NOTES
On July 3, 2002 the Issuers issued the Series A notes as joint and several
obligors under the Indenture (the "Indenture") among the Issuers, the
Subsidiary Guarantors and JPMorgan Chase Bank, as trustee (the "Trustee"). The
Series B notes (for this "Description of Notes", the "Notes") will be issued
under the same indenture. The terms of the Notes include those expressly set
forth in the Indenture and those made part of the Indenture by reference to the
Trust Indenture Act of 1939, as amended (the "Trust Indenture Act").
This description of Notes is intended to be a useful overview of the
material provisions of the Notes and the Indenture. Since this description of
notes is only a summary, you should refer to the Indenture for a complete
description of the obligations of the Issuers and your rights.
The section entitled "Certain Definitions" includes the definitions of the
capitalized terms used in this description. References to the "Company" mean
only Plains Exploration & Production Company and not its subsidiaries and
references to the "Issuers" mean collectively Plains Exploration & Production
Company and Plains E&P Company.
General
The Series A notes and the Series B notes will constitute a single class of
debt securities under the Indenture. If the exchange offer is completed,
holders of Series A notes who do not exchange their Series A notes for Series B
notes will vote together with holders of the Series B notes for all relevant
purposes under the Indenture. In that regard, the Indenture requires that
certain actions by holders, including acceleration following an event of
default, must be taken, and certain rights must be exercised, by specified
minimum percentages of the aggregate principal amount of the outstanding
securities issued under the Indenture. In determining whether the required
holders have given any notice, consent or waiver or taken any other action
permitted under the Indenture, any Series A notes that remain outstanding after
the exchange offer will be aggregated with the Series B notes, and the holders
of the Series A notes and the Series B notes will vote together as a single
series. All references in this prospectus to specified percentages in aggregate
principal amount of the Notes means, at any time after the exchange offer is
completed, the percentages in aggregate principal amount of the Series A notes
and the Series B notes collectively then outstanding.
The Notes
The Notes:
. are general unsecured, senior subordinated obligations of the Issuers;
. are initially limited to an aggregate principal amount of $200.0 million
(the "Initial Notes"), but subject to compliance with the covenant
described in "Limitation On Indebtedness," additional notes may be issued
without limitation as to aggregate principal amount (the "Additional
Notes");
. mature on July 1, 2012;
. will be issued in denominations of $1,000 and integral multiples of
$1,000;
. will be represented by one or more registered Notes in global form, but
in certain circumstances may be represented by Notes in definitive form;
. are subordinated in right of payment to all existing and future Senior
Indebtedness of the Issuers; and
. rank equally in right of payment to all existing and future Senior
Subordinated Indebtedness of the Issuers.
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Interest
Interest on the Notes will compound semi-annually and will:
. accrue at the rate of 8 3/4% per annum;
. accrue from the date of issuance or the most recent interest payment date;
. be payable in cash semi-annually in arrears on January 1 and July 1,
commencing on January 1, 2003;
. be payable to the holders of record on the December 15 and June 15
immediately preceding the related interest payment dates; and
. be computed on the basis of a 360-day year comprised of twelve 30-day
months.
Payments on the Notes; Paying Agent and Registrar
Principal of, premium, if any, and interest on the Notes will be payable,
and the Notes may be exchanged or transferred, at the office or agency of the
Issuers in the Borough of Manhattan, The City of New York (which initially will
be the corporate trust office of the Trustee in New York, New York), except
that, at the option of the Issuers, payment of interest may be made by check
mailed to the address of the holders as such address appears in the Note
Register. Payment of principal of, premium, if any, and interest on, Notes in
global form registered in the name of or held by the Depositary or its nominee
will be made in immediately available funds to the Depositary or its nominee,
as the case may be, as the registered holder of such global Note. No service
charge will be made for any registration of transfer or exchange of Notes, but
the Issuers may require payment of a sum sufficient to cover any transfer tax
or other similar governmental charge payable in connection therewith.
The Trustee will initially act as Paying Agent and Registrar. The Issuers
may change the Paying Agent or Registrar without prior notice to the holders of
the Notes, and the Issuers or any of the Restricted Subsidiaries may act as
Paying Agent or Registrar.
Transfer and Exchange
A holder may 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 Issuers may
require a holder to pay any taxes and fees required by law or permitted by the
Indenture. The Issuers are not required to transfer or exchange any Note
selected for redemption. Also, the Issuers are not required to transfer or
exchange any Note for a period of 15 days before a selection of Notes to be
redeemed.
The registered holder of a Note will be treated as the owner of it for all
purposes.
Subordination
The payment of the principal of, premium, if any, and interest on the Notes
and any other payment obligations in respect of the Notes (including any
obligation to repurchase the Notes) will be subordinated to the prior payment
in full in cash or Cash Equivalents when due of all Senior Indebtedness of the
Issuers. However, payment from the money or the proceeds of U.S. Government
Obligations held in any defeasance trust (as described under "Defeasance"
below) is and will not be subordinated to any Senior Indebtedness or subject to
these restrictions.
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As a result of the subordination provisions described below, holders of the
Notes may recover less than creditors of the Issuers who are holders of Senior
Indebtedness in the event of an insolvency, bankruptcy, reorganization,
receivership or similar proceedings relating to the Issuers. Moreover, the
Notes will be structurally subordinated to the liabilities of the Subsidiaries
of the Issuers other than the Subsidiary Guarantors. See "--Senior Subordinated
Guarantees of Notes." On a pro forma basis:
. on September 30, 2002, outstanding Senior Indebtedness would have been
$91.7 million, $90.7 million of which would have been secured;
. on September 30, 2002, the Issuers would have had no Senior Subordinated
Indebtedness other than the Notes;
. on September 30, 2002, the issuers would have had no subordinated
indebtedness; and
. on September 30, 2002, Restricted Subsidiaries would have had $19.8
million of total liabilities (excluding guarantees of the Notes and
amounts borrowed under the Senior Credit Agreement):
Although the Indenture will limit the amount of indebtedness that the
Issuers and the Restricted Subsidiaries may incur, such indebtedness of the
Issuers may be substantial and all of it may be Senior Indebtedness.
Only Indebtedness of the Issuers that is Senior Indebtedness will rank
senior to the Notes in accordance with the provisions of the Indenture. The
Notes will in all respects rank equally with all other Senior Subordinated
Indebtedness of the Issuers. As described in "Limitation on layering," the
Issuers may not incur any indebtedness that is senior in right of payment to
the Notes, but junior in right of payment to Senior Indebtedness. Unsecured
Indebtedness of the Issuers is not deemed to be subordinate or junior to
secured Indebtedness merely because it is unsecured.
The Issuers may not pay principal of, premium, if any, or interest on, or
other payment obligations in respect of, the Notes or make any deposit pursuant
to the provisions described under "Defeasance" below and may not otherwise
purchase, redeem or retire any Notes (collectively, "pay the Notes") if:
(1) any Senior Indebtedness is not paid when due in cash or Cash
Equivalents; or
(2) any other default on Senior Indebtedness occurs and the maturity of
such Senior Indebtedness is accelerated in accordance with its terms
unless, in either case, the default has been cured or waived and any
such acceleration has been rescinded or such Senior Indebtedness has
been paid in full in cash or Cash Equivalents.
However, the Issuers may pay the Notes if the Issuers and the Trustee
receive written notice approving such payment from the Representative of the
Senior Indebtedness with respect to which either of the events set forth in
clause (1) or (2) of the immediately preceding sentence has occurred and is
continuing.
The Issuers also will not be permitted to pay the Notes for a Payment
Blockage Period (as defined below) during the continuance of any default (a
"Non-Payment Default"), other than a default described in clause (1) or (2) of
the preceding paragraph, on any Designated Senior Indebtedness that permits the
holders of the Designated Senior Indebtedness to accelerate its maturity
immediately without either further notice (except such notice as may be
required to effect such acceleration) or the expiration of any applicable grace
periods.
A "Payment Blockage Period" commences on the receipt by the Trustee (with a
copy to the Issuers) of written notice (a "Blockage Notice") of a default of
the kind described in the immediately preceding paragraph from the
Representative of the holders of such Designated Senior Indebtedness specifying
an election to effect a Payment Blockage Period and ends 179 days thereafter.
The Payment Blockage Period will end earlier if such Payment Blockage Period is
terminated:
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(1) by written notice to the Trustee and the Issuers from the Person or
Persons who gave such Blockage Notice;
(2) because the default giving rise to such Blockage Notice is no longer
continuing; or
(3) because such Designated Senior Indebtedness has been repaid in full in
cash or Cash Equivalents.
The Issuers may resume payments on the Notes after the end of the Payment
Blockage Period, unless the holders of such Designated Senior Indebtedness or
the Representative of such holders have accelerated the maturity of such
Designated Senior Indebtedness. Not more than one Blockage Notice may be given
in any consecutive 360-day period, irrespective of the number of defaults with
respect to Designated Senior Indebtedness during such period. No Non-Payment
Default that existed or was continuing on the date of delivery of any Payment
Blockage Period Notice to the Trustee will be, or can be, made the basis for
the commencement of a subsequent Payment Blockage Period.
In the event of:
(1) a total or partial liquidation or a dissolution of the Company or
Plains E&P Company (until the Company is converted into a corporation);
(2) a reorganization, bankruptcy, insolvency, receivership of or similar
proceeding relating to either Issuer or its property; or
(3) an assignment for the benefit of creditors or marshaling of either
Issuer's assets and liabilities, then
the holders of Senior Indebtedness will be entitled to receive payment in full
in cash or Cash Equivalents in respect of such Senior Indebtedness (including
interest accruing after, or which would accrue but for, the commencement of any
proceeding at the rate specified in the applicable Senior Indebtedness, whether
or not a claim for such interest would be allowed) before the holders of the
Notes will be entitled to receive any payment or distribution other than Junior
Securities, in the event of any payment or distribution of the assets or
securities of the Issuers. In addition, until the Senior Indebtedness is paid
in full in cash or Cash Equivalents, any payment or distribution to which
holders of the Notes would be entitled but for the subordination provisions of
the Indenture will be made to holders of the Senior Indebtedness as their
interests may appear. If a payment or distribution is made to holders of the
Notes that, due to the subordination provisions, should not have been made to
them, such holders are required to hold it in trust for the holders of Senior
Indebtedness and pay it over to them as their interests may appear.
If payment of the Notes is accelerated because of an Event of Default, the
Issuers or the Trustee will promptly notify the holders of the Designated
Senior Indebtedness or the Representative of such holders of the acceleration.
The Issuers may not pay the Notes until five Business Days after such holders
or the Representative of the Designated Senior Indebtedness receives notice of
such acceleration and, after that five Business Day period, may pay the Notes
only if the subordination provisions of the Indenture otherwise permit payment
at that time.
Senior Subordinated Guarantees of Notes
Initially, Arguello Inc., Plains Illinois Inc., PMCT Inc. and Plains
Resources International Inc. will be the only Subsidiary Guarantors; however,
other Restricted Subsidiaries may in the future incur Subsidiary Guarantees of
the Notes as described in this Description of Notes. Each Subsidiary Guarantor
will unconditionally guarantee, jointly and severally, to each holder of Notes
and the Trustee the full and prompt performance of the Issuers' obligations
under the Indenture and the Notes, including the payment of principal of and
premium, if any, on and interest on the Notes pursuant to its
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Subsidiary Guarantee. 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 (including, but not limited to, Guarantor
Senior Indebtedness) of such Subsidiary Guarantor 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 the Subsidiary Guarantee not constituting a fraudulent conveyance or
fraudulent transfer under federal or state law. Each Subsidiary Guarantor that
makes a payment or distribution under a Subsidiary Guarantee shall be entitled
to a contribution from each other Subsidiary Guarantor in a pro rata amount
based on the Adjusted Net Assets of each Subsidiary Guarantor.
Each Subsidiary Guarantor may consolidate with or merge into or sell or
otherwise dispose of all or substantially all of its properties and assets to
the Company or another Subsidiary Guarantor without limitation, except to the
extent any such transaction is subject to the covenant described under
"--Merger and Consolidation" or "--Limitation on Sales of Assets and Subsidiary
Stock." Each Subsidiary Guarantor may consolidate with or merge into or sell
all or substantially all of its properties and assets to a Person other than
the Company or another Subsidiary Guarantor (whether or not Affiliated with the
Subsidiary Guarantor). However:
(1) if the surviving Person is not the Subsidiary Guarantor, the surviving
Person must agree to assume the Subsidiary Guarantor's Subsidiary
Guarantee and all its obligations pursuant to the Indenture (except to
the extent the following paragraph would result in the release of such
Subsidiary Guarantee) and
(2) the transaction must not (a) violate any of the covenants described
under the heading "--Certain Covenants" or (b) result in a Default or
Event of Default immediately thereafter that is continuing.
Upon the sale or other disposition (by merger or otherwise) of a Subsidiary
Guarantor (or all or substantially all of its properties and assets) to a
Person other than the Company or another Subsidiary Guarantor and pursuant to a
transaction that is otherwise in compliance with the Indenture (including as
described in the foregoing paragraph), such Subsidiary Guarantor shall be
deemed released from its Subsidiary Guarantee and the related obligations set
forth in the Indenture. However, any such termination shall occur only to the
extent that all obligations of such Subsidiary Guarantor under all of its
guarantees of, and under all of its pledges of assets or other security
interests which secure, other Indebtedness of the Company or any other
Restricted Subsidiary shall also terminate upon such sale or other disposition.
Each Subsidiary Guarantor that is designated as an Unrestricted Subsidiary in
accordance with the Indenture shall be released from its Subsidiary Guarantee
and related obligations set forth in the Indenture for so long as it remains an
Unrestricted Subsidiary.
The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee
are subordinated to the prior payment in full of all Guarantor Senior
Indebtedness of such Subsidiary Guarantor (including its guarantee of
Indebtedness of the Company under the Senior Credit Agreement) to substantially
the same extent as the Notes are subordinated to Senior Indebtedness. The
Subsidiary Guarantees will be structurally subordinated to all existing and
future liabilities of Subsidiaries of Subsidiary Guarantors that are not also
Subsidiary Guarantors.
Optional Redemption
Except as described below, the Notes are not redeemable until July 1, 2007.
On and after July 1, 2007, the Issuers may redeem all or a part of the Notes
from time to time upon not less than 30 nor more than 60 days' notice, at the
following redemption prices (expressed as a percentage of principal amount)
plus accrued and unpaid interest thereon, if any, to the applicable redemption
date (subject to
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the right of holders of record on the relevant record date to receive interest
due on the relevant interest payment date), if redeemed during the twelve-month
period beginning on July 1 of the years indicated below:
Year Percentage
---- ----------
2007............... 104.375%
2008............... 102.917%
2009............... 101.458%
2010 and thereafter 100.000%
Prior to July 1, 2005, the Issuers may on any one or more occasions redeem
up to 35% of the original principal amount of the Notes with the Net Cash
Proceeds of one or more Equity Offerings at a redemption price of 108.75% of
the principal amount thereof, plus accrued and unpaid interest, if any, to the
redemption date (subject to the right of holders of record on the relevant
record date to receive interest due on the relevant interest payment date);
provided that
(1) at least 65% of the original principal amount of the Notes remains
outstanding after each such redemption; and
(2) the redemption occurs within 90 days after the closing of such Equity
Offering.
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 the Notes are not listed, then on a pro rata basis, by lot or by
such other method as the Trustee in its sole discretion will deem to be fair
and appropriate, although no Note of $1,000 in original principal amount or
less will be redeemed in part. If any Note is to be redeemed in part only, the
notice of redemption relating to such Note will 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.
Mandatory Redemption
The Issuers are not required to make mandatory redemption or sinking fund
payments with respect to the Notes.
Change of Control
If a Change of Control occurs, each holder will have the right to require
the Issuers to repurchase all or any part (equal to $1,000 or an integral
multiple thereof) of such holder's Notes at a purchase price in cash equal to
101% of the principal amount of the Notes plus accrued and unpaid interest, if
any, to the date of purchase (subject to the right of holders of record on the
relevant record date to receive interest due on the relevant interest payment
date). Neither the Issuers nor the Trustee may waive the covenant relating to
the holders' right to require the Issuers to make such repurchase.
Within 30 days following any Change of Control, the Issuers will mail a
notice (the "Change of Control Offer") to each holder with a copy to the
Trustee stating:
(1) that a Change of Control has occurred and that such holder has the
right to require the Issuers to purchase such holder's Notes at a
purchase price in cash equal to 101% of the principal amount thereof
plus accrued and unpaid interest, if any, to the date of purchase
(subject to the right of holders of record on a record date to receive
interest on the relevant interest payment date) (the "Change of Control
Payment");
(2) the repurchase date (which shall be no earlier than 30 days nor later
than 60 days from the date such notice is mailed) (the "Change of
Control Payment Date"); and
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(3) the procedures determined by the Issuers, consistent with the
Indenture, that a holder must follow in order to have its Notes
repurchased.
On the Change of Control Payment Date, the Issuers will, to the extent
lawful:
(1) accept for payment all Notes or portions thereof (equal to $1,000 or an
integral multiple thereof) properly tendered pursuant to the Change of
Control Offer;
(2) deposit with the paying agent an amount equal to the Change of Control
Payment in respect of all Notes or portions thereof so tendered; and
(3) deliver or cause to be delivered to the Trustee the Notes so accepted
together with an Officers' Certificate stating the aggregate principal
amount of Notes or portions thereof being purchased by the Issuers.
The paying agent will promptly mail to each holder of 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 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.
If the Change of Control Payment Date is on or after an interest record
date and on or before the related interest payment date, any accrued and unpaid
interest will be paid to the Person in whose name a Note is registered at the
close of business on such record date, and no additional interest will be
payable to holders who tender pursuant to the Change of Control Offer.
The Change of Control provisions described above will be applicable whether
or not any other provisions of the Indenture are applicable. Except as
described above with respect to a Change of Control, the Indenture does not
contain provisions that permit the holders to require that the Issuers
repurchase or redeem the Notes in the event of a takeover, recapitalization or
similar transaction.
Prior to mailing a Change of Control Offer, and as a condition to such
mailing (i) all Senior Indebtedness must be repaid in full in cash or Cash
Equivalents, or the Issuers must offer to repay all Senior Indebtedness whose
holders accept such offer or (ii) the requisite holders of each issue of Senior
Indebtedness shall have consented to such Change of Control Offer being made
and waived the event of default, if any, caused by the Change of Control. The
Issuers covenant to effect such repayment or obtain such consent and waiver
within 30 days following any Change of Control, it being a default of the
Change of Control provision if the Issuers fail to comply with such covenant. A
default under the Indenture may result in a cross-default under the Senior
Credit Agreement. In the event of a default under the Senior Credit Agreement,
the subordination provisions of the Indenture would likely restrict payments to
the holders of the Notes.
The Issuers will not be required to make a Change of Control Offer upon a
Change of Control 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
Issuers and purchases all Notes validly tendered and not withdrawn under such
Change of Control Offer.
The Issuers will comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Notes pursuant to this covenant. To the
extent that the provisions of any securities laws or regulations conflict with
provisions of the Indenture, the Issuers will comply with the applicable
securities laws and regulations and will not be deemed to have breached its
obligations described in the Indenture by virtue thereof.
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The Issuers' ability to repurchase Notes pursuant to a Change of Control
Offer may be limited by a number of factors. The occurrence of the events that
constitute a Change of Control will constitute a default under the Senior
Credit Agreement. In addition, certain events that may constitute a change of
control under the Senior Credit Agreement and cause a default thereunder may
not constitute a Change of Control under the Indenture. Future Indebtedness of
the Issuers and the Subsidiaries may also contain prohibitions of certain
events that would constitute a Change of Control or require such Indebtedness
to be repurchased upon a Change of Control. Moreover, the exercise by the
holders of their right to require the Issuers to repurchase the Notes could
cause a default under such Indebtedness, even if the Change of Control itself
does not, due to the financial effect of such repurchase on the Issuers.
Finally, the Issuers' ability to pay cash to the holders upon a repurchase may
be limited by the Issuers' then existing financial resources. There can be no
assurance that sufficient funds will be available when necessary to make any
required repurchases.
The Change of Control provisions described above may deter certain mergers,
tender offers and other takeover attempts involving the Issuers by increasing
the capital required to effectuate such transactions. The definition of "Change
of Control" includes a disposition of all or substantially all of the property
and assets of the Company and its Restricted Subsidiaries taken as a whole to
any Person. Although there is a limited body of case law interpreting the
phrase "substantially all," there is no precise established definition of the
phrase under applicable law. Accordingly, in certain circumstances there may be
a degree of uncertainty as to whether a particular transaction would involve a
disposition of "all or substantially all" of the property or assets of a
Person. As a result, it may be/-/unclear as to whether a Change of Control has
occurred and whether a holder of Notes may require the Issuers to make an offer
to repurchase the Notes as described above.
Certain Covenants
Limitation on Indebtedness
The Company will not, and will not permit any of its Restricted
Subsidiaries to, Incur any Indebtedness; provided, however, that the Company
and its Restricted Subsidiaries may Incur Indebtedness if on the date thereof:
(1) the Consolidated Coverage Ratio for the Company and its Restricted
Subsidiaries is at least 2.50 to 1.00; and
(2) no Default or Event of Default will have occurred and be continuing or
would occur as a consequence thereof.
The first paragraph of this covenant will not prohibit the Incurrence of
the following Indebtedness:
(1) Indebtedness incurred pursuant to the Senior Credit Agreement,
including any amendment, modification, supplement, extension,
restatement, replacement (including replacement after the termination
of such Senior Credit Agreement), restructuring, increase, renewal, or
refinancing thereof from time to time in one or more agreements or
instruments; provided, however; that, after giving effect to any such
Incurrence, the aggregate principal amount of such Indebtedness then
outstanding does not exceed the greater of (i) $300.0 million and (ii)
so long as the Consolidated Coverage Ratio for the Company and its
Restricted Subsidiaries is at least 2.00 to 1.00 after giving effect to
any such Incurrence, $100.0 million plus 25% of Adjusted Consolidated
Net Tangible Assets determined as of the date of the Incurrence of such
Indebtedness;
(2) Indebtedness owed to and held by the Company or a Restricted
Subsidiary; provided, however, that any subsequent issuance or transfer
of any Capital Stock which results in any
105
such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any
subsequent transfer of such Indebtedness (other than to the Company or
a Restricted Subsidiary) shall be deemed, in each case, to constitute
the Incurrence of such Indebtedness by the obligor thereon;
(3) Indebtedness under the Notes (but not Additional Notes) and the
Subsidiary Guarantees;
(4) Indebtedness outstanding on the Issue Date (other than Indebtedness
described in clause (1), (2) or (3) of this covenant);
(5) Indebtedness of a Restricted Subsidiary Incurred and outstanding on or
prior to the date on which such Subsidiary was acquired by the Company
(other than Indebtedness Incurred in connection with, or to provide all
or any portion of the funds or credit support utilized to consummate,
the transaction or series of related transactions pursuant to which
such Subsidiary became a Restricted Subsidiary or was acquired by the
Company);
(6) Refinancing Indebtedness in respect of Indebtedness Incurred pursuant
to the first paragraph of this covenant or pursuant to clause (3), (4),
(5) or this clause (6); provided, however, that to the extent such
Refinancing Indebtedness directly or indirectly Refinances Indebtedness
of a Subsidiary Incurred pursuant to clause (5), such Refinancing
Indebtedness shall be Incurred only by such Subsidiary or the Company;
(7) Permitted Acquisition Indebtedness;
(8) Indebtedness in respect of purchase money obligations, including
Capitalized Lease Obligations, in an aggregate amount not to exceed
$25.0 million;
(9) Hedging Obligations consisting of Interest Rate Agreements directly
related to Indebtedness permitted to be Incurred pursuant to the
Indenture;
(10)Non-Recourse Debt;
(11)Indebtedness in respect of bid, performance, reimbursement or surety
obligations issued by or for the account of the Company or any
Restricted Subsidiary in the ordinary course of business, including
Guarantees and letters of credit functioning as or supporting such bid,
performance, reimbursement or surety obligations (in each case other
than for an obligation for money borrowed);
(12)Indebtedness consisting of obligations in respect of purchase price
adjustments, indemnities or Guarantees of the same or similar matters
in connection with the acquisition or disposition of Property;
(13)Indebtedness under Commodity Agreements and Currency Agreements 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;
(14)Any Guarantee by the Company or a Subsidiary of the Company of
Indebtedness Incurred pursuant to the first paragraph of this covenant
or pursuant to clause (1), (2), (3), (4), (8), (9), (13) or (15) or
pursuant to clause (6) to the extent the Refinancing Indebtedness
Incurred thereunder directly or indirectly Refinances Indebtedness
Incurred pursuant to the first paragraph of this covenant or pursuant
to clauses (3) or (4); and
(15)Indebtedness in an aggregate principal amount which, when taken
together with all other Indebtedness of the Company outstanding on the
date of such Incurrence (other than Indebtedness permitted by clauses
(1) through (14) above or the first paragraph of this covenant) does
not exceed $30.0 million.
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The Company will not Incur any Indebtedness under the preceding paragraph
if the proceeds thereof are used, directly or indirectly, to refinance any
Subordinated Obligations of the Company unless such Indebtedness will be
subordinated to the Notes to at least the same extent as such Subordinated
Obligations.
For purposes of determining compliance with, and the outstanding principal
amount of any particular Indebtedness incurred pursuant to and in compliance
with, this covenant:
(i) in the event that Indebtedness meets the criteria of more than one of
the types of Indebtedness described in the first and second paragraphs
of this covenant, the Company, in its sole discretion, will on the date
of Incurrence classify (or later reclassify) such item of Indebtedness
and only be required to include the amount and type of such
Indebtedness in one of such clauses; and
(ii)the amount of Indebtedness issued at a price that is less than the
principal amount thereof will be equal to the amount of the liability
in respect thereof determined in accordance with GAAP.
Accrual of interest, accrual of dividends, the accretion of accreted value,
the payment of interest in the form of additional Indebtedness and the payment
of dividends in the form of additional shares of Preferred Stock will not be
deemed to be an incurrence of Indebtedness for purposes of this covenant. The
amount of any Indebtedness outstanding as of any date shall be (i) the accreted
value thereof in the case of any Indebtedness issued with original issue
discount and (ii) the principal amount or liquidation preference thereof,
together with any interest thereon that is more than 30 days past due, in the
case of any other Indebtedness.
In addition, the Company will not permit any of its Unrestricted
Subsidiaries to Incur any Indebtedness or issue any shares of Disqualified
Stock, other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary
becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be
deemed to be Incurred by a Restricted Subsidiary of the Company as of such date
(and, if such Indebtedness is not permitted to be Incurred as of such date
under this "Limitation on Indebtedness" covenant, the Company shall be in
Default of this covenant).
For purposes of determining compliance with any U.S. dollar-denominated
restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent
principal amount of Indebtedness denominated in a foreign currency shall be
calculated based on the relevant currency exchange rate in effect on the date
such Indebtedness was Incurred, in the case of term Indebtedness, or first
committed, in the case of revolving credit Indebtedness; provided that if such
Indebtedness is Incurred to refinance other Indebtedness denominated in a
foreign currency, and such refinancing would cause the applicable U.S.
dollar-dominated restriction to be exceeded if calculated at the relevant
currency exchange rate in effect on the date of such refinancing, such U.S.
dollar-dominated restriction shall be deemed not to have been exceeded so long
as the principal amount of such refinancing Indebtedness does not exceed the
principal amount of such Indebtedness being refinanced. Notwithstanding any
other provision of this covenant, the maximum amount of Indebtedness that the
Company may Incur pursuant to this covenant shall not be deemed to be exceeded
solely as a result of fluctuations in the exchange rate of currencies. The
principal amount of any Indebtedness incurred to refinance other Indebtedness,
if Incurred in a different currency from the Indebtedness being refinanced,
shall be calculated based on the currency exchange rate applicable to the
currencies in which such Refinancing Indebtedness is denominated that is in
effect on the date of such refinancing.
Limitation on Layering
The Issuers will not Incur any Indebtedness if such Indebtedness is
subordinate or junior in ranking in any respect to any Senior Indebtedness
unless such Indebtedness is Senior Subordinated Indebtedness or is
contractually subordinated in right of payment to Senior Subordinated
Indebtedness. No Subsidiary Guarantor will incur or allow to remain
outstanding, any Indebtedness (including Acquired Indebtedness and any
indebtedness allowed pursuant to the second paragraph of
107
the covenant described under "Limitation on Indebtedness") other than such
Subsidiary Guarantor's Subsidiary Guarantee, that is subordinated in right of
payment to any Guarantor Senior Indebtedness unless such Indebtedness is
Guarantor Senior Subordinated Indebtedness or is subordinated in right of
payment to Guarantor Senior Subordinated Indebtedness.
Limitation on Restricted Payments
The Company will not, and will not permit any of its Restricted
Subsidiaries, directly or indirectly, to:
(1) declare or pay any dividend or make any distribution on or in respect
of its Capital Stock (including any payment in connection with any
merger or consolidation involving the Company or any of its Restricted
Subsidiaries) except:
(a) dividends or distributions payable in Capital Stock of the Company
(other than Disqualified Stock) or in options, warrants or other
rights to purchase such Capital Stock of the Company; and
(b) dividends or distributions payable to the Company or a Restricted
Subsidiary of the Company (and if such Restricted Subsidiary is
not a Wholly-Owned Subsidiary, to its other holders of common
Capital Stock on a pro rata basis);
(2) purchase, redeem, retire or otherwise acquire for value any Capital
Stock of the Company or any direct or indirect parent of the Company
held by Persons other than the Company or a Restricted Subsidiary of
the Company (other than in exchange for Capital Stock of the Company
(other than Disqualified Stock));
(3) purchase, repurchase, redeem, defease or otherwise acquire or retire
for value, prior to scheduled maturity, scheduled repayment or
scheduled sinking fund payment, any Subordinated Obligations (other
than the purchase, repurchase or other acquisition of Subordinated
Obligations purchased in anticipation of satisfying a sinking fund
obligation, principal installment or final maturity, in each case due
within one year of the date of purchase, repurchase or acquisition); or
(4) make any Restricted Investment in any Person;
(any such dividend, distribution, purchase, redemption, repurchase, defeasance,
other acquisition, retirement or Restricted Investment referred to in clauses
(1) through (4) shall be referred to herein as a "Restricted Payment"), if at
the time the Company or such Restricted Subsidiary makes such Restricted
Payment:
(a) a Default shall have occurred and be continuing (or would result
therefrom); or
(b) the Company is not able to Incur an additional $1.00 of
Indebtedness pursuant to the first paragraph under the "Limitation
on Indebtedness" covenant, after giving effect to such Restricted
Payment; or
(c) the aggregate amount of such Restricted Payment and all other
Restricted Payments declared or made subsequent to the Issue Date
would exceed the sum of:
(i) 50% of Consolidated Net Income for the period (treated as one
accounting period) from the beginning of the first fiscal
quarter commencing after the date of the Indenture to the end
of the most recent fiscal quarter ending prior to the date of
such Restricted Payment for which financial statements are in
existence (or, in case such Consolidated Net Income is a
deficit, minus 100% of such deficit);
(ii)the aggregate Net Cash Proceeds received by the Company from
the issue or sale of its Capital Stock (other than
Disqualified Stock) or other capital
108
contributions subsequent to the Issue Date (other than Net
Cash Proceeds received from an issuance or sale of such
Capital Stock to a Subsidiary of the Company or an employee
stock ownership plan, option plan or similar trust to the
extent such sale to an employee stock ownership plan, option
plan or similar trust is financed by loans from or Guaranteed
by the Company or any Restricted Subsidiary unless such loans
have been repaid with case on or prior to the date of
determination);
(iii)the amount by which Indebtedness of the Company is reduced on
the Company's balance sheet upon the conversion or exchange
(other than by a Subsidiary of the Company subsequent to the
Issue Date of any Indebtedness of the Company convertible or
exchangeable for Capital Stock (other than Disqualified Stock)
of the Company (less the amount of any cash, or other
property, distributed by the Company upon such conversion or
exchange); and
(iv)the amount equal to the net reduction in Restricted Investment
made by the Company or any of its Restricted Subsidiaries in
any Person resulting from:
(A) repurchases or redemptions of such Restricted Investments
by such Person, proceeds realized upon the sale of such
Restricted Investment to a purchaser other than the
Company or a Subsidiary, repayments of loans or advances
or other transfers of assets (including by way of dividend
or distribution) by such Person to the Company or any
Restricted Subsidiary of the Company; or
(B) the redesignation of Unrestricted Subsidiaries as
Restricted Subsidiaries (valued in each case as provided
in the definition of "Investment") not to exceed, in the
case of any Unrestricted Subsidiary the amount of
Investments previously made by the Company or any
Restricted Subsidiary in such Unrestricted Subsidiary,
which amount in each case under this clause (iv) was included
in the calculation of the amount of Restricted Payments;
provided, however, that no amount will be included under this
clause (iv) to the extent it is already included in
Consolidated Net Income.
The provisions of the preceding paragraph will not prohibit:
(1) any purchase or redemption of Capital Stock or Subordinated Obligations
of the Company made by exchange for, or out of the proceeds of the
substantially concurrent sale of, Capital Stock of the Company (other
than Disqualified Stock and other than Capital Stock issued or sold to
a Subsidiary or an employee stock ownership plan or similar trust to
the extent such sale to an employee stock ownership plan or similar
trust is financed by loans from or guaranteed by the Company or any
Restricted Subsidiary unless such loans have been repaid with cash on
or prior to the date of determination); provided, however, that (a)
such purchase or redemption will be excluded in subsequent calculations
of the amount of Restricted Payments and (b) the Net Cash Proceeds from
such sale will be excluded from clause (c)(ii) of the preceding
paragraph;
(2) any purchase or redemption of Subordinated Obligations of the Company
made by exchange for, or out of the proceeds of the substantially
concurrent sale of, Subordinated Obligations of the Company that
qualifies as Refinancing Indebtedness; provided, however, that such
purchase or redemption will be excluded in subsequent calculations of
the amount of Restricted Payments;
(3) so long as no Default or Event of Default has occurred and is
continuing, any purchase or redemption of Subordinated Obligations or
Preferred Stock from Net Available Cash to the
109
extent permitted under "--Limitation on Sales of Assets and Subsidiary
Stock" below; provided, however, that such purchase or redemption will
be excluded in subsequent calculations of the amount of Restricted
Payments;
(4) dividends paid within 60 days after the date of declaration if at such
date of declaration such dividend would have complied with this
provision; provided, however, that such dividends will be included in
subsequent calculations of the amount of Restricted Payments unless the
declaration of such dividend had been counted in a prior period;
(5) so long as no Default or Event of Default has occurred and is
continuing, the declaration and payment of dividends to holders of any
class or series of Disqualified Stock of the Company issued in
accordance with the terms of the Indenture to the extent such dividends
are included in the definition of "Consolidated Interest Expense";
provided, that the payment of such dividends will be excluded from
subsequent calculations of Restricted Payments;
(6) repurchases of Capital Stock deemed to occur upon the exercise of stock
options if such Capital Stock represents a portion of the exercise
price thereof; provided, however, that such repurchases will be
excluded from subsequent calculations of the amount of Restricted
Payments;
(7) payments contemplated by the Transition Agreements (except the
employment matters agreement) as in effect on the date hereof, as these
agreements may be amended, modified or supplemented from time to time;
provided, however, that any future amendment, modification or
supplement entered into after the Issue Date will be permitted to the
extent that its terms do not adversely affect the rights of any holders
of the Notes as compared to the terms of the agreements in effect on
the Issue Date; provided, further, that payments made pursuant to the
Plains Exploration & Production transition services agreement shall be
the costs and expenses incurred in providing the services and limited
in an aggregate amount not to exceed $30.0 million;
(8) repurchases of Capital Stock of any officer, director or employee of
the Company in an aggregate amount not to exceed $2.0 million in any
twelve-month period; provided, that such payments will be excluded from
subsequent calculation of the amounts of Restricted Payments; and
(9) Restricted Payments in an amount not to exceed $15.0 million; provided,
that such payments will be included in subsequent calculations of the
amount of Restricted Payments.
The amount of all Restricted Payments (other than cash) shall be the fair
market value on the date of such Restricted Payment of the asset(s) or
securities proposed to be paid, transferred or issued by the Company or such
Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment.
The fair market value of any cash Restricted Payment shall be its face amount
and any non-cash Restricted Payment shall be determined conclusively by the
Board of Directors acting in good faith whose resolution with respect thereto
shall be delivered to the Trustee, such determination to be based upon an
opinion or appraisal issued by an accounting, appraisal or investment banking
firm of national standing if such fair market value is estimated to exceed
$25.0 million. Not later than the date of making any Restricted Payment other
than a Restricted Payment allowed pursuant to (1) through (9) of the previous
paragraph, the Company shall deliver to the Trustee an Officers' Certificate
stating that such Restricted Payment is permitted and setting forth the basis
upon which the calculations required by the covenant "Restricted Payments" were
computed, together with a copy of any fairness opinion or appraisal required by
the Indenture.
Limitation on Liens
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create, incur or permit to exist any
Lien (other than Permitted Liens) upon any Principal
110
Property or any shares of stock or Indebtedness of any Restricted Subsidiary
that owns or leases any Principal Property (whether such Principal Property,
shares of stock or Indebtedness are now owned or hereafter acquired), securing
any Senior Subordinated Indebtedness or Subordinated Obligations, unless all
payments due under the Indenture with respect to the Notes are secured on an
equal and ratable basis with the obligations so secured until such time as such
obligations are no longer secured by a Lien.
Limitation on Restrictions on Distributions from Restricted Subsidiaries
The Company will not, and will not permit any Restricted Subsidiary to,
create or otherwise cause or permit to exist or become effective any consensual
encumbrance or consensual restriction on the ability of any Restricted
Subsidiary to:
(1) pay dividends or make any other distributions on its Capital Stock or
pay any Indebtedness or other obligations owed to the Company or any
Restricted Subsidiary;
(2) make any loans or advances to the Company or any Restricted Subsidiary;
or
(3) transfer any of its property or assets to the Company or any Restricted
Subsidiary.
The preceding provisions will not prohibit:
(i) any encumbrance or restriction pursuant to an agreement in effect at or
entered into on the Issue Date (including, without limitation, the
Indenture and the Senior Credit Agreement in effect on such date);
(ii)any encumbrance or restriction with respect to a Restricted Subsidiary
pursuant to an agreement effecting a refinancing of indebtedness
Incurred pursuant to an agreement referred to in clause (i) of this
paragraph or this clause (ii) or contained in any amendment to an
agreement referred to in clause (i) of this paragraph or this clause
(ii); provided, however, that the encumbrances and restrictions with
respect to such Restricted Subsidiary contained in any such agreement
or amendment taken as a whole are no less favorable in any material
respect to the holders of the Notes than the encumbrances and
restrictions contained in such agreements referred to in clause (i) of
this paragraph on the Issue Date;
(iii)in the case of clause (3) of the first paragraph of this covenant, any
encumbrance or restriction:
(a) that restricts in a customary manner the subletting, assignment or
transfer of any property or asset that is subject to a lease,
license or similar contract, or the assignment or transfer of any
such lease, license or other contract;
(b) contained in mortgages, pledges or other security agreements
permitted under the Indenture securing Indebtedness of the Company
or a Restricted Subsidiary to the extent such encumbrances or
restrictions restrict the transfer of the property subject to such
mortgages, pledges or other security agreements; or
(c) pursuant to customary provisions restricting dispositions of real
property interests set forth in any reciprocal easement
agreements`of the Company or any Restricted Subsidiary;
(iv)purchase money obligations for property acquired in the ordinary course
of business that impose encumbrances or restrictions of the nature
described in clause (3) of the first paragraph of this covenant on the
property so acquired;
(v) any restriction with respect to a Restricted Subsidiary (or any of its
property or assets) imposed pursuant to an agreement entered into for
the direct or indirect sale or disposition
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of all or substantially all the Capital Stock or assets of such
Restricted Subsidiary (or the property or assets that are subject to
such restriction) pending the closing of such sale or disposition;
(vi)encumbrances or restrictions arising or existing by reason of
applicable law or any applicable rule, regulation or order;
(vii)customary supermajority voting provisions and other customary
provisions with respect to the disposition or distribution of assets or
property in joint venture agreements;
(viii)customary encumbrances or restrictions imposed pursuant to any
agreement referred to in the definition of "Permitted Business
Investment";
(ix)encumbrances or restrictions in instruments evidencing Indebtedness of
a Restricted Subsidiary Incurred and outstanding on or prior to the
date on which such Subsidiary was acquired by the Company; provided,
however, that such encumbrances or restrictions are not created,
incurred or assumed in connection with, or in contemplation of, such
acquisition; and
(x) Indebtedness permitted under the Indenture containing encumbrances or
restrictions that taken as a whole are not materially more restrictive
than the encumbrances and restrictions otherwise contained in the
Indenture.
Limitation on Sales of Assets and Subsidiary Stock
The Company will not, and will not permit any of its Restricted Subsidiaries
to, make any Asset Disposition unless:
(1) the Company or such Restricted Subsidiary receives consideration at the
time of such Asset Disposition at least equal to the fair market value,
as determined in good faith by the Board of Directors (including as to
the value of all non-cash consideration), of the shares and assets
subject to such Asset Disposition;
(2) at least 75% of the consideration thereof received by the Company or
such Restricted Subsidiary, as the case may be, is in the form of cash,
Cash Equivalents or Additional Assets; and
(3) an amount equal to 100% of the Net Available Cash from such Asset
Disposition is applied by the Company or such Restricted Subsidiary, as
the case may be:
(a) to the extent the Company or any Restricted Subsidiary, as the
case may be, elects (or is required by the terms of any Senior
Indebtedness), to prepay, repay or purchase Senior Indebtedness or
Indebtedness (other than any Preferred Stock) of a Restricted
Subsidiary that is a Subsidiary Guarantor (in each case other than
Indebtedness owed to the Company or an Affiliate of the Company)
within 360 days from the later of the date of such Asset
Disposition or the receipt of such Net Available Cash; provided,
however, that, in connection with any prepayment, repayment or
purchase of Indebtedness pursuant to this clause (a), the Company
or such Restricted Subsidiary will retire such Indebtedness and
will cause the related commitment (if any) to be permanently
reduced in an amount equal to the principal amount so prepaid,
repaid or purchased; and
(b) to the extent the Company or such Restricted Subsidiary elects, to
invest in Additional Assets within 360 days from the later of the
date of such Asset Disposition or the receipt of such Net
Available Cash.
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Pending the final application of any Net Available Cash, the Company may
temporarily reduce its revolving credit borrowings or otherwise invest such Net
Available Cash in any manner that is not prohibited by the Indenture.
Any Net Available Cash from Asset Dispositions that is not applied or
invested as provided in the second preceding paragraph will be deemed to
constitute "Excess Proceeds." On the 361st day after an Asset Disposition (or,
if there exists any Senior Indebtedness with similar provisions requiring the
Company to make an offer to purchase such Senior Indebtedness, on the 451st day
after an Asset Disposition), if the aggregate amount of Excess Proceeds exceeds
$10.0 million, the Issuers will be required to make an offer ("Asset
Disposition Offer") to all holders of Notes and to the extent required by the
terms thereof, to all holders of other Senior Subordinated Indebtedness
outstanding with similar provisions requiring the Company or the Issuers to
make an offer to purchase such Senior Subordinated Indebtedness with the
proceeds from any Asset Disposition ("Pari Passu Notes"), to purchase the
maximum principal amount of Notes and any such Pari Passu Notes to which the
Asset Disposition Offer applies that may be purchased out of the Excess
Proceeds, at an offer price in cash in an amount equal to 100% of the principal
amount thereof plus accrued and unpaid interest to the date of purchase, in
accordance with the procedures set forth in the Indenture or the agreements
governing the Pari Passu Notes, as applicable. To the extent that the aggregate
amount of Notes and Pari Passu Notes so validly tendered and not properly
withdrawn pursuant to an Asset Disposition Offer is less than the Excess
Proceeds, the Issuers may use any remaining Excess Proceeds for general
corporate or partnership purposes, subject to the other covenants contained in
the Indenture. If the aggregate principal amount of Notes surrendered by
holders thereof and other Pari Passu Notes surrendered by holders or lenders
thereof, collectively, exceeds the amount of Excess Proceeds, the Trustee shall
select the Notes to be purchased on a pro rata basis on the basis of the
aggregate principal amount of tendered Notes and Pari Passu Notes. Upon
completion of such Asset Disposition Offer, the amount of Excess Proceeds shall
be reset at zero.
The Asset Disposition Offer will remain open for a period of 20 Business
Days following its commencement, except to the extent that a longer period is
required by applicable law (the "Asset Disposition Offer Period"). No later
than five Business Days after the termination of the Asset Disposition Offer
Period (the "Asset Disposition Purchase Date"), the Issuers will purchase the
principal amount of Notes and Pari Passu Notes required to be purchased
pursuant to this covenant (the "Asset Disposition Offer Amount") or, if less
than the Asset Disposition Offer Amount has been so validly tendered, all Notes
and Pari Passu Notes validly tendered in response to the Asset Disposition
Offer.
If the Asset Disposition Purchase Date is on or after an interest record
date and on or before the related interest payment date, any accrued and unpaid
interest will be paid to the Person in whose name a Note is registered at the
close of business on such record date, and no additional interest will be
payable to holders who tender Notes pursuant to the Asset Disposition Offer.
On or before the Asset Disposition Purchase Date, the Issuers will, to the
extent lawful, accept for payment, on a pro rata basis to the extent necessary,
the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions
thereof so validly tendered and not properly withdrawn pursuant to the Asset
Disposition Offer, or if less than the Asset Disposition Offer Amount has been
validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so
validly tendered and not properly withdrawn. The Issuers will deliver to the
Trustee an Officers' Certificate stating that such Notes or portions thereof
were accepted for payment by the Issuers in accordance with the terms of this
covenant and, in addition, the Issuers will deliver all certificates and notes
required, if any, by the agreements governing the Pari Passu Notes. The Issuers
or the Paying Agent, as the case may be, will promptly (but in any case not
later than five Business Days after the termination of the Asset Disposition
Offer Period) mail or deliver to each tendering holder of Notes or holder or
lender of Pari Passu Notes, as the case may be, an amount equal to the purchase
price of the Notes or Pari Passu
113
Notes so validly tendered and not properly withdrawn by such holder or lender,
as the case maybe, and accepted by the Issuers for purchase, and the Issuers
will promptly issue a new Note, and the Trustee, upon delivery of an Officers'
Certificate from the Issuers will authenticate and mail or deliver such new
Note to such holder, in a principal amount equal to any unpurchased portion of
the Note surrendered. In addition, the Company or the Issuers will take any and
all other actions required by the agreements governing the Pari Passu Notes.
Any Note not so accepted will be promptly mailed or delivered by the Issuers to
the holder thereof. The Issuers will publicly announce the results of the Asset
Disposition Offer on the Asset Disposition Purchase Date.
For the purposes of this covenant, the following will be deemed to be cash:
(1) the assumption by the transferee of Indebtedness (other than Senior
Subordinated Indebtedness, Subordinated Obligations or Disqualified
Stock) of the Company or Indebtedness (other than Preferred Stock) of
any Restricted Subsidiary of the Company and the release of the Company
or such Restricted Subsidiary from all liability on such Indebtedness
in connection with such Asset Disposition (in which case the Company
will, without further action, be deemed to have applied such deemed
cash to Indebtedness in accordance with clause (3)(a) above); and
(2) securities, notes or other obligations received by the Company or any
Restricted Subsidiary of the Company from the transferee that are
promptly converted by the Company or such Restricted Subsidiary into
cash.
The Issuers will comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Notes pursuant to the Indenture. To the
extent that the provisions of any securities laws or regulations conflict with
provisions of this covenant, the Issuers will comply with the applicable
securities laws and regulations and will not be deemed to have breached its
obligations under the Indenture by virtue thereof.
Limitation on Affiliate Transactions
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, enter into or conduct any transaction
(including the purchase, sale, lease or exchange of any property or the
rendering of any service) with any Affiliate of the Company (an "Affiliate
Transaction") unless:
(1) the terms of such Affiliate Transaction are no less favorable to the
Company or such Restricted Subsidiary, as the case may be, than those
that could be obtained in a comparable transaction at the time of such
transaction in arms-length dealings with a Person who is not such an
Affiliate;
(2) in the event such Affiliate Transaction involves an aggregate amount in
excess of $5.0 million, the terms of such transaction have been
approved by a majority of the members of the Board of Directors of the
Company and by a majority of the members of such Board having no
personal stake in such transaction, if any (and such majority or
majorities, as the case may be, determines that such Affiliate
Transaction satisfies the criteria in clause (1) above); and
(3) in the event such Affiliate Transaction involves an aggregate amount in
excess of $20.0 million, the Company has received a written opinion
from an independent investment banking firm, appraiser or other expert
of nationally recognized standing that such Affiliate Transaction is
not materially less favorable than those that might reasonably have
been obtained in a comparable transaction at such time on an
arms-length basis from a Person that is not an Affiliate.
114
The preceding paragraph will not apply to:
(1) any Restricted Payment (other than a Restricted Investment) permitted
to be made pursuant to the covenant described under "Limitation on
Restricted Payments;"
(2) any issuance of securities, or other payments, awards or grants in
cash, securities or otherwise pursuant to, or the funding of,
employment arrangements, stock options and stock ownership plans and
other reasonable fees, compensation, benefits and indemnities paid or
entered into by the Company or its Restricted Subsidiaries in the
ordinary course of business to or with officers, directors or employees
of the Company and its Restricted Subsidiaries;
(3) loans or advances to employees in the ordinary course of business of
the Company or any of its Restricted Subsidiaries;
(4) any transaction between the Company and a Restricted Subsidiary or
between Restricted Subsidiaries;
(5) the payment of reasonable and customary fees paid to, and indemnity
provided on behalf of, officers, directors or employees of the Company
or any Restricted Subsidiary of the Company;
(6) any transaction between the Company and Plains Resources Inc. and its
Subsidiaries or between a Restricted Subsidiary and Plains Resources
Inc. or its Subsidiaries pursuant to any of the Transition Agreements
as in effect on the Issue Date, as these agreements may be amended,
modified or supplemented from time to time; provided, however that any
future amendment, modification or supplement entered into after the
Issue Date will be permitted to the extent that its terms do not
adversely affect the rights of any holders of the Notes as compared to
the terms of the agreements in effect on the Issue Date;
(7) any transaction pursuant to the existing agreements between the Company
and PAA as in effect on the date hereof, as these agreements may be
amended, modified or supplemented from time to time; provided, however
that any future amendment, modification or supplement entered into
after the Issue Date will be permitted to the extent that its terms do
not adversely affect the rights of any holders of the Notes as compared
to the terms of the agreements in effect on the Issue Date; and
(8) the performance of obligations of the Company or any of its Restricted
Subsidiaries under the terms of any agreement to which the Company or
any of its Restricted Subsidiaries is a party on the Issue Date and
identified on a schedule to the Indenture on the Issue Date, as these
agreements may be amended, modified or supplemented from time to time;
provided, however that any future amendment, modification or supplement
entered into after the Issue Date will be permitted to the extent that
its terms do not adversely affect the rights of any holders of the
Notes as compared to the terms of the agreements in effect on the Issue
Date.
Limitation on Sale of Capital Stock of Restricted Subsidiaries
The Company will not, and will not permit any Restricted Subsidiary of the
Company to, transfer, convey, sell, lease or otherwise dispose of any Voting
Stock of any Restricted Subsidiary or to issue any of the Voting Stock of a
Restricted Subsidiary (other than, if necessary, shares of its Voting Stock
constituting directors' qualifying shares) to any Person except:
(1) to the Company or a Restricted Subsidiary or the parent of a Restricted
Subsidiary; or
(2) in compliance with the covenant described under "--Limitation on Sales
of Assets and Subsidiary Stock" and immediately after giving effect to
such issuance or sale, such Restricted Subsidiary would continue to be
a Restricted Subsidiary.
115
Notwithstanding the preceding paragraph, the Company may sell all the
Voting Stock of a Restricted Subsidiary as long as the Company complies with
the terms of the covenant described under "--Limitation on Sales of Assets and
Subsidiary Stock."
SEC Reports
Notwithstanding that the Company may not be subject to the reporting
requirements of Section 13 or 15(d) of the Exchange Act, to the extent
permitted by the Exchange Act, the Company will file with the Commission, and
provide the Trustee and the holders of the Notes with, the annual reports and
the information, documents and other reports (or copies of such portions of any
of the foregoing as the Commission may by rules and regulations prescribe) that
are specified in Sections 13 and 15(d) of the Exchange Act within the time
periods specified therein. In the event that the Company is not permitted to
file such reports, documents and information with the Commission pursuant to
the Exchange Act, the Company will nevertheless provide such Exchange Act
information to the Trustee and the holders of the Notes as if the Company were
subject to the reporting requirements of Section 13 or 15(d) of the Exchange
Act within the time periods specified therein.
Merger and Consolidation
The Company will not consolidate with or merge with or into, or convey,
transfer or lease all or substantially all its assets to, any Person, unless:
(1) the resulting, surviving or transferee Person (the "Successor Company")
will be a corporation, partnership, trust or limited liability company
organized and existing under the laws of the United States of America,
any State thereof or the District of Columbia and the Successor Company
(if not the Company) will expressly assume, by supplemental indenture,
executed and delivered to the Trustee, in form satisfactory to the
Trustee, all the obligations of the Company under the Notes and the
Indenture;
(2) immediately after giving effect to such transaction (and treating any
Indebtedness that becomes an obligation of the Successor Company or any
Subsidiary of the Successor Company as a result of such transaction as
having been Incurred by the Successor Company or such Subsidiary at the
time of such transaction), no Default or Event of Default shall have
occurred and be continuing;
(3) immediately after giving effect to such transaction, the Successor
Company would be able to Incur at least an additional $1.00 of
Indebtedness pursuant to the first paragraph of the "Limitation on
Indebtedness" covenant;
(4) if the Company is not the continuing obligor under the Indenture, then
any Subsidiary Guarantor, unless it is the Successor Company, shall
have by supplemental indenture to the Indenture confirmed that its
Subsidiary Guarantee of the Notes shall apply to the Successor
Company's obligations under the Indenture and the Notes; and
(5) the Company shall have delivered to the Trustee an Officers'
Certificate and an Opinion of Counsel, each stating that such
consolidation, merger or transfer and such supplemental indenture (if
any) comply with the Indenture.
For purposes of this covenant, the sale, lease, conveyance, assignment,
transfer, or other disposition of all or substantially all of the properties
and assets of one or more Subsidiaries of the Company, which properties and
assets, if held by the Company instead of such Subsidiaries, would constitute
all or substantially all of the properties and assets of the Company on a
consolidated basis, shall be deemed to be the transfer of all or substantially
all of the assets of the Company.
116
The Successor Company will succeed to, and be substituted for, and may
exercise every right and power of, the Company under the Indenture, but, in the
case of a lease of all or substantially all its assets, the Company will not be
released from the obligation to pay the principal of and interest on the Notes.
Although there is a limited body of case law interpreting the phrase
"substantially all," there is no precise established definition of the phrase
under applicable law. Accordingly, in certain circumstances there may be a
degree of uncertainty as to whether a particular transaction would involve "all
or substantially all" of the property or assets of a Person.
Notwithstanding the foregoing, the Company is permitted to reorganize as a
corporation in accordance with the procedures established in the Indenture, and
may merge or consolidate with an Affiliate for such purpose; provided that the
Company shall have delivered to the Trustee an Opinion of Counsel reasonably
acceptable to the 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 reorganization. Notwithstanding the preceding clause (3), (x)
any Restricted Subsidiary of the Company may consolidate with, merge into or
transfer all or part of its properties and assets to the Company, and (y) if
then a corporation, the Company may merge with an Affiliate solely for the
purpose of reincorporating the Company in another jurisdiction to realize tax
or other benefits.
Effectiveness of Covenants
The covenants described under "--Limitation on Indebtedness," "--Limitation
on Layering," "--Limitation on Restricted Payments," "--Limitation on
Restrictions on Distributions from Restricted Subsidiaries," "--Limitation on
Sale of Assets and Subsidiary Stock," "--Limitation on Sale of Capital Stock of
Restricted Subsidiaries," "--Limitation on Lines of Business" and "--Payments
for Consent" (collectively, the "Suspended Covenants"), will no longer be in
effect upon (a) the Notes having an Investment Grade Rating from either of the
Rating Agencies and (b) no Default or Event of Default having occurred and
continuing under the Indenture. In the event that the Issuers and the
Restricted Subsidiaries are not subject to the Suspended Covenants for any
period of time as a result of the preceding sentence and, subsequently, one or
both of the Rating Agencies withdraws its ratings or downgrades the rating
assigned to the Notes below the required Investment Grade Ratings or a Default
or Event of Default occurs and is continuing, then the Issuers and the
Restricted Subsidiaries will thereafter again be subject to the Suspended
Covenants and compliance with the Suspended Covenants. Compliance with the
Suspended Covenants with respect to Restricted Payments made after the time of
such withdrawal, downgrade, Default or Event of Default will be calculated in
accordance with the terms of the covenant described above under "--Limitation
on Restricted Payments" as though such covenant had been in effect during the
entire period of time from the date the Notes are issued.
Future Subsidiary Guarantors
After the Issuer Date, the Company will cause each Restricted Subsidiary
other than a Foreign Subsidiary created or acquired by the Company to execute
and deliver to the Trustee a Subsidiary Guarantee pursuant to which such
Subsidiary Guarantor will unconditionally Guarantee, on a joint and several
basis, the full and prompt payment of the principal of, premium, if any, and
interest on the Notes on a senior subordinated basis.
Limitation on Lines of Business
The Company will not, and will not permit any Restricted Subsidiary to,
engage in any business other than a Related Business.
117
Restrictions on Activities of Plains E&P Company
Plains E&P Company will not hold any material assets, become liable for any
material obligations, other than the Notes, or engage in any significant
business activities; provided that Plains E&P Company may be a co-obligor with
respect to Indebtedness if the Company is the primary obligor of such
Indebtedness and the net proceeds of such Indebtedness are received by the
Company or one or more of the Company's Restricted Subsidiaries other than
Plains E&P Company. At any time after the Company is a corporation, Plains E&P
Company may consolidate or merge with or into the Company or any Restricted
Subsidiary.
Payments for Consent
Neither the Issuers nor any of the Restricted Subsidiaries will, directly
or indirectly, pay or cause to be paid any consideration, whether by way of
interest, fees or otherwise, to any holder of any Notes for or as an inducement
to any consent, waiver or amendment of any of the terms or provisions of the
Indenture or the Notes unless such consideration is offered to be paid or is
paid to all holders of the Notes that consent, waive or agree to amend in the
time frame set forth in the solicitation documents relating to such consent,
waiver or agreement.
Events of Default
Each of the following is an Event of Default:
(1) default in any payment of interest or additional interest (as required
by the Registration Rights Agreement) on any Note when due, continued
for 30 days, whether or not such payment is prohibited by the
provisions described under "Subordination;"
(2) default in the payment of principal of or premium, if any, on any Note
when due at its Stated Maturity, upon optional redemption, upon
required repurchase, upon declaration or otherwise, whether or not such
payment is prohibited by the provisions described under "Subordination;"
(3) failure by the Company to comply with its obligations under "Certain
Covenants--Merger and Consolidation;"
(4) failure by the Issuers to comply for 30 days after notice with any of
its obligations under the covenants described under "Change of Control"
above or under the covenants described under "Certain Covenants" above
(in each case, other than a failure to purchase Notes which will
constitute an Event of Default under clause (2) above and other than a
failure to comply with "Certain Covenants--Merger and Consolidation"
which is covered by clause (3));
(5) failure by the Issuers or any Subsidiary Guarantor to comply for 60
days after notice with its other agreements contained in the Indenture;
(6) 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), other than Indebtedness owed to
the Company or a Restricted Subsidiary, 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, or interest or
premium, if any, on such Indebtedness prior to the expiration of
the grace period provided in such Indebtedness ("payment
default"); or
(b) results in the acceleration of such Indebtedness prior to its
maturity (the "cross acceleration provision");
118
and, in each case, the principal amount of any such Indebtedness,
together with the principal amount of any other such Indebtedness under
which there has been a payment default or the maturity of which has
been so accelerated, aggregates $10.0 million or more;
(7) any Subsidiary Guarantee shall be held in a judicial proceeding to be,
or be asserted by the Issuers or any Subsidiary Guarantor, as
applicable, not to be, enforceable or valid or shall cease to be in
full force and effect (except pursuant to the release or termination of
any such Subsidiary Guarantee in accordance with the Indenture);
(8) certain events of bankruptcy, insolvency or reorganization of the
Company or a Significant Subsidiary or group of Restricted Subsidiaries
that, taken together (as of the latest audited consolidated financial
statements for the Company and its Restricted Subsidiaries), would
constitute a Significant Subsidiary (the "bankruptcy provisions"); or
(9) failure by the Company or any Significant Subsidiary or group of
Restricted Subsidiaries that, taken together (as of the latest audited
consolidated financial statements for the Company and its Restricted
Subsidiaries), would constitute a Significant Subsidiary to pay final
judgments aggregating in excess of $10.0 million (net of any amounts
that a reputable and creditworthy insurance company has acknowledged
liability for in writing), which judgments are not paid, discharged or
stayed for a period of 60 days (the "judgment default provision").
However, a default under clauses (4) and (5) of this paragraph will not
constitute an Event of Default until the Trustee or the holders of 25% in
principal amount of the outstanding Notes notify the Company, and the Trustee
in the case of a notice given by the holders, of the default and the Company
does not cure such default within the time specified in clauses (4) and (5) of
this paragraph after receipt of such notice.
If an Event of Default (other than an Event of Default described in clause
(8) above) occurs and is continuing, the Trustee by notice to the Company, or
the holders of at least 25% in principal amount of the outstanding Notes by
notice to the Company and the Trustee, may, and the Trustee at the request of
such holders shall, declare the principal of, premium, if any, and accrued and
unpaid interest, if any, on all the Notes to be due and payable. Upon such a
declaration, such principal, premium and accrued and unpaid interest will be
due and payable immediately. In the event of a declaration of acceleration of
the Notes because an Event of Default described in clause (6) under "Events of
Default" has occurred and is continuing, the declaration of acceleration of the
Notes shall be automatically annulled if the event of default or payment
default triggering such Event of Default pursuant to clause (6) shall be
remedied or cured by the Company or a Restricted Subsidiary of the Company or
waived by the holders of the relevant Indebtedness within 20 days after the
declaration of acceleration with respect thereto and if (1), the annulment of
the acceleration of the Notes would not conflict with any judgment or decree of
a court of competent jurisdiction and (2) all existing Events of Default,
except nonpayment of principal, premium or interest on the Notes that became
due solely because of the acceleration of the Notes, have been cured or waived.
If an Event of Default described in clause (8) above occurs and is continuing,
the principal of, premium, if any, and accrued and unpaid interest on all the
Notes will become and be immediately due and payable without any declaration or
other act on the part of the Trustee or any holders. The holders of a majority
in principal amount of the outstanding Notes may waive all past defaults
(except with respect to nonpayment of principal, premium or interest) and
rescind any such acceleration with respect to the Notes and its consequences if
(1) rescission would not conflict with any judgment or decree of a court of
competent jurisdiction and (2) all existing Events of Default, other than the
nonpayment of the principal of, premium, if any, and interest on the Notes that
have become due solely by such declaration of acceleration, have been cured or
waived.
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Subject to the provisions of the Indenture relating to the duties of the
Trustee, if an Event of Default occurs and is continuing, the Trustee will be
under no obligation to exercise any of the rights or powers under the Indenture
at the request or direction of any of the holders unless such holders have
offered to the Trustee reasonable indemnity or security against any loss,
liability or expense. Except to enforce the right to receive payment of
principal, premium, if any, or interest when due, no holder may pursue any
remedy with respect to the Indenture or the Notes unless :
(1) such holder has previously given the Trustee notice that an Event of
Default is continuing;
(2) holders of at least 25% in principal amount of the outstanding Notes
have requested the Trustee to pursue the remedy;
(3) such holders have offered the Trustee reasonable security or indemnity
against any loss, liability or expense;
(4) the Trustee has not complied with such request within 60 days after the
receipt of the request and the offer of security or indemnity; and
(5) the holders of a majority in principal amount of the outstanding Notes
have not given the Trustee a direction that, in the opinion of the
Trustee, is inconsistent with such request within such 60-day period.
Subject to certain restrictions, the holders of a majority in principal
amount of the outstanding Notes are given the right to direct the time, method
and place of conducting any proceeding for any remedy available to the Trustee
or of exercising any trust or power conferred on the Trustee. The Trustee,
however, may refuse to follow any direction that conflicts with law or the
Indenture or that the Trustee determines is unduly prejudicial to the rights of
any other holder or that would involve the Trustee in personal liability. Prior
to taking any action under the Indenture, the Trustee will be entitled to
indemnification satisfactory to it in its sole discretion against all losses
and expenses caused by taking or not taking such action.
The indenture provides that if a Default occurs and is continuing and is
known to the Trustee, the Trustee must mail to each holder notice of the
Default within 90 days after it occurs. Except in the case of a Default in the
payment of principal of, premium, if any, or interest on any Note, the Trustee
may withhold notice if and so long as a committee of trust officers of the
Trustee in good faith determines that withholding notice is in the interests of
the holders. In addition, the issuers are required try deliver to the Trustee;
within 120 days after the end of each fiscal year, a certificate indicating
whether the signers thereof know of any Default that occurred during the
previous year. The Issuers also are required to deliver to he Trustee within 30
days after the occurrence thereof, written notice of any events which would
constitute certain Defaults, their status and what action the Issuers are to
king or proposes to take in respect thereof.
In the case of any Event of Default occurring by reason of any willful
action (or inaction) taken (or not taken) by or on behalf of the Issuers with
the intention of avoiding payment of the premium that the Issuers would have
had to pay if the Issuers then had elected to redeem the Notes pursuant to the
optional redemption provisions of the Indenture or were required to repurchase
the Notes, an equivalent premium shall also become and be immediately due and
payable to the extent permitted by law upon the acceleration of the Notes. If
an Event of Default occurs prior to July 1, 2007 by reason of any willful
action (or inaction) taken (or not taken) by or on behalf of the issuers with
the intention of avoiding the prohibition on redemption of the Notes prior to
July 1, 2007, the premium specified in the Indenture far the period commencing
July 1, 2007 shall also become immediately due and payable to the extent
permitted by law upon the acceleration of the Notes.
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Amendments and Waivers
Subject to certain exceptions the Indenture may be amended with the consent
of the holders of 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, Notes) and, subject to certain
exceptions, any past default or compliance with any provisions may be waived
with the consent of the holders of 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 far, Notes).
However, without the consent of each holder of an outstanding Note affected, no
amendment may, among other things:
(1) reduce the amount of Notes whose holders must consent to an amendment;
(2) reduce the stated rate of or extend the stated time for payment of
interest on any Note;
(3) reduce the principal of or extend the Stated Maturity of any Note;
(4) reduce the premium payable upon the redemption or repurchase of any
Note or change the time at which any Note may be redeemed or
repurchased as described above under "Optional Redemption;" "Change of
Control," "Certain Covenants--Limitation on Sales of Assets and
Subsidiary Stock" or any similar provision, whether through an
amendment or waiver of provisions in the covenants, definitions or
otherwise;
(5) make any Note payable in money other than that stated in the Note;
(6) impair the right of any holder to receive payment of, premium, if any,
principal of and interest on such holder's Notes on or after the due
dates therefor or to institute suit for the enforcement of any payment
on or with respect to such holder's Notes;
(7) reduce the relative ranking of any Notes or Subsidiary Guarantees; or
(8) make any change in the amendment provisions which require each holder's
consent or in the waiver provisions.
Without the consent of any holder, the Issuers, the Subsidiary Guarantors
and the Trustee may amend the Indenture to:
(1) cure any ambiguity, omission, defect or inconsistency;
(2) provide for the assumption by a successor corporation, partnership,
trust or limited liability company of the obligations of the Issuers
under the Indenture;
(3) provide for uncertificated Notes in addition to or in place of
certificated Notes (provided 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);
(4) add or release Subsidiary Guarantees pursuant to the terms of the
Indenture;
(5) secure the Notes;
(6) add to the covenants of the Company and the Subsidiary Guarantors for
the benefit of the holders or surrender any right or power conferred
upon the Company;
(7) make any change that does not adversely affect the rights of any
holder; or
(8) comply with any requirement of the Commission in connection with the
quaIification of the Indenture under the Trust Indenture Act.
However, no amendment may be made to the subordination provisions of the
Indenture that adversely affects the rights of any holder of Senior
Indebtedness then outstanding unless the holders of such Senior Indebtedness
(or any group or representative thereof authorized to give a consent)
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consent to such change. In addition, any amendment to the subordination
provisions of the Indenture that adversely affects the rights of any holder of
the Notes will require the consent of the holders of at least 66 2/3% in
aggregate principal amount of the Notes then outstanding.
The consent of the holders is not necessary under the Indenture to approve
the particular form of any proposed amendment. It is sufficient if such consent
approves the substance of the proposed amendment. After an amendment under the
Indenture becomes effective, the Company is required to mail to the holders a
notice briefly describing such amendment. However, the failure to give such
notice to all the holders, or any defect therein, will not impair or affect the
validity of the amendment.
Defeasance
The Issuers at any time may terminate aII their obIigations under the Notes
and the Indenture and all obligations of the Subsidiary Guarantors under the
Subsidiary Guarantees and the Indenture ("legal defeasance"), except for
certain obligations, including those respecting the defeasance trust and
obligations to register the transfer or exchange of the Notes, to replace
mutilated, destroyed, lost or stolen Notes and to maintain a registrar and
paying agent in respect of the Notes.
The Issuers at any time may terminate their and the Subsidiary Guarantors
obligations under covenants described under "Certain Covenants" (other than
"Merger and Consolidation"), the operation of the cross-default upon a payment
default, cross acceleration provisions, the bankruptcy provisions with respect
to Significant Subsidiaries and the judgment default provision described under
"Events of Default" above and the limitations contained in clause (3) under
"Certain Covenants--Merger and Consolidation" above ("covenant defeasance").
The Issuers may exercise their legal defeasance option notwithstanding the
prior exercise of a covenant defeasance option. If the Issuers exercise their
legal defeasance option, payment of the Notes may not be accelerated because of
an Event of Default with respect thereto. If the Issuers exercise their
covenant defeasance option, payment of the Notes may not be accelerated because
of an Event of Default specified in clause (4), (5), (6), (8) (with respect
only to Significant Subsidiaries) or (9) under "Events of Default" above or
because of the failure of the Company to comply with clause (3) under "Certain
Covenants--Merger and Consolidation" above.
In order to exercise either defeasance option, the Issuers or any
Subsidiary Guarantor must irrevocably deposit in trust (the "defeasance trust")
with the Trustee money or U.S. Government Obligations for the payment of
principal, premium, if any, and interest on the Notes to redemption or
maturity, as the case may be, and must comply with certain other conditions,
including delivery to the Trustee of an Opinion of Counsel (subject to
customary exceptions and exclusions) to the effect that holders of the Notes
will not recognize income, gain or loss for Federal income tax purposes as a
result of such deposit and defeasance and will be subject to Federal income tax
on the same amount and in the same manner and at the same times as would have
been the case if such deposit and defeasance had not occurred. In the case of
legal defeasance only, such Opinion of Counsel must be based on a ruling of the
Internal Revenue Service or other change in applicable Federal income tax law.
Satisfaction and Discharge
The Indenture will be discharged and will cease to be of further effect
(except as to surviving rights of registration of transfer or exchange of the
Notes, as expressly provided for in the Indenture) as to all outstanding Notes
and the Subsidiary Guarantees when:
(1) either (a) all the Notes theretofore authenticated and delivered
(except lost, stolen or destroyed Notes which have been replaced or
paid and Notes for whose payment money or
122
certain United States governmental obligations have theretofore been
deposited in trust or segregated and held in trust by the Issuers and
thereafter repaid to the Issuers or discharged from such trust) have
been delivered to the Trustee for cancellation or (b) all Notes not
theretofore delivered to the Trustee for cancellation have become due
and payable or will become due and payable at their Stated Maturity
within one year, or are to be called for redemption within one year
under arrangements satisfactory to the Trustee for the giving of notice
of redemption by the Trustee in the name, and at the expense, of the
Issuers, and the Issuers or the Subsidiary Guarantors have irrevocably
deposited or caused to be deposited with the Trustee funds or U.S.
Government Obligations, or a combination thereof, in an amount
sufficient to pay and discharge the entire indebtedness on the Notes
not theretofore delivered to the Trustee for cancellation, for
principal of and premium, if any, on and interest on the Notes to the
date of deposit (in the case of Notes which have become due and
payable) or to the Stated Maturity or redemption date, as the case may
be, together with instructions from the issuers irrevocably directing
the Trustee to apply such funds to the payment thereof at maturity or
redemption, as the case may be;
(2) the Issuers or the Subsidiary Guarantors have paid all other sums then
due and payable under the Indenture by the lssuers; and
(3) the lssuers have delivered to the Trustee an Officers' Certificate and
an Opinion of Counsel, which, taken together, state that all conditions
precedent under the Indenture relating to the satisfaction and
discharge of the indenture have been complied with.
No Personal Liability of Directors, Officers, Employees, Partners and
Stockholders
No director, officer, employee, incorporator, partner or stockholder of the
Company, Plains E&P Company or any Subsidiary Guarantor, as such, shall have
any liability for any obligations of the Company, Plains E&P Company or the
Subsidiary Guarantors under the Notes, the Indenture, the Subsidiary Guarantees
or for any claim based on, in respect of, or by reason of, such obligations or
their creation. Each holder by accepting a Note waives and releases all such
liability. The waiver and release are part of the consideration for issuance of
the Notes. Such waiver may not be effective to waive liabilities under the
federal securities laws and it is the view of the Commission that such a waiver
is against public policy.
Concerning the Trustee
JPMorgan Chase Bank is the Trustee under the Indenture and has been
appointed by the Issuers as Registrar and Paying Agent with regard to the Notes.
Governing Law
The Indenture provides that it, the Notes and the Subsidiary Guarantees
will be governed by, and construed in accordance with the laws of the State of
New York.
Certain Definitions
"Additional Assets" means:
(1) any property or assets (other than indebtedness and Capital Stock) to
be used by the Company or a Restricted Subsidiary in a Related Business;
(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a
result of the acquisition of such Capital Stock by the Company or a
Restricted Subsidiary of the Company; or
123
(3) Capital Stock constituting a minority interest in any Person that at
such time is a Restricted Subsidiary of the Company;
provided, however, that, in the case of clauses (2) and (3), such Restricted
Subsidiary is primarily engaged in a Related Business.
"Adjusted Consolidated Net Tangible Assets" means (without duplication), as
of the date of determination, the remainder of,
(a) the sum of:
(i) discounted future net revenues from proved\\.\\oil and gas
reserves of the Company and its Restricted Subsidiaries calculated
in accordance with SEC guidelines before any provincial,
territorial, state, Federal or foreign income taxes, as estimated
by the Company in a reserve report prepared as of the end of the
Company's most recently completed fiscal year for which audited
financial statements are available and giving effect
to/-/applicable Commodity Agreements, as increased by, as of the
date of determination, the estimated discounted future net
revenues from
(A) estimated proved oil and gas reserves acquired since such year
end, which reserves were not reflected in such year end
reserve report, and
(B) estimated oil and gas reserves attributable to upward
revisions of estimates of proved oil and gas reserves since
such year end due to exploration, development or exploitation
activities, in each case calculated in accordance with SEC
guidelines (utilizing the prices for the fiscal quarter ending
prior to the date of determination and giving effect to
applicable Commodity Agreements),
and decreased by, as of the date of determination, the estimated
discounted future net revenues from
(C) estimated proved oil and gas reserves produced or disposed of
since such year end, and
(D) estimated oil and gas reserves attributable to downward
revisions of estimates of proved oil and gas reserves since
such year end due to changes in geological conditions or other
factors which would, in accordance with standard industry
practice, cause such revisions, in each case calculated on a
pre-tax basis and substantially in accordance with SEC
guidelines (utilizing the prices for the fiscal quarter ending
prior to the date of determination and giving effect to
applicable Commodity Agreements), in each case as estimated by
the Company's petroleum engineers or any independent petroleum
engineers engaged by the Company for that purpose;
(ii)the capitalized costs that are attributable to oil and gas
properties of the Company and its Restricted Subsidiaries to which
no proved oil and gas reserves are attributable, based on the
Company's books and records as of a date no earlier than the date
of the Company's latest available annual or quarterly financial
statements;
(iii)the Net Working Capital on a date no earlier than the date of the
Company's latest annual or quarterly financial statements; and
124
(iv)the greater of
(A) the net book value of other tangible assets of the Company and
its Restricted Subsidiaries, as of a date no earlier than the
date of the Company's latest annual or quarterly financial
statement, and
(B) the appraised value, as estimated by independent appraisers,
of other tangible assets of the Company and its Restricted
Subsidiaries, as of a date no earlier than the date of the
Company's latest audited financial statements (provided that
the Company shall not be required to obtain such appraisal
solely for the purpose of determining this value); minus
(b) the sum of:
(i) Minority Interests;
(ii)any net gas balancing liabilities of the Company and its
Restricted Subsidiaries reflected in the Company's latest audited
financial statements;
(iii)to the extent included in (a)(i) above, the discounted future net
revenues, calculated in accordance with SEC guidelines (utilizing
the prices utilized in the Company's year end reserve report),
attributable to reserves which are required to be delivered to
third parties to fully satisfy the obligations of the Company and
its Restricted Subsidiaries with respect to Volumetric Production
Payments (determined, if applicable, using the schedules specified
with respect thereto); and
(iv)the discounted future net revenues, calculated in accordance with
SEC guidelines, attributable to reserves subject to
Dollar-Denominated Production Payments which, based on the
estimates of production and price assumptions included in
determining the discounted future net revenues specified in (a)(i)
above, would be necessary to fully satisfy the payment obligations
of the Company and its Subsidiaries with respect to
Dollar-Denominated Production Payments (determined, if applicable,
using the schedules specified with respect thereto).
If the Company changes its method of accounting from the full cost or a
similar method to the successful efforts method of accounting, "Adjusted
Consolidated Net Tangible Assets" will continue to be calculated as if the
Company were still using the full cost or a similar method of accounting.
"Adjusted Net Assets" of a Subsidiary Guarantor at any date means the
amount by which the fair value of the properties and assets of such Subsidiary
Guarantor exceeds the total amount of liabilities, including, without
limitation, contingent liabilities (after giving effect to all other fixed and
contingent liabilities incurred or assumed on such date), but excluding
liabilities under its Subsidiary Guarantee, of such Subsidiary Guarantor at
such date.
"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 the purposes of this definition,
"control" when used with respect to any Person means the power to direct the
management and policies of such Person, directly or indirectly, whether through
the ownership of voting securities, by contract or otherwise; and the terms
"controlling" and "controlled" have meanings correlative to the foregoing.
"Asset Disposition" means any direct or indirect sale, lease (other than an
operating lease entered into in the ordinary course of business), transfer,
issuance or other disposition, or a series of related sales, leases, transfers,
issuances or dispositions that are part of a common plan, of shares of Capital
Stock of a Subsidiary (other than directors' qualifying shares), property or
other assets (each
125
referred to for the purposes of this definition as a "disposition") by the
Company or any of its Restricted Subsidiaries, including any disposition by
means of a merger, consolidation or similar transaction.
Notwithstanding the preceding, the following items shall not be deemed to be
Asset Dispositions:
(1) a disposition by a Restricted Subsidiary to the Company or by the
Company or a Restricted Subsidiary to a Wholly-Owned Subsidiary;
(2) the transfer of cash and Cash Equivalents in the ordinary course of
business;
(3) a disposition of Hydrocarbons or mineral products inventory in the
ordinary course of business;
(4) a disposition of obsolete or worn out equipment or equipment that is no
longer useful in the conduct of the business of the Company and its
Restricted Subsidiaries and that is disposed of in each case in the
ordinary course of business;
(5) transactions permitted under "Certain Covenants--Merger and
Consolidation;"
(6) an issuance of Capital Stock by a Restricted Subsidiary of the Company
to the Company or to a Wholly-Owned Subsidiary;
(7) for purposes of "Certain Covenants--Limitation on Sales of Assets and
Subsidiary Stock" only, the making of a Permitted Investment or a
disposition that constitutes a Restricted Payment permitted under
"Certain Covenants--Limitation on Restricted Payments;"
(8) dispositions of assets with an aggregate fair market value of less than
$1.0 million;
(9) dispositions in connection with Permitted Liens;
(10)any change of Control;
(11)dispositions of defaulted accounts receivable to any collection agency;
(12)the licensing or sublicensing of intellectual property or other general
intangibles and licenses, leases or subleases of other property in the
ordinary course of business and which do not materially interfere with
the business of the Company and its Restricted Subsidiaries;
(13)foreclosure on assets;
(14)the sale or transfer (whether or not in the ordinary course of
business) of crude oil and natural gas properties or direct or indirect
interests in real property; provided, that at the time of such sale or
transfer such properties do not have associated with them any proved
reserves; and
(15)the farm-out, lease or sublease of developed or undeveloped crude oil
and natural gas Property owned or held by the Company or such
Restricted Subsidiary for crude oil and natural gas Property owned or
held by another Person.
"Attributable Indebtedness" in respect of a Sale/Leaseback Transaction
means, as at the time of determination, the present value (discounted at the
interest rate borne by the Notes, compounded semi-annually) of the total
obligations of the lessee for rental payments during the remaining term of the
lease included in such Sale/Leaseback Transaction (including any period for
which such lease has been extended).
"Average Life" means, as of the date of determination, with respect to any
Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum
of the products of the numbers of years from the date of determination to the
dates of each successive scheduled principal payment of such Indebtedness or
redemption or similar payment with respect to such Preferred Stock multiplied
by the amount of such payment by (2) the sum of all such payments.
126
"Bank Indebtedness" means any and all amounts, whether outstanding on the
Issue Date or thereafter Incurred, payable by the Company or any Subsidiary
Guarantor under or in respect of the Senior Credit Agreement and any related
notes, collateral documents, letters of credit and guarantees and any Interest
Rate Agreement entered into with any lender or affiliate of a lender, including
principal, premium, if any, interest (including interest accruing on or after
the filing of any petition in bankruptcy or for reorganization relating to the
Company or any Subsidiary Guarantor at the rate specified therein whether or
not a claim for post filing interest is allowed in such proceedings), fees,
charges, expenses, reimbursement obligations, guarantees and all other amounts
payable thereunder or in respect thereof.
"Board of Directors" means, as to any Person, the board of directors of
such Person or any duly authorized committee thereof; provided that so long as
the Company is a limited partnership, "Board of Directors" means the board of
directors of Stocker Resources, Inc., its general partner, or any duly
authorized committee thereof.
"Capital Stock" of any Person means any and all shares, interests, rights
to purchase, warrants, options, participations or other equivalents of or
interests in (however designated) equity of such Person, including any
Preferred Stock, but excluding any debt securities convertible into such equity.
"Capitalized Lease Obligations" means an obligation that is required to be
classified and accounted for as a capitalized lease for financial reporting
purposes in accordance with GAAP, and the amount of Indebtedness represented by
such obligation will be the capitalized amount of such obligation at the time
any determination thereof is to be made as determined in accordance with GAAP,
and the Stated Maturity thereof will be the date of the last payment of rent or
any other amount due under such lease prior to the first date such lease may be
terminated without penalty.
"Cash equivalents" means:
(1) securities issued or directly and fully guaranteed or insured by the
United States Government or any agency or instrumentality thereof
(provided that the full faith and credit of the United States is
pledged in support thereof), having maturities of not more than one
year from the date of acquisition;
(2) marketable general obligations issued by any state of the United States
of America or any political subdivision of any such state or any public
instrumentality thereof maturing within one year from the date of
acquisition thereof and, at the time of acquisition thereof, having a
credit rating of "A" or better from either Standard & Poor's Ratings
Group or Moody's Investors Service,Inc.;
(3) certificates of deposit, time deposits, eurodollar time deposits,
overnight bank deposits or bankers' acceptances having maturities of
not more than one year from the date of acquisition thereof issued by
any commercial bank the long-term debt of which is rated at the time of
acquisition thereof at least "A" or the equivalent thereof by Standard
& Poor's Ratings Group or "A" or the equivalent thereof by Moody's
Investors Service, Inc., and having combined capital and surplus in
excess of $500 million;
(4) repurchase obligations with a term of not more than seven days for
underlying securities of the types described in clauses (1), (2) and
(3) entered into with any bank meeting the qualifications specified in
clause (3) above;
(5) commercial paper rated at the time of acquisition thereof at least
"A-2" or the equivalent thereof by Standard & Poor's Ratings Group or
"P-2" or the equivalent thereof by Moody's Investors Service, Inc., or
carrying an equivalent rating by a nationally recognized rating agency,
if both of the two named rating agencies cease publishing ratings of
investments, and in either case maturing within one year after the date
of acquisition thereof; and
127
(6) interests in any investment company or money market fund which invests
solely in instruments of the type specified in clauses (1) through (5)
above.
"Change of Control" means:
(1) any "person" or "group" of related persons (as such terms are used in
Sections 13(d) and 14(d) of the Exchange Act) other than Permitted
Holders, is or becomes the beneficial owner (as defined in Rules 13d-3
and 13d-5 under the Exchange Act, except that such person or group
shall be deemed to have "beneficial ownership" of all shares that any
such person or group has the right to acquire, whether such right is
exercisable immediately or only after the passage of time), directly or
indirectly, of more than 40% of the total voting power of the Voting
Stock of the Company (or its successor by merger, consolidation or
purchase of all or substantially all of its assets) (for the purposes
of this clause, such person or group shall be deemed to beneficially
own any Voting Stock of the Company held by an entity, if such person
or group "beneficially owns" (as defined above), directly or
indirectly, more than 40% of the voting power of the Voting Stock of
such entity);
(2) the first day on which a majority of the members of the Board of
Directors of the Company are not Continuing Directors;
(3) 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 Restricted Subsidiaries taken as a Whole to any "person" (as
such term is used in Sections 13(d) and 14(d) of the Exchange Act);
(4) the adoption of a plan or proposal for the liquidation or dissolution
of the company or, for so long as the Company is a partnership, the
general partner of the Company; or
(5) for so long as the Company is a partnership, such time as Plains
Resources Inc. or any of its Subsidiaries ceases to own, directly or
indirectly, the general partner of the Company, or Plains Resources
inc. or its Subsidiaries, or their respective officers, employees or
agents cease to serve as the only general partners of the Company.
Notwithstanding the foregoing, the conversion of the Company into a
corporation will not be a Change of Control unless clause (1) above is
applicable.
"Code" means the Internal Revenue Code of 1986, as amended.
"Commodity Agreements" means, in respect of any Person, any forward
contract, commodity swap agreement, commodity option agreement or other similar
agreement or arrangement designed to protect such Person against fluctuation in
commodity prices.
"Consolidated Coverage Ratio" means as of any date of determination, with
respect to any Person, the ratio of (x) the aggregate amount of consolidated
EBITDA of such Person for the period of the most recent four consecutive fiscal
quarters ending prior to the date of such determination for which financial
statements are in existence to (y) Consolidated Interest Expense for such four
fiscal quarters, provided, however, that:
(1) if the Company or any Restricted Subsidiary:
(a) has Incurred any Indebtedness since the beginning of such period
that remains outstanding on such date of determination or if the
transaction giving rise to the need to calculate the Consolidated
Coverage Ratio is an Incurrence of Indebtedness, Consolidated
EBITDA and Consolidated Interest Expense (taking into account any `
128
Interest Rate Agreements applicable to such lndebtedness) for such
period will be calculated after giving effect on a pro forma basis
to such Indebtedness as if such Indebtedness had been Incurred on
the first day of such period (except that in making such
computation, the amount of lndebtedness under any revolving credit
facility outstanding on the date of such calculation will be
computed based on (i) the average daily balance of such
Indebtedness during such four fiscal quarters or such shorter
period for which such facility was outstanding or (ii) if such
facility was created after the end of such four fiscal quarters,
the average daily balance of such Indebtedness during the period
from the date of creation of such facility to the date of such
calculation) and the discharge of any other Indebtedness repaid,
repurchased, defeased or otherwise discharged with the proceeds of
such new Indebtedness as if such discharge had occurred on the
first day of such period; or
(b) has repaid, repurchased, defeased or otherwise discharged any
Indebtedness since the beginning of the period that is no longer
outstanding on such date of determination or if the transaction
giving rise to the need to calculate the Consolidated Coverage
Ratio involves a discharge of Indebtedness (in each case other
than Indebtedness incurred under any revolving credit facility
unless such Indebtedness has been permanently repaid and the
related commitment terminated), Consolidated EBITDA and
Consolidated lnterest Expense for such period will be calculated
after giving effect on a pro forma basis to such discharge of such
Indebtedness, including with the proceeds of such new
Indebtedness, as if such discharge had occurred on the first day
of such period;
(2) if since the beginning of such period the Company or any Restricted
Subsidiary will have made any Asset Disposition or if the transaction
giving rise to the need to calculate the Consolidated Coverage Ratio is
an Asset Disposition:
(a) the Consolidated EBITDA for such period will be reduced by an
amount equal to the Consolidated EBITDA (if positive) directly
attributable to the assets which are the subject of such. Asset
Disposition for such period or increased by an amount equal to the
Consolidated EBITDA (if negative) directly attributable thereto
for such period; and
(b) Consolidated Interest Expense for such period will be reduced by
an amount equal to the Consolidated Interest Expense directly
attributable to any Indebtedness of the Company or any Restricted
Subsidiary repaid, repurchased, defeased or otherwise discharged
with respect to the Company and its continuing Restricted
Subsidiaries in connection with such Asset Disposition for such
period (or, if the Capital Stock of any Restricted Subsidiary is
sold, the Consolidated Interest Expense for such period directly
attributable to the indebtedness of such Restricted Subsidiary to
the extent the Company and its continuing Restricted Subsidiaries
are no longer liable for such Indebtedness after such sale);
(3) if since the beginning of such period the Company or any Restricted
Subsidiary (by merger or otherwise) will have made an Investment in any
Restricted Subsidiary (or any Person which becomes a Restricted
Subsidiary or is merged with or into the Company) or acquisition of
assets, including any acquisition of assets occurring in connection
with a transaction causing a calculation to be made hereunder,
including a single asset or all or substantially all of an operating
unit, division or Line of business, Consolidated EBITDA and
Consolidated Interest Expense for such period will be calculated after
giving pro forma effect thereto (including the Incurrence of any
Indebtedness) as if such Investment or acquisition occurred on the
first day of such period; and
(4) if since the beginning of such period any Person (that subsequently
became Restricted Subsidiary or was merged with or into the Company or
any Restricted Subsidiary since the
129
beginning of such period) will have made any Asset Disposition or any
Investment or acquisition of assets that would have required an
adjustment pursuant to clause (2) or (3) above if made by the Company
or a Restricted Subsidiary during such period, Consolidated EBITDA and
Consolidated Interest Expense for such period will be calculated after
giving pro forma effect thereto, as if such Asset Disposition or
Investment or acquisition of assets occurred on the first day of such
period.
For purposes of this definition, whenever pro forma effect is to be given
to any calculation under, this definition, the pro forma calculations will be
determined in good faith by a responsible financial or accounting officer of
the Company (including pro forma expense and cost reductions calculated on a
basis consistent with Regulation S-X under the Securities Act). If any
Indebtedness bears a floating rate of interest and is being given pro forma
effect, the interest expense on such lndebtedness will be calculated as if the
rate in effect on the date of determination had been the applicable rate for
the .entire period (taking into account any Interest Rate Agreement applicable
to such Indebtedness if such interest Rate Agreement has a remaining term in
excess of 12 months).
"Consolidated EBITDA" for any period means, without duplication, the
Consolidated Net Income for such period, plus the following to the extent
deducted in calculating such Consolidated Net Income:
(1) Consolidated Interest Expense, less the consolidated: interest expense
of such Person and its Restricted Subsidiaries that was capitalized and
not deducted during such period;
(2) Consolidated Income Taxes;
(3) consolidated depreciation expense;
(4) consolidated amortization of intangibles;
(5) exploration and abandonment expense (if applicable); and
(6) other non-cash charges reducing Consolidated Net Income (excluding any
such non-cash charge to the extent 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 not included in
the prior period calculation),
and less, to the extent included in calculating such Consolidated Net Income
and in excess of any costs or expenses attributable thereto and deducted in
calculating such Consolidated Net Income, the sum of (x) the amount of deferred
revenues that are amortized during such period and are attributable to reserves
that are subject to Volumetric Production Payments, and (y) amounts recorded in
accordance with GAAP as repayments of principal and interest pursuant to
Dollar-Denominated Production Payments. Notwithstanding the preceding sentence,
clauses (2) through (5) relating to amounts of a Restricted Subsidiary of a
Person will be added to Consolidated Net Income to compute Consolidated EBITDA
of such Person only to the extent (and in the same proportion) that the net
income (loss) of such Restricted Subsidiary was included in calculating the
Consolidated Net Income of such Person and, to the extent the amounts set forth
in clauses (2) through (5) are in excess of those necessary to offset a net
loss of such Restricted Subsidiary or if such Restricted Subsidiary has net
income for such period included in Consolidated Net Income, only if a
corresponding amount would be permitted at the date of determination to be
dividended to the Company by such Restricted Subsidiary without prior approval
(that has not been obtained), 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 Income Taxes" means, with respect to any Person for any
period, taxes imposed upon such Person or other payments required to be made by
such Person by any governmental authority which taxes or other payments are
calculated by reference to the income or profits of such
130
Person or such Person and its Restricted Subsidiaries (to the extent such
income or profits were included in computing Consolidated Net Income for such
period), regardless of whether such taxes or payments are required to be
remitted to any governmental authority.
"Consolidated Interest Expense" means, for any period, the total interest
expense of the Company and its consolidated Restricted Subsidiaries, whether
paid or accrued (except to the extent accrued in a prior period), plus, to the
extent not included in such interest expense:
(1) interest expense attributable to Capitalized Lease Obligations and the
interest portion of rent expense associated with Attributable
Indebtedness in respect of the relevant lease giving rise thereto,
determined as if such lease were a capitalized lease in accordance with
GAAP and the interest component of any deferred payment obligations;
(2) amortization of debt discount and debt issuance cost;
(3) non-cash interest expense;
(4) commissions, discounts and other fees and charges owed with respect to
letters of credit and bankers' acceptance financing;
(5) the interest expense on Indebtedness of another Person that is
Guaranteed by such Person or one of its Restricted Subsidiaries or
secured by a Lien on assets of such Person or one of its Restricted
Subsidiaries;
(6) net payments pursuant to Hedging Obligations (including amortization of
fees);
(7) the consolidated interest expense of such Person and its Restricted
Subsidiaries that was capitalized during such period;
(8) the product of (a) all dividends paid or payable in cash, Cash
Equivalents or Indebtedness or accrued during such period on any series
of Disqualified Stock of such Person or on Preferred Stock of its
Restricted Subsidiaries payable to a party other than the Company or a
Restricted Subsidiary, times (b) a fraction, the numerator of which is
one and the denominator of which is one minus the then current combined
federal, state, provincial and local statutory tax rate of such Person,
expressed as a decimal, in each case, on a consolidated basis and in
accordance with GAAP; and
(9) the cash contributions to any employee stock ownership plan or similar
trust to the extent such contributions are used by such plan or trust
to pay interest or fees to any Person (other than the Company) in
connection with Indebtedness incurred by such plan or trust; provided,
however, that there will be excluded therefrom any such interest
expense of any Unrestricted Subsidiary to the extent the related
Indebtedness is not Guaranteed or paid by the Company or any Restricted
Subsidiary.
For purposes of the foregoing, total interest expense will be determined
after giving effect to any net payments made or received by the Company and its
Subsidiaries with respect to Interest Rate Agreements; provided, however, that
"Consolidated Interest Expense" shall not include (a) any Consolidated Interest
Expense with respect to any Production Payments and Reserve Sales, (b) to the
extent included in total interest expense, write-off of deferred financing
costs of such Person or (c) accretion of interest charges on future plugging
and abandonment obligations, future retirement benefits and other obligations
that do not constitute Indebtedness.
"Consolidated Net Income" means, for any period, the net income (loss) of
the Company and its consolidated Restricted Subsidiaries determined in
accordance with GAAP; provided, however, that there will not be included in
such Consolidated Net Income:
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(1) any net income (loss) of any Person if such Person is not a Restricted
Subsidiary, except that:
(a) subject to the limitations contained in clauses (4), (5) and (6)
below, the Company's equity in the net income of any such Person
for such period will be included in such Consolidated Net Income
up to the aggregate amount of cash actually distributed by such
Person during such period to the Company or a Restricted
Subsidiary as a dividend or other distribution (subject, in the
case of a dividend or other distribution to a Restricted
Subsidiary, to the limitations contained in clause (3) below); and
(b) the Company's equity in a net loss of any such Person (other than
an Unrestricted Subsidiary) for such period will be included in
determining such Consolidated Net Income to the extent such loss
has been funded with cash from the Company or a Restricted
Subsidiary;
(2) any net income (loss) of any Person acquired by the Company or a
Subsidiary in a pooling of interests transaction for any period prior
to the date of such acquisition;
(3) any net income (but not loss) of any Restricted Subsidiary if such
Subsidiary is subject to restrictions, directly or indirectly; on the
payment of dividends or the making of distributions by such Restricted
Subsidiary, directly or indirectly, to the Company, except that:
(a) subject to the limitations contained in clauses (4), (5) and (6)
below, the Company's equity in the net income of any such
Restricted Subsidiary for such period will be included in such
Consolidated Net Income up to the aggregate amount of cash that
could have been distributed by such Restricted Subsidiary during
such period to the Company or another Restricted Subsidiary as a
dividend (subject, in the case of a dividend to another Restricted
Subsidiary, to the limitation contained, in this clause); and
(b) the Company's equity in a net loss of any such Restricted
Subsidiary for such period will be included in determining such
Consolidated Net Income;
(4) any gain (loss) realized upon the sale or other disposition of any
property, plant or equipment of the Company or its consolidated
Restricted Subsidiaries (including pursuant to any Sale/Leaseback
Transaction) which is not sold or otherwise disposed of in the ordinary
course of business and any gain (loss) realized upon the sale or other
disposition of any Capital Stock of any Person;
(5) any extraordinary gain or loss;
(6) the cumulative effect of a change in accounting principles;
(7) any asset impairment writedowns on Oil and Gas Properties under GAAP or
SEC guidelines; and
(8) any unrealized non-cash gains or losses on charges in respect of
Hedging Obligations (including those resulting from the application of
SFAS 133).
"Consolidated Net Worth" of any Person means the stockholders' equity of
such Person and its Subsidiaries, as determined on a consolidated basis in
accordance with GAAP, less (to the extent included in stockholders' equity)
amounts attributable to Disqualified Stock of such Person or its Subsidiaries.
"Continuing Directors" means as of any date of determination after the
Company is a corporation, any member of the Board of Directors of the Company
who:
(1) was a member of such Board of Directors on the date of conversion of
the Company to a corporation; or
132
(2) was nominated for election or elected to such Board of Directors with
the approval of a majority of the Continuing Directors who were members
of such Board at the time of such nomination or election.
"Currency Agreement" means in respect of a Person any foreign exchange
contract, currency swap agreement or other similar agreement as to which such
Person is a party or a beneficiary.
"Default" means any event which is, or after notice or passage of time or
both would be, an Event of Default.
"Designated Senior Indebtedness" means (1) Bank Indebtedness (to the extent
such Bank Indebtedness constitutes Senior Indebtedness) and (2) any other
Senior Indebtedness 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 $25.0 million and is
specifically designated in the instrument evidencing or governing such Senior
Indebtedness as "Designated Senior Indebtedness" for purposes of the Indenture.
"Disqualified Stock" means, with respect to any Person, any Capital Stock
of such Person which 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:
(1) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise;
(2) is convertible or exchangeable for Indebtedness or Disqualified Stock
(excluding Capital Stock which is convertible or exchangeable solely at
the option of the Company or a Restricted Subsidiary); or
(3) is 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 the date (a) on
which the Notes mature or (b) on which there are no Notes outstanding; provided
that only the portion of Capital Stock which so matures or is mandatorily
redeemable, is so convertible or exchangeable or is so redeemable at the option
of the holder thereof prior to such date will be deemed to be Disqualified
Stock; provided further that any Capital Stock that would constitute
Disqualified Stock solely because the holders thereof have the right to require
the Company to repurchase such Capital Stock upon the occurrence of a change of
control or asset sale (each defined in a substantially identical manner to the
corresponding definitions in the Indenture) shall not constitute Disqualified
Stock if the terms of such Capital Stock (and all such securities into which it
is convertible or for which it is ratable or exchangeable) provide that the
Company may not repurchase or redeem any such Capital Stock (and all such
securities into which it is convertible or for which it is ratable or
exchangeable) pursuant to such provision prior to compliance by the Company
with the provisions of the Indenture described under the captions "Change of
Control" and "Limitation on Sales of Assets and Subsidiary Stock" and such
repurchase or redemption complies with "Certain Covenants--Restricted Payments."
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Equity Offering" means an offering for cash by the Company of its common
Capital Stock, or options, warrants or rights with respect to its common
Capital Stock.
"Foreign Subsidiary" means any Restricted Subsidiary that is not organized
under the laws of the United States of America or any state thereof or the
District of Columbia.
133
"GAAP" means generally accepted accounting principles in the United States
of America as in effect as of the date of the indenture, including those 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 by such other entity as approved by a significant segment of the
accounting profession. All ratios and computations based on GAAP contained in
the Indenture will be computed in conformity with GAAP.
"Guarantee" means any obligation, contingent or otherwise, of any Person
directly or indirectly guaranteeing any Indebtedness of any other Person and
any obligation, direct or indirect, contingent or otherwise, of such Person:
(1) to purchase or pay (or advance or supply funds for the purchase or
payment of) such Indebtedness of such other Person (whether arising by
virtue of partnership arrangements, or by agreement to keep-well, to
purchase assets, goods, securities or services, to take-or-pay, or to
maintain financial statement conditions or otherwise); or
(2) entered into for purposes of assuring in any other manner the obligee
of such Indebtedness of the payment thereof or to protect such obligee
against loss in respect thereof (in whole or in part);
provided, however, that the term "Guarantee" will not include endorsements for
collection or deposit in the ordinary course of business. The term "Guarantee"
used as a verb has a corresponding meaning.
"Guarantor Senior Indebtedness" means, with respect to a Subsidiary
Guarantor, the following obligations, whether outstanding on the date of the
Indenture or thereafter issued, without duplication:
(1) any Guarantee of the Bank Indebtedness by such Subsidiary Guarantor and
all other Guarantees by such Subsidiary Guarantor of Senior
Indebtedness of the Issuers or Guarantor Senior Indebtedness of any
other Subsidiary Guarantor; and
(2) all obligations consisting of principal of and premium, if any, accrued
and unpaid interest on, and fees and other amounts relating to, the
Bank Indebtedness and all other Indebtedness of the Subsidiary
Guarantor. Guarantor Senior Indebtedness includes interest accruing on
or after the filing of any petition in bankruptcy or for reorganization
relating to the Subsidiary Guarantor regardless of whether post-filing
interest is allowed in such proceeding.
Notwithstanding anything to the contrary in the preceding paragraph,
Guarantor Senior Indebtedness will not include:
(1) any Indebtedness which, in the instrument creating or evidencing the
same or pursuant to which the same is outstanding, it is provided that
the obligations in respect of such Indebtedness are not superior in
right of, or are subordinate to, payment of the Notes and the
Subsidiary Guarantee;
(2) any obligations of such Subsidiary Guarantor to another Subsidiary or
the Company;
(3) any liability for Federal, state, foreign, local or other taxes owed or
owing by such Subsidiary Guarantor;
(4) any accounts payable or other liability to trade creditors arising in
the ordinary course of business (including Guarantees thereof or
instruments evidencing such liabilities);
(5) any Indebtedness, Guarantee or obligation of such Subsidiary Guarantor
that is expressly subordinate or junior in right of payment to any
other Indebtedness, Guarantee or obligation of such Subsidiary
Guarantor, including, without limitation, any Guarantor Senior
Subordinated Indebtedness and Guarantor Subordinated Obligations of
such Guarantor; or
(6) any Capital Stock.
134
"Guarantor Senior Subordinated Indebtedness" means, with respect to a
Subsidiary Guarantor, the obligations of such Subsidiary Guarantor under the
Subsidiary Guarantee and any other Indebtedness of such Subsidiary Guarantor
that specifically provides that such Indebtedness is to rank equally in right
of payment with the obligations of such Subsidiary Guarantor under its
Subsidiary Guarantee and is not expressly subordinated by its terms in right of
payment to any Indebtedness of such Subsidiary Guarantor which is not Guarantor
Senior Indebtedness of such Subsidiary Guarantor.
"Guarantor Subordinated Obligation" means any Indebtedness of a Subsidiary
Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which
is subordinate or junior in right of payment to the Subsidiary Guarantee of
such Subsidiary Guarantor pursuant to a written agreement.
"Hedging Obligations" of any Person means the obligations of such Person
pursuant to any Interest Rate Agreement or Currency Agreement.
"Hydrocarbons" means oil, gas, casinghead gas, drip gasoline, natural
gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and
all constituents, elements or compounds thereof and products refined or
processed therefrom.
"Incur" means issue, create, assume, Guarantee, incur or otherwise become
liable for; provided, however, that any Indebtedness or Capital Stock of a
Person existing at the time such person becomes a Restricted Subsidiary
(whether by merger, consolidation, acquisition or otherwise) will be deemed to
be incurred by such Restricted Subsidiary at the time it becomes a Restricted
Subsidiary; and the terms "Incurred" and "Incurrence" have meanings correlative
to the foregoing.
"Indebtedness" means, with respect to any Person on any date of
determination (without duplication):
(1) the principal of and premium (if any) in respect of indebtedness of
such Person for borrowed money;
(2) the principal of and premium (if any) in respect of obligations of such
Person evidenced by bonds, debentures, notes or other similar
instruments;
(3) the principal component of all obligations of such Person in respect of
letters of credit, bankers' acceptances or other similar instruments
(including reimbursement obligations with respect thereto except to the
extent such reimbursement obligation relates to a trade payable and
such obligation is satisfied within 30 days of Incurrence);
(4) the principal component of all obligations of such Person to pay the
deferred and unpaid purchase price of property (except trade payables),
which purchase price is due more than nine months after the date of
placing such property in service or taking delivery and title thereto;
(5) Capitalized Lease Obligations and all Attributable Indebtedness of such
Person;
(6) the principal component or liquidation preference of all obligations of
such Person with respect to the redemption, repayment or other
repurchase of any Disqualified Stock or, with respect to any
Subsidiary, any Preferred Stock (but excluding, in each case, any
accrued dividends);
(7) the principal component of all Indebtedness of other Persons secured by
a Lien on any asset of such Person, whether or not such Indebtedness is
assumed by such Person; provided, however, that the amount of such
Indebtedness will be the lesser of (a) the fair market value of such
asset at such date of determination and (b) the amount of such
Indebtedness of such other Persons;
135
(8) the principal component of Indebtedness of other Persons to the extent
Guaranteed by such Person; and
(9) to the extent not otherwise included in this definition, net
obligations of such Person under Currency Agreements and Interest Rate
Agreements (the amount of any such obligations to be equal at any time
to the termination value of such agreement or arrangement giving rise
to such obligation that would be payable by such Person at such time).
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, upon the occurrence of the contingency giving
rise to the obligation, of any contingent obligations at such date.
In addition, "Indebtedness" of any Person shall include Indebtedness
described in the preceding paragraph that would not appear as a liability on
the balance sheet of such Person if:
(1) such indebtedness is the obligation of a partnership or joint venture
that is not a Restricted Subsidiary (a "Joint Venture");
(2) such Person or a Restricted Subsidiary of such Person is a general
partner of the Joint Venture (a "General Partner"); and
(3) there is recourse, by contract or operation of law, with respect to the
payment of such Indebtedness to property or assets of such Person or a
Restricted Subsidiary of such Person; and then such Indebtedness shall
be included in an amount not to exceed:
(a) the lesser of (i) the net assets of the General Partner and (ii)
the amount of such obligations to the extent that there is
recourse, by contract or operation of law, to the property or
assets of such Person or a Restricted Subsidiary of such Person; or
(b) if less than the amount determined pursuant to clause (a)
immediately above, the actual amount of such Indebtedness that is
recourse to such Person or a Restricted Subsidiary of such Person,
if the Indebtedness is evidenced by a writing and is for a
determinable amount and the related interest expense shall be
included in Consolidated Interest Expense to the extent actually
paid by the Company or its Restricted Subsidiaries.
Notwithstanding the preceding, Indebtedness shall not include (a) accounts
payable arising in the ordinary course of business, (b) any obligations in
respect of prepayments for gas or oil production or gas or oil imbalances, and
(c) Production Payments and Reserve Sales.
"Interest Rate Agreement" means with respect to any Person any interest
rate protection agreement, interest rate future agreement, interest rate option
agreement, interest rate swap agreement, interest rate cap agreement, interest
rate collar agreement, interest rate hedge agreement or other similar agreement
or arrangement as to which such Person is party or a beneficiary.
"Investment" means, with respect to any Person, all investments by such
Person in other Persons (including Affiliates) in the form of any direct or
indirect advance, loan (other than advances to customers in the ordinary course
of business) or other extension of credit (including by way of Guarantee or
similar arrangement, but excluding any debt or extension of credit represented
by a bank deposit other than a time deposit) or capital contribution to (by
means of any transfer of cash or other property to others or any payment for
property or services for the account or use of others), or any purchase or
acquisition of Capital Stock, Indebtedness or other similar instruments issued
by, such Person and all other items that are or would be classified as
investments on a balance sheet prepared in accordance with GAAP; provided that:
136
(1) Hedging Obligations entered into in the ordinary course of business and
in compliance with the Indenture;
(2) endorsements of negotiable instruments and documents in the ordinary
course of business; and
(3) an acquisition of assets, Capital Stock or other securities by the
Company or a Subsidiary for consideration consisting exclusively of
common equity securities of the Company,
shall in each case not be deemed to be an Investment.
For purposes of "Certain covenants--Limitation on restricted payments,"
(1) "Investment" will include the portion (proportionate to the Company's
equity interest in a Restricted Subsidiary to be designated as an
Unrestricted Subsidiary) of the fair market value of the net assets of
such Restricted Subsidiary of the Company at the time that such
Restricted Subsidiary is designated an Unrestricted Subsidiary;
provided, however, that upon a redesignation of such Subsidiary as a
Restricted Subsidiary, the Company will be deemed to continue to have a
permanent "Investment" in an Unrestricted Subsidiary in an amount (if
positive) equal to (a) the Company's "Investment" in such Subsidiary at
the time of such redesignation less (b) the portion (proportionate to
the Company's equity interest in such Subsidiary) of the fair market
value of the net assets (as conclusively determined by the Board of
Directors of the Company in good faith) of such Subsidiary at the time
that such Subsidiary is so re-designated a Restricted Subsidiary; and
(2) any property transferred to or from an Unrestricted Subsidiary will be
valued at its fair market value at the time of such transfer, in each
case as determined in good faith by the Board of Directors of the
Company.
If the Company or any Restricted Subsidiary of the Company sells or
otherwise disposes of any Voting Stock of any 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 (as conclusively determined by the Board of Directors of
the Company in good faith) of the Capital Stock of such Subsidiary not sold or
disposed of.
"Investment Grade Rating" means a rating equal to or higher than Baa3 (or
the equivalent) by Moody's Investors Service, Inc. or BBB- (or the equivalent)
by Standard & Poor's Ratings Group.
"Issue Date" means the date on which the Initial Notes are originally
issued.
"Junior Securities" means securities that are subordinated to the Senior
Indebtedness at least to the same extent as the Notes.
"Lien" means any mortgage, pledge, security interest, encumbrance, lien or
charge of any kind (including any conditional sale or other title retention
agreement or lease in the nature thereof).
"Minority Interest" means the percentage interest represented by any shares
of stock of any class of Capital Stock of a Restricted Subsidiary of the
Company that are not owned by the Company or a Restricted Subsidiary of the
Company.
"Net Available Cash" from an Asset Disposition means cash payments received
(including any cash payments received by way of deferred payment of principal
pursuant to a note or installment
137
receivable or otherwise, but only as and when received, but excluding any other
consideration received in the form of assumption by the acquiring Person of
Indebtedness or other obligations relating to the properties or assets that are
the subject of such Asset Disposition or received in any other noncash form)
therefrom, in each case net of:
(1) all legal, accounting, investment banking, title and recording tax
expenses, commissions and other fees and expenses incurred, and all
Federal, state, provincial, foreign and local taxes, required to be
paid or accrued as a liability under GAAP (after taking into account
any available tax credits or deductions and any tax sharing
agreements), as a consequence of such Asset Disposition;
(2) all payments made on any Indebtedness which is secured by any assets
subject to such Asset Disposition, in accordance with the terms of any
Lien upon such assets, or which must by its terms, or in order to
obtain a necessary consent to such Asset Disposition, or by applicable
law be repaid out of the proceeds from such Asset Disposition;
(3) all distributions and other payments required to be made to minority
interest holders in Subsidiaries or joint ventures as a result of such
Asset Disposition; and
(4) the deduction of appropriate amounts to be provided by the seller as a
reserve, in accordance with GAAP, against any liabilities associated
with the assets disposed of in such Asset Disposition and retained by
the Company or any Restricted Subsidiary after such Asset Disposition.
"Net Cash Proceeds" with respect to any issuance or sale of Capital Stock,
means the cash proceeds of such issuance or sale net of attorneys' fees,
accountants' fees, underwriters' or placement agents' fees, listing fees,
discounts or commissions and brokerage, consultant and other fees and charges
actually incurred in connection with such issuance or sale and net of taxes
paid or payable as a result of such issuance or sale (after taking into account
any available tax credit or deductions and any tax sharing arrangements).
"Net Working Capital" means (a) all current assets of the Company and its
Restricted Subsidiaries except current assets from commodity price risk
management activities arising in the ordinary course of business; less (b) all
current liabilities of the Company and its Restricted Subsidiaries, except
current liabilities included in Indebtedness and any current liabilities from
commodity price risk management activities arising in the ordinary course of
business, in each case as set forth in the consolidated financial statements of
the Company prepared in accordance with GAAP.
"Non-Recourse Debt" means Indebtedness:
(1) as to which neither the Company nor any Restricted Subsidiary (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 a
guarantor or otherwise);
(2) 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 Restricted
Subsidiary to declare a default under such other Indebtedness or cause
the payment thereof to be accelerated or payable prior to its stated
maturity; and
(3) the explicit terms of which provide there is no recourse against any of
the assets of the Company or its Restricted Subsidiaries.
"Officer" means the Chairman of the Board, the President, any Vice
President, the Treasurer or the Secretary of an Issuer or, so long as the
Company is a limited partnership, of its general partner.
138
"Officers' Certificate" means a certificate signed by two Officers or by an
Officer and either an Assistant Treasurer or an Assistant Secretary of an
Issuer or, so long as the Company is a limited partnership, of its general
partner.
"Oil and Gas Properties" means all Properties, including equity or other
ownership interests therein, owned by such Person which contain "proved oil and
gas reserves" as defined in Rule 4-10 of Regulation S-X of the Securities Act.
"Opinion of Counsel" means a written opinion from legal counsel who is
acceptable to the Trustee. The counsel may be an employee of or counsel to the
Company or the Trustee.
"PAA" means Plains All American Pipeline, a Delaware limited partnership.
"Permitted Acquisition Indebtedness" means Indebtedness of the Company or
any Restricted Subsidiary to the extent such Indebtedness is incurred to
finance the acquisition of Oil and Gas Properties (and development costs
related thereto) and does not exceed the principal amount of $50.0 million with
respect to any such acquisition transaction or series of related acquisition
transactions if on the date of the incurrence (i) (A) the Adjusted Consolidated
Net Tangible Assets acquired are equal to or greater than 200% of the
Indebtedness incurred, and (B) the Adjusted Consolidated Net Tangible Assets of
Company (after giving effect to such acquisition) are equal to or greater than
125% of the consolidated Indebtedness of the Company and its Restricted
Subsidiaries or (ii) (A) the Property Net Revenue Coverage Ratio would have
been equal to or greater than 2.5 to 1.0, (B) the Adjusted Consolidated Net
Tangible Assets acquired are equal to or greater than 150% of the Indebtedness
incurred, and (C) the Adjusted Consolidated Net Tangible Assets of the Company
(after giving effect to such acquisition) are equal to or greater than 125% of
the consolidated Indebtedness of the Company and its Restricted Subsidiaries.
"Permitted Business Investment" means any investment made in the ordinary
course of, and of a nature that is or shall have become customary in, the
Related Business including investments or expenditures for actively exploiting,
exploring for, acquiring, developing, producing, processing, gathering,
marketing or transporting oil and gas through agreements, transactions,
interests or arrangements which permit one to share risks or costs, comply with
regulatory requirements regarding local ownership or satisfy other objectives
customarily achieved through the conduct of the Related Business jointly with
third parties, including (i) ownership interests in oil and gas properties,
processing facilities, gathering systems, pipelines or ancillary real property
interests and (ii) investments in the form of or pursuant to operating
agreements, processing agreements, farm-in agreements, farm-out agreements,
development agreements, area of mutual interest agreements, unitization
agreements, pooling agreements, joint bidding agreements, service contracts,
joint venture agreements, partnership agreements (whether general or limited),
subscription agreements, stock purchase agreements and other similar agreements
(including for limited liability companies) with third parties, excluding,
however, Investments in corporations other than Restricted Subsidiaries.
"Permitted Holders" means (a) prior to the Spin-off, Plains Resources Inc.
and its Subsidiaries or (b) (i) James C. Flores and his spouse and lineal
descendants, their respective estates or legal representatives, (ii) trusts
created for the benefit of such Persons and (iii) entities 80% or more of the
Voting Stock of which is directly or indirectly owned by any of the preceding
Persons.
"Permitted Investment" means an Investment by the Company or any Restricted
Subsidiary in:
(1) a Restricted Subsidiary or a Person which will, upon the making of such
Investment, become a Restricted Subsidiary; provided, however, that the
primary business of such Restricted Subsidiary is a Related Business;
139
(2) another Person if as a result of such investment such other Person is
merged or consolidated with or into, or transfers or conveys all or
substantially all its assets to, the Company or a Restricted
Subsidiary; provided, however, that such Person's primary business is a
Related Business;
(3) cash and Cash Equivalents;
(4) receivables owing to the Company or any Restricted Subsidiary created
or acquired in the ordinary course of business and payable or
dischargeable in accordance with customary trade terms; provided,
however, that such trade terms may include such concessionary trade
terms as the Company or any such Restricted Subsidiary deems reasonable
under the circumstances;
(5) payroll, travel and similar advances to cover matters that are expected
at the time of such advances ultimately to be treated as expenses for
accounting purposes and that are made in the ordinary course of
business;
(6) loans or advances to employees made in the ordinary course of business
consistent with past practices of the Company or such Restricted
Subsidiary;
(7) stock, obligations or securities received in settlement of debts
created in the ordinary course of business and owing to the Company or
any Restricted Subsidiary or in satisfaction of judgments or pursuant
to any plan of reorganization or similar arrangement upon the
bankruptcy or insolvency of a debtor;
(8) Investments made as a result of the receipt of non-cash consideration
from an Asset Disposition that was made pursuant to and in compliance
with "Certain Covenants--Limitation on Sales of Assets and Subsidiary
Stock;"
(9) Investments in existence on the Issue Date;
(10)Currency Agreements, Interest Rate Agreements and related Hedging
Obligations, which transactions or obligations are incurred in
compliance with "Certain Covenants--Limitation on Indebtedness;"
(11)Investments by the Company or any of its Restricted Subsidiaries,
together with all other Investments pursuant to this clause (11), in an
aggregate amount at the time of such Investment not to exceed $20.0
million outstanding at any one time;
(12)Guarantees issued in accordance with "Certain Covenants--Limitations on
Indebtedness;"
(13)prepaid expenses, lease, utilities, workers' compensation performance
and similar deposits made in the ordinary course of business;
(14)Investments owned by a Person if and when it is acquired by the Company
and becomes a Restricted Subsidiary; provided, however, that such
Investments are not made in contemplation of such acquisition;
(15)Permitted Business Investments; and
(16)Investments in any units of any oil and gas royalty trust.
"Permitted Liens" means, with respect to any Person:
(1) Liens securing Indebtedness and other obligations of the Company under
the Senior Credit Agreement, Interest Rate Agreements, Currency
Agreements and other Senior Indebtedness and liens on assets of
Restricted Subsidiaries securing Guarantees of Indebtedness and other
obligations of the Company under the Senior Credit Agreement and other
Senior Indebtedness;
140
(2) pledges or deposits by such Person under workmen's compensation laws,
unemployment insurance laws or similar legislation, or good faith
deposits in connection with bids, tenders, contracts (other than for
the payment of Indebtedness) or leases to which such Person is a party,
or deposits to secure public or statutory obligations of such Person or
deposits or cash or United States government bonds to secure surety or
appeal bonds to which such Person is a party, or deposits/,/as security
for contested taxes or import or customs duties or for the payment of
rent, in each case Incurred in the ordinary course of business;
(3) Liens imposed by law, including carriers', warehousemen's and
mechanics' Liens, in each case for sums not yet due or being contested
in good faith, by appropriate proceedings if a reserve or other
appropriate provisions, if any, as shall be required by GAAP shall have
been made in respect thereof;
(4) Liens for taxes, assessments or other governmental charges not yet
subject to penalties for non-payment or which are being contested in
good faith by appropriate proceedings provided appropriate reserves
required pursuant to GAAP have been made in respect thereof;
(5) Liens in favor of issuers of surety or performance bonds or letters of
credit or bankers' acceptances issued pursuant to the request of and
for the account of such Person in the ordinary course of its business;
provided, however, that such letters of credit do not constitute
Indebtedness;
(6) encumbrances, easements or reservations of, or rights of others for,
licenses, rights of way, sewers, electric fines, telegraph and
telephone lines and other similar purposes, or zoning or other
restrictions as to the use of real properties or Liens incidental to
the conduct of the business of such Person or to the ownership of its
properties which do not in the aggregate materially adversely affect
the value of said properties or materially impair their use in the
operation of the business of such Person;
(7) Liens securing Hedging Obligations so long as the related Indebtedness
is, and is permitted to be under the Indenture, secured by a Lien on
the same property securing such Hedging Obligation;
(8) leases and subleases of real property which do not materially interfere
with the ordinary conduct of the business of the Company or any of its
Restricted Subsidiaries;
(9) judgment Liens not giving rise to an Event of Default so long as such
Lien is adequately bonded and any appropriate legal proceedings which
may have been duly initiated for the review of such judgment have not
been finally terminated or the period within which such proceedings may
be initiated has not expired;
(10)Liens for the purpose of securing the payment of all or a part of the
purchase price of, or Capitalized Lease Obligations with respect to,
assets or property acquired or constructed in the ordinary course of
business; provided that:
(a) the aggregate principal amount of Indebtedness secured by such
Liens is otherwise permitted to be Incurred under the Indenture
and does not exceed the cost of the assets or property so acquired
or constructed; and
(b) such Liens are created within 180 days of construction or
acquisition of such assets or property and do not encumber any
other assets or property of the Company or any Restricted
Subsidiary other than such assets or property and assets affixed
or appurtenant thereto;
(11)Liens arising solely by virtue of any statutory or common law
provisions relating to banker's Liens, rights of set-off or similar
rights and remedies as to deposit accounts or other funds maintained
with a depositary institution; provided that:
141
(a) such deposit account is not a dedicated cash collateral account
and is not subject to restrictions against access by the Company
in excess of those set forth by regulations promulgated by the
Federal Reserve Board; and
(b) such deposit account is not intended by the Company or any
Restricted Subsidiary to provide collateral to the depository
institution;
(12)Liens arising from Uniform Commercial Code financing statement filings
regarding operating leases entered into by the Company and its
Restricted Subsidiaries in the ordinary course of business;
(13)Liens existing on the Issue Date;
(14)Liens on property at the time the Company acquired the property,
including any acquisition by means of a merger or consolidation with or
into the Company; provided, however, that such Liens are not created,
incurred or assumed in connection with, or in contemplation of, such
acquisition; provided further, however, that such Liens may not extend
to any other property owned by the Company or any Restricted Subsidiary;
(15)Liens securing Indebtedness or other obligations of a Restricted
Subsidiary owing to the Company or a Wholly Owned Subsidiary;
(16)Liens securing the Notes, the Subsidiary Guarantees and other
obligations arising under the Indenture;
(17)Liens securing Refinancing Indebtedness of the Company or a Restricted
Subsidiary Incurred to refinance Indebtedness of the Company that was
previously so secured; provided that any such Lien is limited to all or
part of the same property or assets (plus improvements, accessions,
proceeds or dividends or distributions in respect thereof) that secured
(or, under the written arrangements under which the original Lien
arose, could secure) the Indebtedness being refinanced or is in respect
of property or assets that is the security for a Permitted Lien
hereunder;
(18)Liens in respect of Production Payments and Reserve Sales;
(19)Liens on pipelines and pipeline facilities that arise by operation of
law; and
(20)farmout, carried working interest, joint operating, unitization,
royalty, sales and similar agreements relating to the exploration or
development of, or production from, oil and gas properties entered into
in the ordinary course of business.
"Person" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization, limited
liability company, government or any agency or political subdivision hereof. or
any other entity.
"Point Arguello Partnerships" means the following partnerships of which
Arguello Inc. is a managing general partner: (a) Gaviota Gas Plant Company, (b)
Point Arguello Natural Gas Line Company, (c) Point Arguello Pipeline Company
and (d) Point Arguello Terminal Company.
"Preferred Stock," as applied to the Capital Stock of any corporation means
Capital Stock of any class or classes (however designated) which is preferred
as to the payment of dividends, or as to the distribution of assets upon any
voluntary or involuntary liquidation or dissolution of such corporation, over
shares of Capital Stock of any other class of such corporation.
"Principal Property" means any property owned or leased by the Company or
any Subsidiary of the Company, the gross book value of which exceeds one
percent of Consolidated Net Worth.
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"Production Payments and Reserve Sales" means the grant or transfer by the
Company or a Subsidiary of the Company to any Person of a royalty, overriding
royalty, net profits interest, production payment (whether volumetric or dollar
denominated), partnership or other interest in oil and gas properties, reserves
or the right to receive all or a portion of the production or the proceeds from
the sale of production attributable to such properties, including any such
grants or transfers pursuant to incentive compensation programs on terms that
are reasonably customary in the oil and gas business for geologists,
geophysicists and other providers of technical services to the Company or a
Subsidiary of the Company.
"Property" means, with respect to any Person, any interest of such Person
in any kind of property or asset, whether real, personal or mixed, or tangible
or intangible, including Capital Stock and other securities issued by any other
Person (but excluding Capital Stock or other securities issued by such first
mentioned Person).
"Property Net Revenue Coverage Ratio" means, with respect to Property to be
acquired by the Company or any Restricted Subsidiary, the ratio of (i) the
amount equal to (A) the revenues attributable to the sale of Hydrocarbons from
such Property for the most recent four full fiscal quarters for which financial
information is available immediately prior to the acquisition date (the "Pro
Forma Period"), minus (B) the production and general and administrative
expenses attributable to such Property during the Pro Forma Period (the
"Property Net Revenue") to (ii) the aggregate Consolidated Interest Expense
which the Company or any Restricted Subsidiary will accrue during the fiscal
quarter in which the acquisition date occurs and the three fiscal quarters
immediately subsequent to such fiscal quarter as a result of Indebtedness
incurred for the purpose of making such acquisition (as though all such
Indebtedness was incurred or repaid on the first day of the quarter in which
the acquisition date occurs). For purposes of this definition, Property Net
Revenue shall be calculated, after giving effect on a pro forma basis for the
Pro Forma Period, to (a) any adjustments in revenues from the sale of
Hydrocarbons as a result of fixed price or other contract arrangements entered
into as of the acquisition date and (b) any adjustments in production and
general and administrative expenses which are fixed or determinable as of the
acquisition date.
"Refinancing Indebtedness" means Indebtedness that is Incurred to refund,
refinance, replace, renew, repay or extend (including pursuant to any
defeasance or discharge mechanism) (collectively, "refinance", "refinances,"
and "refinanced" shall have a correlative meaning) any Indebtedness existing on
the date of the lndenture or Incurred in compliance with the Indenture
(including Indebtedness of the Company that refinances Indebtedness of any
Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that
refinances Indebtedness of another Restricted Subsidiary) including
Indebtedness that refinances. Refinancing Indebtedness; provided, however, that:
(1) (a) if the Stated Maturity of the Indebtedness being refinanced is
earlier than the Stated Maturity of the Notes, the Refinancing
Indebtedness has a Stated Maturity no earlier than the Stated Maturity
of the Indebtedness being refinanced or (b) if the Stated Maturity of
the Indebtedness being refinanced is later than the Stated Maturity of
the Notes, the Refinancing Indebtedness has a Stated Maturity at least
91 days later than the Stated Maturity of the Notes;
(2) the-Refinancing Indebtedness has an Average Life at the time such
Refinancing Indebtedness is Incurred that is equal to or greater than
the Average Life of the Indebtedness being refinanced;
(3) such Refinancing Indebtedness is Incurred in an aggregate principal
amount (or if issued with original issue discount, an aggregate issue
pricey that is equal to or less than the sum of the aggregate principal
amount (or if issued with original issue discount, the aggregate
accreted value) then outstanding (plus, without duplication, accrued
interest, fees and
143
expenses, including any premium and defeasance costs) of the
Indebtedness being refinanced; and
(4) if the Indebtedness being refinanced is subordinated in right of
payment to the Notes, such Refinancing Indebtedness is subordinated in
right of payment to the Notes on terms at least as favorable to the
holders as those contained in the documentation governing the
Indebtedness being extended, refinanced, renewed, replaced, defeased or
refunded.
"Related Business" means any business which is the same as or related,
ancillary or complementary to any of the businesses of the Company on the date
of the Indenture, which includes (a) the acquisition, exploration,
exploitation, development, production, operation and disposition of interests
in oil, gas and other hydrocarbon properties, and the utilization of the
Company's properties, (b) the gathering, marketing, treating, processing,
storage, refining, selling and transporting of any production from such
interests or properties and products produced in association therewith, (c) any
power generation and electrical transmission business and (d) any business or
activity relating to, arising from, or necessary, appropriate or incidental to
the activities described in the foregoing clauses (a) through (c) of this
definition.
"Representative" means any trustee, agent or representative (if any) of an
issue of Senior Indebtedness.
"Restricted investment" means any Investment other than a Permitted
Investment.
"Restricted Subsidiary" means any Subsidiary of the Company other than an
Unrestricted Subsidiary.
"Sale/Leaseback Transaction" means an arrangement relating to property now
owned or hereafter acquired whereby the Company or a Restricted Subsidiary
transfers such property to a Person and the Company or a Restricted Subsidiary
leases it from such Person.
"Senior Credit Agreement" means, with respect to the Company, one or more
debt facilities (including, without limitation, the Credit Agreement, dated as
of July 3, 2002, among the Company, JPMorgan Chase Bank, as administrative
agent, and the lenders and agents parties thereto from time to time) or
commercial paper facilities providing for revolving credit loans, term loans,
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, refunded, replaced or refinanced in whole or in
part from time to time (and whether or not with the original administrative
agent and lenders or another administrative agent or agents or other lenders
and whether provided under the original Senior Credit Agreement or any other
credit or other agreement or indenture).
"Senior Indebtedness" means, whether outstanding on the Issue Date or
thereafter issued, created, incurred or assumed, the Bank Indebtedness and all
other Indebtedness of an Issuer, including accrued and unpaid interest
(including interest accruing on or after the filing of any petition in
bankruptcy or for reorganization relating to such Issuer at the rate specified
in the documentation with respect thereto whether or not a claim for post
filing interest is allowed in such proceeding) and fees relating thereto;
provided, however, that Senior Indebtedness will not include:
(1) any Indebtedness which, in the instrument creating or evidencing the
same or pursuant to which the same is outstanding, it is provided that
the obligations in respect of such Indebtedness are not superior in
right of, or are subordinate to, payment of the Notes;
(2) any obligation of the Company to any Subsidiary;
144
(3) any liability for Federal, state, foreign, local or other taxes owed or
owing by the Company;
(4) any accounts payable or other liability to trade creditors arising in
the ordinary course of business (including Guarantees thereof or
instruments evidencing such liabilities);
(5) any Indebtedness, Guarantee or obligation of the Company that is
expressly subordinate or junior in right of payment to any other
Indebtedness, Guarantee or obligation of the Company, including,
without limitation, any Senior Subordinated Indebtedness and any
Subordinated Obligations; or
(6) any Capital Stock.
"Senior Subordinated Indebtedness" means the Notes and any other
Indebtedness of the Company that specifically provides that such Indebtedness
is to rank equally with the Notes in right of payment and is not subordinated
by its terms in right of payment to any Indebtedness or other obligation of the
Company which is not Senior Indebtedness.
"Significant Subsidiary" means any Restricted Subsidiary that would be a
"Significant Subsidiary" of the Company within the meaning of Rule 1-02 under
Regulation S-X promulgated by the SEC.
"Spin-off" means any distribution of Voting Stock then owned by Plains
Resources Inc. and its Subsidiaries of the Company to Plains Resources Inc.'s
shareholders.
"Stated Maturity" means, with respect to any security, the date specified
in such security as the fixed date on which the payment of principal of such
security is due and payable, including pursuant to any mandatory redemption
provision, but shall not include any contingent obligations to repay, redeem or
repurchase any such principal prior to the date originally scheduled for the
payment thereof.
"Subordinated Obligation" means any Indebtedness of the Company (whether
outstanding on the Issue Date or thereafter Incurred) which is subordinate or
junior in right of payment to the Notes pursuant to a written agreement.
"Subsidiary" of any Person means any corporation, association, partnership,
joint venture, limited liability company or other business entity of which more
than 50% of the total voting power of shares of Capital Stock or other
interests (including partnership and joint venture interests) 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 (1) such Person, (2) such Person and one or more
Subsidiaries of such Person or (3) one or more Subsidiaries of such Person.
Unless otherwise specified herein, each reference to a Subsidiary will refer to
a Subsidiary of the Company. The Point Arguello Partnerships are not
Subsidiaries of the Company.
"Subsidiary Guarantee" means any guarantee of the Notes by any Subsidiary
Guarantor in accordance with the provisions set forth in "--Senior Subordinated
Guarantee of Notes."
"Subsidiary Guarantor" means each Restricted Subsidiary of the Company that
has issued a Subsidiary Guarantee.
"Transition Agreements" mean the Master Separation Agreement, between
Plains Resources Inc. and the Company, dated as of July 3, 2002, the Employee
Matters Agreement, between Plains Resources Inc. and the Company, dated as of
July 3, 2002, the Plains Exploration & Production transition services
agreement, between Plains Resources Inc. and the Company, dated as of July 3,
2002, the Plains Resources transition services agreement, between Plains
Resources Inc. and the Company, dated as of July 3, 2002, the Technical
Services Agreement, among Plains Resources Inc., Calumet Florida, LLC and the
Company, dated as of July 3, 2002, the Intellectual Property Agreement, between
145
Plains Resources Inc. and the Company, dated as of July 3, 2002 and the Tax
Allocation Agreement, between Plains Resources Inc. and the Company, dated as
of July 3, 2002, each as amended or supplemented from time to time in
compliance with the terms of the Indenture.
"Unrestricted Subsidiary" means:
(1) any Subsidiary of the Company that at the time of determination shall
be designated an Unrestricted Subsidiary by the Board of Directors of
the Company in the manner provided below; and
(2) 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:
(1) such Subsidiary or any of its Subsidiaries does not own any Capital
Stock or Indebtedness of or have any Investment in, 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;
(2) all the Indebtedness of such Subsidiary and its Subsidiaries shall, at
the date of designation, and will at all times thereafter, consist of
Non-Recourse Debt;
(3) such designation and the Investment of the Company in such Subsidiary
complies with "Certain Covenants--Limitation on Restricted Payments;"
(4) 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 taken as a whole;
(5) such Subsidiary is a Person with respect to which neither the Company
nor any of its Restricted Subsidiaries has any direct or indirect
obligation:
(a) to subscribe for additional Capital Stock of such Person; or
(b) to maintain or preserve such Person's financial condition or to
cause such Person to achieve any specified levels of operating
results; and
(6) 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 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 complies with the foregoing
conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the
foregoing requirements as an Unrestricted Subsidiary, it 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 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 under the first
paragraph of the "Limitation on Indebtedness" covenant on a pro forma basis
taking into account such designation.
146
"Volumetric Production Payments" means production payment obligations
recorded as defined revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" of a Person means all classes of Capital Stock of such
Person then outstanding and normally entitled to vote in the election of
directors.
"Wholly-Owned Subsidiary" means a Restricted Subsidiary of the Company, all
of the Capital Stock of which (other than directors' qualifying shares) is
owned by the Company or another Wholly-Owned Subsidiary.
147
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES
The following is a summary of the material United States federal income tax
consequences of purchasing, holding and selling the notes. Except where we
state otherwise, this summary deals only with notes held as capital assets, as
defined in the Internal Revenue Code of 1986, as amended, or the Code, by a
United States holder (as defined below) who purchases the notes at their
original offering price when we originally issue them.
We do not address all of the tax consequences that may be relevant to a
United States holder. We also do not address, except as stated below, any of
the tax consequences to holders that are foreign holders (as defined below) or
to holders that may be subject to special tax treatment including banks, thrift
institutions, real estate investment trusts, personal holding companies,
insurance companies, and brokers and dealers in securities or currencies.
Further, we do not address:
. the United States federal income tax consequences to stockholders in, or
partners or beneficiaries of, an entity that is a holder of the notes;
. the United States federal estate and gift or alternative minimum tax
consequences of the purchase, ownership or sale of the notes;
. the United States federal income tax consequences to persons who hold the
notes in a "straddle" or as part of a "hedging," "conversion" or
"constructive sale" transaction or whose "functional currency" is not the
United States dollar; or
. any state, local or foreign tax consequences of the purchase, ownership
and sale of the notes.
Accordingly, you are urged to consult your own tax advisor regarding the
particular tax consequences of purchasing, owning and selling the notes in
light of your circumstances.
A "United States holder" is a beneficial owner of the notes who, for United
States federal income tax purposes, is:
. an individual who is a citizen or resident of the United States;
. a corporation, another entity taxable as a corporation or a partnership
created or organized in or under the laws of the United States or any
political subdivision thereof or therein;
. an estate if its income is subject to United States federal income
taxation regardless of its source; or
. a trust if (1) a United States court can exercise primary supervision
over its administration and (2) one or more United States persons have
the authority to control all of its substantial decisions or it has made
a valid election under applicable U.S. treasury regulations to be treated
as a United States person.
If a partnership holds notes, the tax treatment of a partner will generally
depend upon the status of the partner and upon the activities of the
partnership.
A "foreign holder" is a beneficial owner of the notes other than a United
States holder. This summary is based on the currently existing provisions of
the Code, Treasury regulations issued under the Code, and administrative
judicial interpretations thereof, all as they currently exist as of the date of
this prospectus and all of which are subject to change, possibly with
retroactive effect, or different interpretations.
148
United States Federal Income Taxation of United States Holders
Payment of interest on the notes. The notes were not issued with original
issue discount. Interest paid or payable on a note will be taxable to a United
States holder as ordinary income, generally at the time it is received or
accrued, in accordance with such holder's regular method of accounting for
United States federal income tax purposes.
Exchange offer. The exchange of Series A notes for Series B notes in the
registered exchange offer will not constitute a taxable event for United States
holders. Consequently, a United States holder will not recognize gain or loss
on the exchange, the holding period of the Series B note will include the
holding period of the Series A note, and the basis of the Series B note will be
the same as the basis of the Series A note immediately before the exchange.
As more fully described under "The Exchange Offer--Registration Rights," we
may be required to pay liquidated damages to United States holders. If this
occurs, we believe these payments should be treated in the same manner as
regular interest on the notes. However, this matter is not free from doubt. The
Internal Revenue Service might instead require the United States holder to
report it as income when it accrues or becomes fixed, even if the United States
holder is a cash method taxpayer.
Sale, exchange or retirement of the notes. Upon the sale, exchange,
redemption, retirement at maturity, or other disposition of a note, a United
States holder generally will recognize taxable gain or loss equal to the
difference between (1) the sum of cash plus the fair market value of all
non-cash property received on such disposition (except to the extent such cash
or property is attributable to accrued, but unpaid, interest, which will be
taxable as ordinary income) and (2) such United States holder's adjusted tax
basis in the note. A United States holder's adjusted tax basis in a note
generally will equal the cost of the note to the United States holder. Gain or
loss recognized on the disposition of a note will be long-term capital gain or
loss if, at the time of such disposition, the United States holder's holding
period for the note is more than one year. Long-term capital gain realized by
individual taxpayers is generally taxable at a maximum rate of 20%. The
deductibility of capital losses is subject to limitations.
Backup withholding and information reporting. Backup withholding and
information reporting requirements may apply to payments made with respect to
the notes. We, or our agents or a broker, as the case may be, will be required
to withhold from any payment that is subject to backup withholding a portion of
such payment not to exceed 22.5% if a United States holder fails to furnish its
taxpayer identification number (social security or employer identification
number) or otherwise fails to comply with the applicable requirements of the
backup withholding rules. Corporations and certain other entities are generally
exempt from the backup withholding and information reporting requirements.
Generally, income on the notes will be reported to non-exempt United States
holders on an applicable Internal Revenue Service Form 1099.
Any amounts withheld under the backup withholding rules from a payment to a
United States holder will be allowed as a credit against such United States
holder's federal income tax liability and may entitle the United States holder
to a refund, provided that the required information is furnished to the
Internal Revenue Service by the United States holder.
United States Federal Income Taxation of Foreign Holders
Payment of interest on the notes. Payments of interest to a foreign holder
that are not effectively connected to the conduct of a United States trade or
business will generally not be subject to United States federal income tax, or
the withholding thereof, provided the foreign holder is the beneficial owner
and:
149
. does not own (directly or indirectly, actually or constructively) 10% or
more of the total combined voting power of all classes of our capital
stock entitled to vote within the meaning of 871(h)(3) of the Code and
the regulations thereunder;
. is not a controlled foreign corporation that is related to us through
stock ownership; and
. is not a bank receiving interest described in section 881(c)(3)(A) of the
Code.
A foreign holder that receives interest payments that are not effectively
connected with a United States trade or business but that does not satisfy each
of the three above mentioned conditions will be subject to withholding tax at a
rate of 30%, unless a United States income tax treaty applies to reduce or
eliminate withholding.
To qualify for exemption from withholding, the last United States payor in
the chain of payment before payment to a foreign holder (the "withholding
agent") must have received in the year in which a payment of interest or
principal occurs, or in either of the two preceding calendar years, a statement
that:
. is signed by the foreign holder under penalties of perjury;
. certifies that the holder of the securities is a foreign holder; and
. provides the name and address of the foreign holder.
The statement may be made on an Internal Revenue Service Form W-8BEN or a
substantially similar form, and the foreign holder must inform the withholding
agent of any change in the information on the statement within 30 days of any
change. If the notes are held through a securities clearing organization or
certain other financial institutions that are not qualified intermediaries, the
organization or institution may provide a signed statement to the withholding
agent along with a copy of Internal Revenue Service Form W-8BEN or a substitute
form provided by the foreign holder. If the financial institution is a
qualified intermediary, it generally will not be required to furnish a copy of
the Internal Revenue Service Form W-8BEN. A qualified intermediary is a
financial institution that has entered into a withholding agreement with the
Internal Revenue Service.
Exchange offer. The exchange of Series A notes Series B notes in the
exchange offer will not constitute a taxable event for foreign holders.
Consequently, for United States federal income tax purposes, a foreign holder
will not recognize gain or loss on the exchange, the holding period of the
Series B note will include the holding period of the Series A note, and the
basis of the Series B note will be the same as the basis of the Series A note
immediately before the exchange. As more fully described under "Exchange
Offer--Registration Rights," upon the occurrence of certain enumerated events
we may be required to pay liquidation damages to the foreign holders. If this
occurs, we believe these payments should be treated in the same manner as
regular interest on the notes.
Sale, exchange or retirement of the notes. A foreign holder will generally
not be subject to United States federal income tax, or the withholding thereof,
on any gain realized upon the sale, exchange, redemption, retirement at
maturity, or other disposition of the notes. If, however, the gain is
effectively connected with the conduct of a trade or business within the United
States by the foreign holder or if the foreign holder is an individual present
in the United States for 183 days or more during the taxable year of sale,
redemption, retirement, or other disposition and certain other conditions are
met, the foreign holder may be subject to income tax on all income and gains
recognized.
U.S. trade or business. If a foreign holder holds the notes in connection
with a trade or business that the foreign holder has conducted in the United
States:
. Any interest on the notes, and any gain from disposing of the notes,
generally will be subject to income tax as if the foreign holder were a
United States holder.
150
. If the foreign holder is a corporation, the foreign holder may be subject
to the "branch profits tax" on the earnings that are connected with
foreign holder's United States trade or business, including earnings from
the notes. This tax is 30%, but may be reduced or eliminated by an
applicable United States income tax treaty.
Backup withholding and information reporting. Backup withholding and
information reporting requirements do not apply to payments of interest made to
foreign holders if the certification needed to avoid withholding tax on
interest, as described above, is received, provided that the payor does not
have actual knowledge or reason to know that the holder is a United States
holder. If any payments of principal and interest are made to the beneficial
owner of a note by or through the foreign office of a foreign custodian,
foreign nominee or other foreign agent of such beneficial owner, or if the
foreign office of a foreign "broker" (as defined in applicable United States
Treasury regulations) pays the proceeds of the sale of a note effected outside
the United States to the seller thereof, backup withholding and information
reporting will not apply. Information reporting requirements (but not backup
withholding) will apply, however, to a payment by or through a foreign office
of a broker of principal and interest or the proceeds of a sale of a note
effected outside the United States if that broker has specified types of
relationships with the United States, unless the broker has documentary
evidence in its records that the holder is a foreign holder and certain other
conditions are met or the foreign holder otherwise establishes an exemption.
Payment by a United States office of a broker is subject to both backup
withholding at a rate of approximately 30% and information reporting unless the
holder certifies, under penalties of perjury, in the manner required as to its
foreign holder status or otherwise establishes an exemption.
151
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC set forth in no-action
letters issued to third parties, we believe that you may freely transfer Series
B notes issued under the exchange offer in exchange for the Series A notes,
unless you are:
. our "affiliate" within the meaning of Rule 405 under the Securities Act;
. a broker-dealer or an initial purchaser that acquired Series A notes
directly from us; or
. a broker-dealer that acquired Series A notes as a result of market-making
or other trading activities without compliance with the registration and
prospectus delivery provisions of the Securities Act;
provided that you acquire the Series B notes in the ordinary course of your
business and you are not engaged in, and do not intend to engage in, and have
no arrangement or understanding with any person to participate in, a
distribution of the Series B notes. Broker-dealers receiving Series B notes in
the exchange offer in exchange for Series A notes that were acquired in
market-making or other trading activities will be subject to a prospectus
delivery requirement with respect to resales of the Series B notes.
To date, the staff of the SEC has taken the position that participating
broker-dealers may fulfill their prospectus delivery requirements with respect
to transactions involving an exchange of securities such as this exchange
offer, other than a resale of an unsold allotment from the original sale of the
Series A notes, with the prospectus contained in the exchange offer
registration statement. Pursuant to the registration rights agreement, we have
agreed to permit such participating broker-dealers to use this prospectus in
connection with the resale of the Series B notes.
If you wish to exchange your Series A notes for Series B notes in the
exchange offer, you will be required to make certain representations to us as
set forth in "The Exchange Offer--Registration Rights" and "--Procedures for
Tendering Series A Notes--Determination of Validity" of this prospectus
beginning on pages 27 and 34 and in the letter of transmittal. In addition, if
you are a broker-dealer who receives Series B notes for your own account in
exchange for Series A notes that were acquired by you as a result of
market-making activities or other trading activities, you will be required to
acknowledge that you will deliver a prospectus in connection with any resale by
you of those Series B notes. See "The Exchange Offer--Resale of Series B Notes;
Plan of Distribution" beginning on page 38.
We will not receive any proceeds from any sale of Series B notes by
broker-dealers. Broker-dealers who receive Series B notes for their own account
in the exchange offer may sell them 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 Series B notes or a combination of
such methods of resale;
. at market prices prevailing at the time of resale; or
. at prices related to the prevailing market prices or negotiated prices.
Any 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 broker-dealer or the purchasers of any Series B notes. Any
broker-dealer that resells Series B notes it received for its own account
pursuant to the exchange offer and any broker or dealer that participates in a
distribution of
152
Series B notes may be deemed to be an "underwriter" within the meaning of the
Securities Act, and any profit on any resale of Series B notes and any
commissions or concessions received by any such persons may be deemed to be
underwriting compensation under the Securities Act. Although the letter of
transmittal requires a broker dealer to deliver a prospectus, a broker-dealer
will not be deemed to admit that it is an "underwriter" within the meaning of
the Securities Act as a result of such delivery.
We have agreed to pay all expenses incidental to the exchange offer other
than commissions and concessions of any brokers or dealers and will indemnify
holders of the Series A notes, including any broker-dealers, against certain
liabilities, including liabilities under the Securities Act, as set forth in
the registration rights agreement.
VALIDITY OF THE SERIES B NOTES
Akin Gump Strauss Hauer & Feld LLP will pass upon the validity of the
Series B notes we are offering.
EXPERTS
The combined financial statements of the Upstream Subsidiaries of Plains
Resources Inc. as of December 31, 2001 and 2000 and for each of the three years
in the period ended December 31, 2001 included in this prospectus have been so
included in reliance on the report of PricewaterhouseCoopers LLP, independent
accountants, given on the authority of said firm as experts in auditing and
accounting.
Certain information with respect to the oil and gas reserves associated
with our oil and gas properties is derived from the reports of Netherland,
Sewell & Associates, Inc., Ryder Scott Company, and H.J. Gruy and Associates,
Inc., independent petroleum consulting firms, and has been included in this
prospectus upon the authority of said firms as experts with respect to the
matters covered by such reports and in giving such reports.
WHERE YOU CAN FIND MORE INFORMATION
Upon completion of this offering, we will be required to file annual,
quarterly and current reports, proxy statements and other information with the
Securities and Exchange Commission. You may read and copy the registration
statement and any other documents we have filed at the Securities and Exchange
Commission's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C.
20549. Please call the Securities and Exchange Commission at 1-800-SEC-0330 for
further information on the Public Reference Room. Our Securities and Exchange
Commission filings are also available to the public at the Securities and
Exchange Commission's Internet site at "http://www.sec.gov".
This prospectus is part of the registration statement and does not contain
all of the information included in the registration statement. Although we have
discussed the material provisions of our contracts and other documents in this
prospectus, whenever a reference is made in this prospectus to any of our
contracts or other documents, you should refer to the exhibits that are a part
of the registration statement for a copy of the contract or document.
After this offering, we expect to provide annual reports to our
stockholders that include financial information examined and reported on by our
independent public accountants.
153
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly
used in the oil and gas industry and this prospectus:
API gravity. A system of classifying oil based on its specific gravity,
whereby the greater the gravity, the lighter the oil.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
BOE. One stock tank barrel equivalent of oil, calculated by converting gas
volumes to equivalent oil barrels at a ratio of 6 Mcf to 1 Bbl of oil.
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 area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil from an established spot
market price to reflect differences in the quality and/or location of oil.
Exploratory well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
Farm-in. An agreement between a participant who brings a property into the
venture and another participant who agrees to spend an agreed amount to explore
and develop the property and has no right of reimbursement but may gain a
vested interest in the venture. A "farm-in" describes the position of the
participant who agrees to spend the agreed-upon sum of money to gain a vested
interest in the venture.
Gas. Natural gas.
Gross acres. The total acres in which a person or entity has a working
interest.
Gross oil and gas wells. The total wells in which a person or entity owns
a working interest.
Infill drilling. A drilling operation in which one or more development
wells is drilled within the proven boundaries of a field.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBOE. One thousand BOE.
Mcf. One thousand cubic feet of gas.
Midstream. The portion of the oil and gas industry focused on marketing,
gathering, transporting and storing oil.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
154
MMBOE. One million BOE.
MMcf. One million cubic feet of gas.
Net acres. Gross acres multiplied by the percentage working interest.
Net oil and gas wells. Gross wells multiplied by the percentage working
interest.
Net production. Production that is owned, less royalties and production
due others.
Net revenue interest. Our share of petroleum after satisfaction of all
royalty and other non-cost-bearing interests.
NYMEX. New York Mercantile Exchange.
Oil. Crude oil, condensate and natural gas liquids.
Operator. The individual or company responsible for the exploration and/or
exploitation and/or production of an oil or gas well or lease.
PV-10. The pre-tax present value, discounted at 10% per year, of estimated
future net revenues from the production of proved reserves, computed by
applying sales prices in effect as of the dates of such estimates and held
constant throughout the productive life of the reserves (except for
consideration of price changes to the extent provided by contractual
arrangements), and deducting the estimated future costs to be incurred in
developing, producing and abandoning the proved reserves (computed based on
current costs and assuming continuation of existing economic conditions).
Proved developed reserves. Proved developed oil and gas reserves are
reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. 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 should be included as "proved developed reserves" only after testing
by a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.
Proved reserves. Per Article 4-10(a)(2) of Regulation S-X, the SEC defines
proved oil and gas reserves as 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, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not
on escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes: (i) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any; and (ii) the immediately
adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
155
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include: (i) oil that may become
available from known reservoirs but is classified separately as "indicated
additional reserves"; (ii) crude oil, natural gas, and natural gas liquids, the
recovery of which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors; (iii) crude oil,
natural gas, and natural gas liquids, that may occur in undrilled prospects;
and (iv) crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite and other such sources.
Proved reserve additions. The sum of additions to proved reserves from
extensions, discoveries, improved recovery, acquisitions and revisions of
previous estimates.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units can be claimed only
where it can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no circumstances
should estimates for proved undeveloped reserves be attributable to any 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.
Reserve life. A measure of the productive life of an oil and gas property
or a group of properties, expressed in years. Reserve life is calculated by
dividing proved reserve volumes at year-end by production for that year.
Reserve replacement cost. The cost per BOE of reserves added during a
period calculated by using a fraction, the numerator of which equals the costs
incurred for the relevant property acquisition, exploration, exploitation and
development and the denominator of which equals changes in proved reserves due
to revisions of previous estimates, extensions, discoveries, improved recovery
and other additions and purchases of reserves in-place.
Reserve replacement ratio. The proved reserve additions for the period
divided by the production for the period.
Royalty. An interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the
wells on the leased acreage. Royalties may be either landowner's royalties,
which are reserved by the owner of the leased acreage at the time the lease is
granted, or overriding royalties, which are usually reserved by an owner of the
leasehold in connection with a transfer to a subsequent owner.
Standardized measure. The present value, discounted at 10% per year, of
estimated future net revenues from the production of proved reserves, computed
by applying sales prices in effect as of the dates of such estimates and held
constant throughout the productive life of the reserves (except for
consideration of price changes to the extent provided by contractual
arrangements), and deducting the estimated future costs to be incurred in
developing, producing and abandoning the proved reserves (computed based on
current costs and assuming continuation of existing economic conditions).
Future income taxes are calculated by applying the statutory federal and state
income tax rate to pre-tax
156
future net cash flows, net of the tax basis of the properties involved and
utilization of available tax carryforwards related to oil and gas operations.
Undeveloped acreage. Acreage held under lease, permit, contract or option
that is not in a spacing unit for a producing well.
Upstream. The portion of the oil and gas industry focused on acquiring,
exploiting, developing, exploring for and producing oil and gas.
Waterflood. A secondary recovery operation in which water is injected into
the producing formation to maintain reservoir pressure and force oil toward and
into the producing wells.
Working interest. An interest in an oil and gas lease that gives the owner
of the interest the right to drill for and produce oil and gas on the leased
acreage and requires the owner to pay a share of the costs of drilling and
production operations.
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INDEX TO OUR FINANCIAL STATEMENTS
Page
Plains Exploration & Production Company
Unaudited Pro Forma Consolidated Statement of Income for the nine months ended
September 30, 2002.................................................................... F-4
Unaudited Pro Forma Consolidated Statement of Income for the year ended December 31,
2001.................................................................................. F-6
Unaudited Consolidated Balance Sheets as of September 30, 2002 and December 31,
2001.................................................................................. F-8
Unaudited Consolidated Statements of Income for the nine months ended September 30,
2002 and 2001......................................................................... F-9
Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30,
2002 and 2001......................................................................... F-10
Unaudited Consolidated Statements of Comprehensive Income for the nine months ended
September 30, 2002 and 2001........................................................... F-11
Unaudited Consolidated Statements of Changes in Stockholder's Equity for the nine months
ended September 30, 2002 and 2001..................................................... F-12
Notes to Unaudited Consolidated Financial Statements.................................... F-13
Upstream Subsidiaries of Plains Resources Inc.
Report of Independent Accountants....................................................... F-29
Combined Balance Sheets as of December 31, 2001 and 2000................................ F-30
Combined Statements of Income for the years ended December 31, 2001, 2000 and 1999...... F-31
Combined Statements of Cash Flows for the years ended December 31, 2001, 2000 and
1999.................................................................................. F-32
Combined Statements of Comprehensive Income for the years ended December 31, 2001,
2000 and 1999......................................................................... F-33
Combined Statements of Combined Owners' Equity for the years ended December 31, 2001,
2000 and 1999......................................................................... F-34
Notes to Combined Financial Statements.................................................. F-35
F-1
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
The following unaudited pro forma consolidated statements of income for the
nine months ended September 30, 2002 and the year ended December 31, 2001 have
been prepared based on the historical consolidated financial statements of
Plains Exploration & Production Company ("PXP"), prior to the reorganization
discussed below known as the Upstream Subsidiaries of Plains Resources Inc.,
under the assumptions set forth in the accompanying footnotes. An unaudited pro
forma consolidated balance sheet at September 30, 2002 is not presented because
the effect of the reorganization and the debt issuance transactions described
below are reflected in the historical consolidated balance sheet of PXP at
September 30, 2002. The effect of the spin-off, as described below, represents
only one transaction and has no effect on the unaudited pro forma consolidated
statements of income.
On July 3, 2002, as provided in the Separation Agreement, Plains Resources
transferred to PXP (previously known as Stocker Resources L.P.) 100% of the
capital stock of Arguello Inc., Plains Illinois, Inc., PMCT, Inc. and Plains
Resources International Inc. (all referred to as Upstream Subsidiaries in the
historical combined financial statements) and all amounts payable to it by PXP
and its subsidiary companies. These transactions are referred to as the
"reorganization". As part of the reorganization, PXP was converted into a
Delaware corporation on September 18, 2002. The effect of the reorganization is
reflected in the Reorganization Adjustments in the unaudited pro forma
consolidated statements of income.
On July 3, 2002, PXP and Plains E&P Company, a wholly owned subsidiary that
has no material assets and was formed for the sole purpose of being a corporate
co-issuer of certain indebtedness, issued $200.0 million of 8.75% senior
subordinated notes due 2012 (the "8.75% Notes") at an issue price of 98.376%.
Also on July 3, PXP entered into a $300.0 million revolving credit facility
(the "PXP credit facility") that provides for a borrowing base of $225.0
million and made initial borrowings of $117.6 million. On July 3, PXP
distributed the $195.3 million net proceeds from the 8.75% Notes and $116.7
million of the initial borrowings under the PXP credit facility to Plains
Resources. The effect of these transactions is reflected in the Debt Issuance
Adjustments in the unaudited pro forma consolidated statements of income.
Plains Resources has received a favorable private letter ruling from the
Internal Revenue Service, or IRS, stating that, for United States federal
income tax purposes, a distribution by Plains Resources of the PXP capital
stock owned by it to its stockholders will generally be tax-free to both Plains
Resources and its stockholders. We call this proposed distribution the
"spin-off".
Prior to July 2002 certain of PXP's operations were conducted by Stocker
Resources L.P., a limited partnership of which Plains Resources and one of its
subsidiaries were the limited and general partners. As a result, when the
spin-off occurs the tax basis of certain assets and liabilities related to such
operations will be retained by Plains Resources. Accordingly, upon the
consummation of the spin-off, the deferred tax liability of PXP will increase
by $5.3 million and stockholder's equity will decrease by a corresponding
amount to reflect the effect of the tax basis that will be retained by Plains
Resources for tax reporting purposes. This transaction has no effect on the
unaudited pro forma consolidated statements of income.
Historically, general and administrative expenses consist of our direct
expenses plus amounts allocated from Plains Resources for various operational,
financial, accounting and administrative services provided to us. We estimate
that as a result of the reorganization and the spin-off, our annual general and
administrative expenses will increase by approximately $5.3 million over the
historical amount for the year ended December 31, 2001 reflecting the
incremental costs of operating as a separate, publicly-held company.
F-2
The unaudited pro forma combined statements of income for the nine months
ended September 30, 2002 and the year ended December 31, 2001 assume the
Reorganization Adjustments and the Debt Issuance Adjustments occurred on
January 1, 2001. We believe the assumptions used provide a reasonable basis for
presenting the significant effects directly attributable to the separation and
offering transactions. The unaudited pro forma combined financial statements do
not purport to represent what our results of operations would have been if such
transactions had occurred on such dates. These unaudited pro forma combined
financial statements should be read in conjunction with the Consolidated
Financial Statements of Plains Exploration & Production Company, the Combined
Financial Statements of the Upstream Subsidiaries of Plains Resources Inc. and
Management's Discussion and Analysis of Financial Condition and Results of
Operations, included elsewhere herein.
F-3
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002
(in thousands of dollars)
Plains Plains
Exploration Exploration
& Production Debt & Production
Company Reorganization Issuance Company
Historical Adjustments Adjustments Proforma(7)
------------ -------------- ----------- ------------
Revenues
Crude oil and liquids......................... $129,563 $ -- $ -- $129,563
Natural gas................................... 7,130 -- -- 7,130
Other operating revenues...................... 27 -- -- 27
-------- ------- -------- --------
136,720 -- -- 136,720
-------- ------- -------- --------
Costs and Expenses
Production expenses........................... 56,826 -- -- 56,826
General and administrative.................... 7,362 -- -- 7,362
(218)(3)
Depreciation, depletion and amortization...... 21,262 -- 679 (4) 21,723
-------- ------- -------- --------
85,450 -- 461 85,911
-------- ------- -------- --------
Income from Operations.......................... 51,270 -- (461) 50,809
Other Income (Expense)
Expenses of terminated public equity offering. (1,700) -- -- (1,700)
4,982 (3)
Interest expense.............................. (14,427) 9,357(1) (16,399)(5) (16,487)
Interest and other income..................... 114 -- -- 114
-------- ------- -------- --------
Income Before Income Taxes...................... 35,257 9,357 (11,878) 32,736
Income tax expense............................ (13,757) (3,651)(2) 4,635 (6) (12,773)
-------- ------- -------- --------
Net Income...................................... $ 21,500 $ 5,706 $ (7,243) $ 19,963
======== ======= ======== ========
Earnings Per Share
Basic and diluted............................. $ 0.89 $ 0.82
Average Shares Outstanding
Basic and diluted............................. 24,200 24,200
Reorganization Adjustments
(1) Reflects the reversal of historical interest expense related to amounts
payable to Plains Resources since such amounts payable were contributed
to PXP under the terms of the Separation Agreement.
(2) Reflects the income tax effect of the Reorganization Adjustments based
on our historical effective income tax rate of 39%.
Debt Issuance Adjustments
(3) Reflects the reversal of historical amortization of debt issue costs
and interest expense related to the 8.75% Notes and the PXP credit
facility.
(4) Reflects amortization of debt issue costs for the period, on a straight
line basis that approximates the interest method, over the life of the
debt agreements.
(5) Reflects interest expense for the period on the 8.75% Notes ($13.3
million) and the PXP credit facility ($4.6 million). Interest expense
with respect to the 8.75% Notes includes $0.2 million of amortization
of original issue discount. Interest expense with respect to the PXP
credit facility is computed based on the prime rate at the time the
borrowings were made (4.75%). A 1/8 of 1% change in the interest rate
with respect to the PXP credit facility would result in a $0.1 million
change in interest expense. Pro forma amount reflects interest expense
after capitalization of interest of $1.5 million.
F-4
(6) Reflects the income tax effect of the Debt Issuance Adjustments based
on our historical effective income tax rate of 39%.
Stock Appreciation Rights
(7) Plains Resources has received a favorable private letter ruling from
the Internal Revenue Service, stating that for U.S. federal income tax
purposes, a distribution by Plains Resources of PXP common stock owned
by it to its stockholders will generally be tax-free to both Plains
Resources and its stockholders. This proposed distribution is called
the "spin-off".
When the spin-off occurs, our employees holding options to acquire
Plains Resources common stock will receive, assuming a one-to-one
distribution ratio on the spin-off (one share of our common stock for
each share of Plains Resources common stock outstanding), an equal
number of stock appreciation rights, or SARs, with respect to our
common stock. The exercise price of the SARs will be based on the
relationship between the price of Plains Resources common stock and our
common stock at the time of the spin-off. If the SARs are in-the-money
at the time of the spin-off, we will recognize an initial accounting
charge as compensation expense equal to the aggregate in-the-money
value of the SARs deemed vested at that time. Assuming the market price
of Plains Resources common stock was $20.45 per share (the closing
price of Plains Resources on November 20, 2002) and the market price of
our common stock was $10.00 per share, our costs and expenses will
increase by approximately $2.4 million, and our net income will be
reduced by $1.5 million, or approximately $0.06 per share. Such charge
is not reflected in the unaudited pro forma combined financial
statements.
SARs are subject to variable accounting treatment. As a result, if the
spin-off occurs, at the end of each quarter, we will compare the
closing price of our common stock to the exercise price of each SAR. To
the extent the closing price exceeds the exercise price of each SAR, we
will recognize such excess as an accounting charge for the SARs deemed
vested to the extent such excess had not been recognized in previous
quarters. If such excess is less than the extent to which accounting
charges had been recognized in previous quarters, we will recognize the
difference as income in the quarter. These quarterly charges and income
will make our results of operations depend, in part on fluctuations in
the price of our common stock and could have a material adverse effect
on our results of operations.
F-5
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2001
(in thousands of dollars)
Upstream Plains
Subsidiaries Exploration
of Plains Debt & Production
Resources Reorganization Issuance Company
Historical Adjustments Adjustments Proforma(6)
------------ -------------- ----------- ------------
Revenues
Crude oil and liquids.................... $174,895 $ -- $ -- $174,895
Natural gas.............................. 28,771 -- -- 28,771
Other operating revenues................. 473 -- -- 473
--------- ------- -------- --------
204,139 -- -- 204,139
--------- ------- -------- --------
Costs and Expenses
Production expenses...................... 63,795 -- -- 63,795
General and administrative............... 10,210 -- -- 10,210
Depreciation, depletion and amortization. 24,105 -- 905 (3) 25,010
--------- ------- -------- --------
98,110 -- 905 99,015
--------- ------- -------- --------
Income from Operations..................... 106,029 -- (905) 105,124
Other Income (Expense)
Interest expense......................... (17,411) 17,216 (1) (21,784)(4) (21,979)
Interest and other income................ 463 -- -- 463
--------- ------- -------- --------
Income Before Income Taxes................. 89,081 17,216 (22,689) 83,608
Income tax expense....................... (34,388) (6,646)(2) 8,759 (5) (32,275)
--------- ------- -------- --------
Net Income................................. $ 54,693 $10,570 $(13,930) $ 51,333
========= ======= ======== ========
Earnings Per Share
Basic and diluted........................ $2.26 $ 2.12
Average Shares Outstanding
Basic and diluted........................ 24,200 24,200
Reorganization Adjustments
(1) Reflects the reversal of historical interest expense related to amounts
payable to Plains Resources since such amounts payable were contributed
to PXP under the terms of the Separation Agreement.
(2) Reflects the income tax effect of the Reorganization Adjustments based
on our historical effective income tax rate of 38.6%.
Debt Issuance Adjustments
(3) Reflects amortization of debt issue costs for the period, on a straight
line basis that approximates the interest method, over the life of the
debt agreements.
(4) Reflects interest expense for the period on the 8.75% Notes ($17.7
million) and the PXP credit facility ($6.2 million). Interest expense
with respect to the 8.75% Notes includes $0.2 million of amortization
of original issue discount. Interest expense with respect to the PXP
credit facility is computed based on the prime rate at the time the
borrowings were made (4.75%). A 1/8 of 1% change in the interest rate
with respect to the PXP credit facility would result in a $0.2 million
change in interest expense. Pro forma amount reflects interest expense
after capitalization of $2.5 million.
(5) Reflects the income tax effect of Debt Issuance Adjustments based on
our historical effective income tax rate of 38.6%.
F-6
Stock Appreciation Rights
(6) Plains Resources has received a favorable private letter ruling from
the Internal Revenue Service, stating that for U.S. federal income tax
purposes, a distribution by Plains Resources of PXP common stock owned
by it to its stockholders will generally be tax-free to both Plains
Resources and its stockholders. This proposed distribution is called
the "spin-off".
When the spin-off occurs, our employees holding options to acquire
Plains Resources common stock will receive, assuming a one-to-one
distribution ratio on the spin-off (one share of our common stock for
each share of Plains Resources common stock outstanding), an equal
number of stock appreciation rights, or SARs, with respect to our
common stock. The exercise price of the SARs will be based on the
relationship between the price of Plains Resources common stock and our
common stock at the time of the spin-off. If the SARs are in-the-money
at the time of the spin-off, we will recognize an initial accounting
charge as compensation expense equal to the aggregate in-the-money
value of the SARs deemed vested at that time. Assuming the market price
of Plains Resources common stock was $20.45 per share (the closing
price of Plains Resources on November 20, 2002) and the market price of
our common stock was $10.00 per share, our costs and expenses will
increase by approximately $2.4 million, and our net income will be
reduced by approximately $1.5 million, or $0.06 per share. Such charge
is not reflected in the unaudited pro forma combined financial
statements.
SARs are subject to variable accounting treatment. As a result, if the
spin-off occurs at the end of each quarter, we will compare the closing
price of our common stock to the exercise price of each SAR. To the
extent the closing price exceeds the exercise price of each SAR, we
will recognize such excess as an accounting charge for the SARs deemed
vested to the extent such excess had not been recognized in previous
quarters. If such excess is less than the extent to which accounting
charges had been recognized in previous quarters, we will recognize the
difference as income in the quarter. These quarterly charges and income
will make our results of operations depend, in part on fluctuations in
the price of our common stock and could have a material adverse effect
on our results of operations.
F-7
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2002 2001
------------- ------------
(in thousands)
ASSETS
Current Assets
Cash and cash equivalents.................................. $ 766 $ 13
Accounts receivable--Plains All American Pipeline, L.P..... 22,751 12,331
Other accounts receivable and current assets............... 4,778 4,051
Commodity hedging contracts................................ 453 21,787
Inventories................................................ 5,643 4,629
--------- ---------
34,391 42,811
--------- ---------
Property and Equipment, at cost
Oil and natural gas properties--full cost method
Subject to amortization.................................. 612,515 561,034
Not subject to amortization.............................. 35,479 33,371
Other property and equipment............................... 1,571 1,516
--------- ---------
649,565 595,921
Less allowance for depreciation, depletion and amortization (161,858) (140,804)
--------- ---------
487,707 455,117
--------- ---------
Other Assets................................................ 18,958 18,827
--------- ---------
$ 541,056 $ 516,755
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
Accounts payable and other current liabilities............. $ 56,143 $ 41,368
Commodity hedging contracts................................ 24,880 --
Payable to Plains Resources Inc............................ 3,357 --
Current maturities on long-term debt....................... 511 511
--------- ---------
84,891 41,879
--------- ---------
Payable to Plains Resources Inc............................. -- 235,161
--------- ---------
Long-Term Debt.............................................. 288,014 1,022
--------- ---------
Other Long-Term Liabilities................................. 3,543 1,413
--------- ---------
Deferred Income Taxes....................................... 44,481 57,193
--------- ---------
Commitments and Contingencies (Note 6)
Stockholder's Equity
Stockholder's equity....................................... 134,730 --
Combined owner's equity.................................... -- 164,203
Accumulated other comprehensive income..................... (14,603) 15,884
--------- ---------
120,127 180,087
--------- ---------
$ 541,056 $ 516,755
========= =========
See notes to consolidated financial statements.
F-8
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED CONSOLIDATED STATEMENTS OF INCOME
Nine Months Ended
September 30,
------------------
2002 2001
-------- --------
(in thousands)
Revenues
Crude oil sales to Plains All American Pipeline, L.P......... $129,563 $133,957
Natural gas sales............................................ 7,130 26,870
Other operating revenues..................................... 27 468
-------- --------
136,720 161,295
-------- --------
Costs and Expenses
Production expenses.......................................... 56,826 47,995
General and administrative................................... 7,362 7,074
Depreciation, depletion and amortization..................... 21,262 16,999
-------- --------
85,450 72,068
-------- --------
Income from Operations........................................ 51,270 89,227
Other Income (Expense)
Expenses of terminated public equity offering................ (1,700) --
Interest expense............................................. (14,427) (12,942)
Interest and other income.................................... 114 459
-------- --------
Income Before Income Taxes and Cumulative Effect of Accounting
Change...................................................... 35,257 76,744
Income tax expense
Current.................................................... (5,660) (5,180)
Deferred................................................... (8,097) (24,443)
-------- --------
Income Before Cumulative Effect of Accounting Change.......... 21,500 47,121
Cumulative effect of accounting change, net of tax benefit... -- (1,522)
-------- --------
Net Income.................................................... $ 21,500 $ 45,599
======== ========
Basic and Diluted Earnings Per Share..........................
Income before cumulative effect of accounting change......... $ 0.89 $ 1.95
Cumulative effect on accounting change....................... -- (0.06)
-------- --------
Net income................................................... $ 0.89 $ 1.89
======== ========
See notes to consolidated financial statements.
F-9
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months
Ended September 30,
-------------------
2002 2001
--------- --------
(in thousands)
Cash Flows From Operating Activities
Net income................................................. $ 21,500 $ 45,599
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization.................. 21,262 16,999
Deferred income taxes..................................... 8,097 24,443
Cumulative effect of adoption of accounting change........ -- 1,522
Change in derivative fair value........................... -- 1,055
Other noncash items....................................... 372 721
Change in assets and liabilities from operating activities:
Accounts receivable and other assets...................... (11,010) 3,293
Payable to Plains Resources Inc........................... 3,357 --
Accounts payable and other liabilities.................... 14,775 8,439
--------- --------
Net cash provided by operating activities.................. 58,353 102,071
--------- --------
Cash Flows From Investing Activities
Acquisition, exploration and developments costs............ (53,589) (99,346)
Additions to other property and equipment.................. (55) (107)
--------- --------
Net cash used in investing activities...................... (53,644) (99,453)
--------- --------
Cash Flows From Financing Activities
Principal payments of long-term debt....................... (511) (511)
Change in revolving credit facility........................ 90,700 --
Proceeds from debt issuance................................ 196,752 --
Debt issuance costs........................................ (5,469) --
Contribution from Plains Resources Inc..................... 5,000 --
Distribution to Plains Resources Inc....................... (311,964) --
Receipts from (payments to) Plains Resources Inc........... 21,536 (2,640)
--------- --------
Net cash used in financing activities...................... (3,956) (3,151)
--------- --------
Net increase (decrease) in cash and cash equivalents....... 753 (533)
Cash and cash equivalents, beginning of period............. 13 536
--------- --------
Cash and cash equivalents, end of period................... $ 766 $ 3
========= ========
See notes to consolidated financial statements.
F-10
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Nine Months
Ended September 30,
-----------------
2002 2001
-------- -------
(in thousands)
Net Income........................................... $ 21,500 $45,599
Other Comprehensive Income (Loss):
Cumulative effect of change in accounting principle. -- 6,967
Commodity hedging contracts
Reclassification adjustment for settled contracts. (4,562) 1,950
Change in fair value.............................. (34,882) (2,327)
Interest rate swap.................................. (167) --
-------- -------
(30,487) 6,590
-------- -------
Comprehensive Income (Loss).......................... $ (8,987) $52,189
======== =======
See notes to consolidated financial statements.
F-11
PLAINS EXPLORATION & PRODUCTION COMPANY
UNAUDITED STATEMENT OF STOCKHOLDER'S EQUITY
Accumulated
Combined Common Stock Additional Other
- Owner's ------------- Paid-in Contribution Retained Comprehensive
Equity Shares Amount Capital Receivable Earnings Income Total
- --------- ------ ------ ---------- ------------ -------- ------------- ---------
Balance at December 31, 2001....... $ 164,203 -- $ -- $ -- $ -- $ -- $ 15,884 $ 180,087
Net income......................... 14,082 -- -- -- -- 7,418 -- 21,500
Contribution of amounts due to
Plains Resources Inc.............. 255,991 -- -- -- -- -- -- 255,991
Distribution to Plains Resources
Inc............................... (311,964) -- -- -- -- -- -- (311,964)
Cash contribution by Plains
Resources Inc..................... 5,000 -- -- -- -- -- -- 5,000
Incorporation and capitalization of
Plains Exploration & Production
Company........................... (127,312) 24,200 242 127,070 -- -- -- --
Note receivable contribution by
Plains Resources Inc.............. -- -- -- 7,200 (7,200) -- -- --
Other comprehensive income......... -- -- -- -- -- -- (30,487) (30,487)
--------- ------ ---- -------- ------- ------ -------- ---------
Balance at September 30, 2002...... $ -- 24,200 $242 $134,270 $(7,200) $7,418 $(14,503) $ 120,127
========= ====== ==== ======== ======= ====== ======== =========
Balance at December 31, 2000....... $ 111,032 -- $ -- $ -- $ -- $ -- $ -- $ 111,032
Net income......................... 45,999 -- -- -- -- -- -- 45,599
Other comprehensive income......... -- -- -- -- -- -- 6,590 6,590
--------- ------ ---- -------- ------- ------ -------- ---------
Balance at September 30, 2001...... $ 156,631 -- $ -- $ -- $ -- $ -- $ 6,590 $ 163,221
========= ====== ==== ======== ======= ====== ======== =========
See notes to consolidated financial statements.
F-12
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Note 1 -- Organization and Significant Accounting Policies
Organization
The consolidated financial statements of Plains Exploration & Production
Company ("PXP", "us", "our", or "we") include the accounts of its wholly-owned
subsidiaries, Arguello Inc., Plains Illinois, Inc., PMCT Inc. and Plains
Resources International Inc. PXP is a Delaware corporation that was converted
from a limited partnership in September 2002 and is a wholly-owned subsidiary
of Plains Resources Inc. ("Plains Resources"). All significant intercompany
transactions have been eliminated.
Under the terms of a Master Separation Agreement between Plains Resources
and PXP, on July 3, 2002, Plains Resources contributed to PXP: (i) 100% of the
capital stock of its wholly-owned subsidiaries, Arguello Inc., Plains Illinois,
Inc., PMCT Inc. and Plains Resources International Inc.; and (ii) all amounts
payable to it by PXP and its subsidiary companies. These transactions are
referred to as the "reorganization". In addition, in September 2002 Plains
Resources made (i) a $5.0 million cash contribution; and (ii) a $7.2 million
contribution in the form of a promissory note payable, both as part of the
working capital for the upstream assets contributed to us. The promissory note
bears interest at 2.5% and is due on December 15, 2002. The contribution of the
amounts payable to Plains Resources, the cash contribution and the contribution
of the promissory note are all reflected in Stockholder's Equity.
Effective at the time of the reorganization PXP assumed direct ownership
and control of Arguello Inc., Plains Illinois, Inc., PMCT Inc. and Plains
Resources International Inc. Accordingly, for periods subsequent to the
reorganization, the financial information is presented on a consolidated basis.
For periods prior to the reorganization, the historical operations of the
businesses owned by PXP, Arguello Inc., Plains Illinois, Inc., PMCT Inc. and
Plains Resources International Inc., all previously referred to as the Upstream
Subsidiaries of Plains Resources Inc., were presented on a carve-out combined
basis since no direct owner relationship existed among the various operations
comprising these businesses. Accordingly, Plains Resources' net investment in
the businesses (combined owners' equity) was shown in lieu of stockholder's
equity in the combined financial statements.
PXP has the authority to issue 5.0 million shares of preferred stock, par
value $0.01 per share, and 100.0 million shares of common stock, par value
$0.01 per share. In September 2002 PXP was capitalized with 24.2 million shares
of common stock, all of which are owned by Plains Resources. In accordance with
SEC Staff Accounting Bulletin No. 98, this capitalization has been
retroactively reflected for purposes for calculating earnings per share for all
periods presented in the accompanying combined statements of income. In
computing EPS, no adjustments were made to reported net income, and no
potential common stock exists. The weighted average shares outstanding for
computing both basic and diluted EPS was 24.2 million shares for all periods
presented.
These consolidated financial statements and related notes present our
financial position as of September 30, 2002 and December 31, 2001 and the
results of our operations, our cash flows, our comprehensive income and the
changes in our stockholder's equity for the nine months ended September 30,
2002 and 2001. The results for the nine months ended September 30, 2002 and
2001, are not necessarily indicative of the final results to be expected for
the full year. All adjustments, consisting only of normal recurring
adjustments, that in the opinion of management were necessary for a fair
statement of the results for the interim periods, have been reflected. These
consolidated financial statements should be read in conjunction with the
audited combined financial statements of the Upstream Subsidiaries of Plains
Resources Inc. for the year ended December 31, 2001.
F-13
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
We are independent energy companies that are engaged in the "Upstream" oil
and gas business. The Upstream business acquires, exploits, develops, explores
for and produces crude oil and natural gas. Our Upstream activities are all
located in the United States.
Under the terms of a service agreement (the "Service Agreement"), Plains
Resources provides us with financial intermediary, treasury and other services.
Such services include, but are not limited to: management, tax, accounting,
payroll, insurance, employee benefits, legal and financial.
These financial statements include allocations of direct and indirect
corporate and administrative costs of Plains Resources. The methods by which
such costs are estimated and allocated to us are deemed reasonable by Plains
Resources' management; however, such allocations and estimates are not
necessarily indicative of the costs and expenses that would have been incurred
had we operated as a separate entity. Allocations of such costs are considered
to be related party transactions and are discussed in Note 5.
Significant Accounting Policies
Oil and Gas Properties. We follow the full cost method of accounting
whereby all costs associated with property acquisition, exploration,
exploitation and development activities are capitalized. Such costs include
internal general and administrative costs such as payroll and related benefits
and costs directly attributable to employees engaged in acquisition,
exploration, exploitation and development activities ($4.4 million and $6.2
million in the nine months ended September 30, 2002 and 2001, respectively).
General and administrative costs associated with production, operations,
marketing and general corporate activities are expensed as incurred. These
capitalized costs along with our estimate of future development and abandonment
costs, net of salvage values and other considerations, are amortized to expense
by the unit-of-production method using engineers' estimates of proved oil and
natural gas reserves. The costs of unproved properties are excluded from
amortization until the properties are evaluated. Interest is capitalized on oil
and natural gas properties not subject to amortization and in the process of
development ($1.9 million and $2.4 million in the nine months ended September
30, 2002 and 2001, respectively). Proceeds from the sale of oil and natural gas
properties are accounted for as reductions to capitalized costs unless such
sales involve a significant change in the relationship between costs and the
estimated value of proved reserves, in which case a gain or loss is recognized.
Unamortized costs of proved properties are subject to a ceiling which limits
such costs to the present value of estimated future cash flows from proved oil
and natural gas reserves of such properties (including the effect of any
related hedging activities) reduced by future operating expenses, development
expenditures and abandonment costs (net of salvage values), and estimated
future income taxes thereon.
Other Property and Equipment. Other property and equipment is recorded at
cost and consists primarily of office furniture and fixtures and computer
hardware and software. Acquisitions, renewals, and betterments are capitalized;
maintenance and repairs are expensed. Depreciation is provided using the
straight-line method over estimated useful lives of three to seven years. Net
gains or losses on property and equipment disposed of are included in interest
and other income in the period in which the transaction occurs.
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
F-14
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Significant estimates made by management include
(1) crude oil and natural gas reserves, (2) depreciation, depletion and
amortization, including future abandonment costs, (3) income taxes and (4)
accrued liabilities. Although management believes these estimates are
reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand
deposits and funds invested in highly liquid instruments with original
maturities of three months or less. At September 30, 2002, the majority of cash
and cash equivalents is concentrated in one institution and at times may exceed
federally insured limits. We periodically assess the financial condition of the
institution and believe that any possible credit risk is minimal.
Inventory. Crude oil inventories are carried at the lower of the cost to
produce or market value. Materials and supplies inventory is stated at the
lower of cost or market with cost determined on an average cost method.
Inventory consists of the following (in thousands):
September 30, December 31,
2002 2001
------------- ------------
Crude oil............. $ 855 $ 428
Materials and supplies 4,788 4,201
------ ------
$5,643 $4,629
====== ======
Federal and State Income Taxes. Income taxes are accounted for in
accordance with Statement of Financial Accounting Standards No. 109, Accounting
for Income Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax
liabilities and assets for the expected future tax consequences of events that
have been included in the financial statements or tax returns. Under this
method, deferred tax liabilities and assets are determined based on the
difference between the financial statement and tax bases of assets and
liabilities using tax rates in effect for the year in which the differences are
expected to reverse. A valuation allowance is established to reduce deferred
tax assets if it is more than likely than not that the related tax benefits
will not be realized.
Under the terms of a tax allocation agreement, our taxable income or loss
is included in the consolidated income tax returns filed by Plains Resources.
Each member of a consolidated group is jointly and severally liable for the
federal income tax liability of each other member of the consolidated group.
Accordingly, although this agreement allocates tax liabilities between us and
Plains Resources during the period in which we are included in Plains
Resources' consolidated group, we could be liable if any federal tax liability
is incurred, but not discharged, by any other member of Plains Resources'
consolidated group. In addition, to the extent Plains Resources' net operating
losses are used in the consolidated return to offset our taxable income from
operations during the period January 1, 2002 through the spin-off, we will
reimburse Plains Resources for the reduction in our federal income tax
liability resulting from the utilization of such net operating losses, but such
reimbursement shall not exceed $3.0 million exclusive of any interest accruing
under the agreement.
Income tax obligations reflected in these financial statements are
calculated assuming we filed a separate consolidated income tax return. Income
taxes currently payable are included in Payable to Plains Resources in the
consolidated balance sheet at December 31, 2001.
Revenue Recognition. Oil and gas revenue from our interests in producing
wells is recognized when the production is delivered and the title transfers.
F-15
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
Derivative Financial Instruments (Hedging). We utilize various derivative
instruments to reduce our exposure to fluctuations in the market price of crude
oil. The derivative instruments consist primarily of crude oil swap and option
contracts entered into with financial institutions.
Recent Accounting Pronouncements. In June 2001 Statement of Financial
Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement
Obligations was issued. SFAS No. 143 requires entities to record the fair value
of a liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset. Subsequently, the asset retirement cost should be allocated
to expense using a systematic and rational method. SFAS No. 143 is effective
for fiscal years beginning after June 15, 2002. We are currently assessing the
impact of SFAS No. 143 and at this time cannot reasonably estimate the effect
of this statement on our consolidated financial statements.
In April 2002, Statement of Accounting Standards ("SFAS") No. 145,
"Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement
No. 13, and Technical Corrections," was issued. SFAS 145 rescinds SFAS 4 and
SFAS 64 related to classification of gains and losses on debt extinguishment
such that most debt extinguishment gains and losses will no longer be
classified as extraordinary. SFAS 145 also amends SFAS 13 with respect to
sales-leaseback transactions. The provisions of SFAS 145 have no effect on our
financials.
In July 2002, SFAS No. 146, "Accounting For Costs Associated with Exit or
Disposal Activities" was issued. SFAS 146 is effective for exit or disposal
activities initiated after December 31, 2002 and does not require previously
issued financial statements to be restated. We will account for exit or
disposal activities initiated after December 31, 2002 in accordance with the
provisions of SFAS 146.
Note 2 -- Proposed Spin-off and Terminated Public Offering
Plains Resources has received a favorable private letter ruling from the
Internal Revenue Service (the "IRS"), stating that, for United States federal
income tax purposes, a distribution of our capital stock to the Plains
Resources stockholders would generally be tax-free to both Plains Resources and
its stockholders. We call this proposed distribution the "spin-off."
On June 21, 2002 we filed a registration statement on Form S-1 with the
Securities and Exchange Commission for the initial public offering (the "IPO"),
of our common stock. We terminated the IPO in October 2002, primarily due to
market conditions. As a result, costs and expenses of $1.7 million incurred in
connection with the IPO were charged to expense during the third quarter of
2002.
Note 3 -- Derivative Instruments and Hedging Activities
We have entered into various derivative instruments to reduce our exposure
to fluctuations in the market price of crude oil. The derivative instruments
consist primarily of crude oil swap and option contracts entered into with
financial institutions. Derivative instruments are accounted for in accordance
with SFAS No. 133 "Accounting for Derivative Instruments and Hedging
Activities" as amended by SFAS 137 and SFAS 138 ("SFAS 133"). Under SFAS 133,
all derivative instruments are recorded on the balance sheet at fair value. If
the derivative does not qualify as a hedge or is not designated as a hedge, the
gain or loss on the derivative is recognized currently in earnings. If the
derivative qualifies for hedge accounting, the unrealized gain or loss on the
derivative is deferred in accumulated Other Comprehensive Income ("OCI"), a
component of Stockholder's Equity. At September 30, 2002 all open positions
qualified for hedge accounting.
F-16
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
Gains and losses on crude oil hedging instruments related to OCI and
adjustments to carrying amounts on hedged volumes are included in oil and gas
revenues in the period that the related volumes are delivered. Gains and losses
on crude oil hedging instruments representing hedge ineffectiveness, which is
measured on a quarterly basis, are included in oil and gas revenues in the
period in which they occur. No ineffectiveness was recognized in 2002 or 2001.
At December 31, 2001, OCI consisted of $26.6 million ($15.9 million, net of
tax) of unrealized gains on our open crude oil hedging instruments. As oil
prices increased significantly during the first nine months of 2002, the fair
value of our open crude oil hedging positions decreased $58.5 million ($34.9
million, after tax). At September 30, 2002, OCI consisted of $24.4 million
($14.4 million after tax) of unrealized losses on our crude oil hedging
instruments and $0.3 million ($0.2 million, net of tax) loss related to our
interest rate swap. At September 30, 2002, the assets and liabilities related
to our open crude oil hedging instruments were included in current assets ($0.2
million), other assets ($2.1 million), current liabilities ($24.9 million),
other long-term liabilities ($1.8 million) and deferred income taxes (a tax
benefit of $10.0 million).
During the first nine months of 2002, $7.5 million ($4.6 million net of
tax) in losses from the settlement of crude oil hedging instruments were
reclassified from OCI and charged to income as a reduction of oil sales
revenues. Oil sales revenues for the period have also been reduced by a $0.6
million non-cash expense related to the amortization of option premiums. As of
September 30, 2002, $14.6 million of deferred net losses on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
the next twelve-month period.
We utilize various derivative instruments to hedge our exposure to price
fluctuations on crude oil sales. The derivative instruments consist primarily
of cash-settled crude oil option and swap contracts entered into with financial
institutions. We do not currently have any natural gas hedges. We also utilize
interest rate swaps and collars to manage the interest rate exposure on our
long-term debt. We currently have an interest rate swap agreement that expires
in October 2004, under which we receive LIBOR and pay 3.9% on a notional amount
of $7.5 million. The interest rate swap fixes the interest rate on $7.5 million
of borrowings under our credit facility at 3.9% plus the LIBOR margin set forth
in the credit facility (5.3% at September 30, 2002).
Our average realized price for crude oil is sensitive to changes in
location and quality differential adjustments as set forth in our crude oil
sales contracts. At September 30, 2002 we had basis risk swap contracts on our
Illinois Basin production through September 30, 2003. The swaps fix the
location differential portion of 2,600 barrels per day at $0.38, $0.43, $0.57
and $0.39 per barrel for the fourth quarter of 2002, and the first, second and
third quarter of 2003, respectively.
F-17
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
At September 30, 2002 we had the following open crude oil hedge positions:
Barrels Per Day
---------------------
2002
-------
4th Qtr 2003 2004
------- ------ ------
Calls
Average price $35.17/bbl........ 9,000 -- --
Collars
Average cap price of $27.04/bbl. -- 2,000 --
Swaps
Average price $24.22/bbl........ 20,000 -- --
Average price $24.36/bbl........ -- 15,250 --
Average price $23.53/bbl........ -- -- 12,500
Location and quality differentials attributable to our properties and the
cost of the hedges are not included in the foregoing prices. Because of the
quality and location of our crude oil production, these adjustments will reduce
our net price per barrel.
Note 4 -- Long-Term Debt
On July 3, 2002, PXP and Plains E&P Company, our wholly owned subsidiary
that has no material assets and was formed for the sole purpose of being a
corporate co-issuer of certain notes, issued $200.0 million principal amount of
8.75% Senior Subordinated Notes due 2012 (the "8.75% notes") at an issue price
of 98.376%. The 8.75% notes are our unsecured general obligations, are
subordinated in right of payment to all of our existing and future senior
indebtedness and are jointly and severally guaranteed on a full, unconditional
basis by all of our existing and future domestic restricted subsidiaries. Also
on July 3, 2002 we entered into a $300.0 million credit facility with a $225.0
million borrowing base (the "PXP credit facility"). The proceeds from the 8.75%
notes, $195.3 million after deducting $3.2 million in issue discount and $1.5
million in underwriting fees, and $117.6 million initially borrowed under the
PXP credit facility were used to pay a $312.0 million cash distribution to
Plains Resources and to pay certain expenses related to obtaining the PXP
credit facility.
As of September 30, 2002 $90.7 million was outstanding under the PXP credit
facility. The PXP credit facility provides for a borrowing base of $225.0
million that will be reviewed every six months, with the lenders and PXP each
having the right to one annual interim unscheduled redetermination, and
adjusted based on our oil and gas properties, reserves, other indebtedness and
other relevant factors, and matures in 2005. Additionally, the PXP credit
facility contains a $30.0 million sub-limit on letters of credit (of which $5.2
million had been issued as of September 30, 2002). To secure borrowings, we
pledged 100% of the shares of stock of our domestic subsidiaries and gave
mortgages covering 80% of the total present value of our domestic oil and gas
properties.
Amounts borrowed under the PXP credit facility bear an annual interest
rate, at our election, equal to either: (i) the Eurodollar rate, plus from
1.375% to 1.75%; or (ii) the greatest of (1) the prime rate, as determined by
JPMorganChase Bank, (2) the certificate of deposit rate, plus 1.0%, or (3) the
federal funds rate, plus 0.5%; plus an additional 0.125% to 0.5% for each of
(1)-(3). The amount of interest payable on outstanding borrowings is based on
(1) the utilization rate as a percentage of the total amount of funds borrowed
under the credit facility to the borrowing base and (2) our long-term debt
rating. Commitment fees and letter of credit fees under the PXP credit facility
are based on the
F-18
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
utilization rate and long-term debt rating. Commitment fees range from 0.375%
to 0.5% of the unused portion of the borrowing base. Letter of credit fees
range from 1.375% to 1.75%. The issuer of any letter of credit will receive an
issuing fee of 0.125% of the undrawn amount.
The PXP credit facility contains negative covenants that limit our ability,
as well as the ability of our subsidiaries, to make dividends to Plains
Resources or enter into other transactions with Plains Resources and its
subsidiaries (other than us and our subsidiaries). In addition, the PXP credit
facility, among other things, limits our ability to incur additional debt, pay
dividends on stock, make distributions of cash or property, change the nature
of our business or operations, redeem stock or redeem subordinated debt, make
investments, create liens, enter into leases, sell assets, sell capital stock
of subsidiaries, create subsidiaries, guarantee other indebtedness, enter into
agreements that restrict dividends from subsidiaries, enter into certain types
of swap agreements, enter into gas imbalance or take-or-pay arrangements, merge
or consolidate and enter into transactions with affiliates. In addition, the
PXP credit facility requires us to maintain a current ratio, which includes
availability, of at least 1.0 to 1.0 and a ratio of total debt to earnings
before interest, depreciation, depletion, amortization and income taxes of no
more than 4.5 to 1.0. At September 30, 2002, we were in compliance with the
covenants contained in the PXP credit facility and could have borrowed the full
$225.0 million available under the PXP credit facility.
The 8.75% notes are our unsecured general obligations, are subordinated in
right of payment to all of our existing and future senior indebtedness and are
jointly and severally guaranteed on a full, unconditional basis by all of our
existing and future domestic restricted subsidiaries. The indenture governing
the notes limits our ability to make dividends to Plains Resources or enter
into other transactions with Plains Resources and its subsidiaries (other than
us and our subsidiaries). The indenture also limits our ability, as well as the
ability of our subsidiaries, among other things, to incur additional
indebtedness, make certain investments, make restricted payments, sell assets,
enter into agreements containing dividends and other payment restrictions
affecting subsidiaries, enter into transactions with affiliates, create liens,
merge, consolidate and transfer assets and enter into different lines of
business. In the event of a change of control, as defined in the indenture, we
will be required to make an offer to repurchase the notes at 101% of the
principal amount thereof, plus accrued and unpaid interest to the date of the
repurchase. The indenture governing the 8.75% notes will permit the spin-off
and the spin-off will not, in itself, constitute a change of control for
purposes of the indenture.
The 8.75% notes are not redeemable until July 1, 2007. On or after that
date they are redeemable, at our option, at 104.375% of the principal amount
for the twelve-month period ending June 30, 2008, at 102.917% of the principal
amount for the twelve-month period ending June 30, 2009, at 101.458% of the
principal amount for the twelve-month period ending June 30, 2010 and at 100%
of the principal amount thereafter. In each case, accrued interest is payable
to the date of redemption.
We also have a note with an outstanding principal balance of $1.0 million
at September 30, 2002 that was issued in connection with the purchase of a
production payment on certain of our producing properties. The note bears
interest at 8%, payable annually, and requires an annual principal payment of
$511,000 through 2004.
Note 5 -- Related Party Transactions
Prior to the reorganization, we used a centralized cash management system
under which our cash receipts were remitted to Plains Resources and our cash
disbursements were funded by Plains
F-19
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
Resources. We were charged interest on any amounts, other than income taxes
payable, due to Plains Resources at the average effective interest rate of
Plains Resources long-term debt. For the nine months ended September 30, 2002
and 2001 we were charged $10.1 million and $12.8 million, respectively, of
interest on amounts payable to Plains Resources. Of such amounts, $8.7 million
and $10.5 million was included in interest expense in 2002 and 2001,
respectively, and $1.4 million and $2.3 million was capitalized in oil and gas
properties in 2002 and 2001, respectively.
To compensate Plains Resources for services rendered under the Services
Agreement, we are allocated direct and indirect corporate and administrative
costs of Plains Resources. Such costs for the nine months ended September 30,
2002 and 2001 totaled $7.1 million and $5.4 million, respectively. Of such
amounts, $5.0 million and $4.3 million was included in general and
administrative expense in 2002 and 2001, respectively, and $2.1 million and
$1.1 million was capitalized in oil and gas properties in 2002 and 2001,
respectively.
In addition, prior to the reorganization Plains Resources entered into
various derivative instruments to reduce our exposure to decreases in the
market price of crude oil. At the time of the reorganization, all open
derivative instruments held by Plains Resources on our behalf were assigned to
us.
Note 6 -- Commitments, Contingencies and Industry Concentration
Commitments and Contingencies
Under the amended terms of an asset purchase agreement with respect to
certain of our onshore California properties, commencing with the year
beginning January 1, 2000, and each year thereafter, we are required to plug
and abandon 20% of the then remaining inactive wells, which currently aggregate
approximately 149. To the extent we elect not to plug and abandon the number of
required wells, we are required to escrow an amount equal to the greater of
$25,000 per well or the actual average plugging cost per well in order to
provide for the future plugging and abandonment of such wells. In addition, we
are required to expend a minimum of $600,000 per year in each of the ten years
beginning January 1, 1996, and $300,000 per year in each of the succeeding five
years to remediate oil contaminated soil from existing well sites, provided
there are remaining sites to be remediated. In the event we do not expend the
required amounts during a calendar year, we are required to contribute an
amount equal to 125% of the actual shortfall to an escrow account. We may
withdraw amounts from the escrow account to the extent we expend excess amounts
in a future year. Through September 30, 2002, we have not been required to make
contributions to an escrow account.
In connection with the acquisition of our interest in the Point Arguello
field, offshore California, we assumed our 52.6% share of (1) plugging and
abandoning all existing well bores, (2) removing conductors, (3) flushing
hydrocarbons from all lines and vessels and (4) removing/abandoning all
structures, fixtures and conditions created subsequent to closing. The seller
retained the obligation for all other abandonment costs, including but not
limited to (1) removing, dismantling and disposing of the existing offshore
platforms, (2) removing and disposing of all existing pipelines and (3)
removing, dismantling, disposing and remediation of all existing onshore
facilities.
Although we obtained environmental studies on our properties in California
and Illinois and we believe that such properties have been operated in
accordance with standard oil field practices, certain of the fields have been
in operation for more than 90 years, and current or future local, state and
federal environmental laws and regulations may require substantial expenditures
to comply with such
F-20
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
rules and regulations. In connection with the purchase of certain of our
onshore California properties, we received a limited indemnity for certain
conditions if they violate applicable local, state and federal environmental
laws and regulations in effect on the date of such agreement. We believe that
we do not have any material obligations for operations conducted prior to our
acquisition of the properties, other than our obligation to plug existing wells
and those normally associated with customary oil field operations of similarly
situated properties. There can be no assurance that current or future local,
state or federal rules and regulations will not require us to spend material
amounts to comply with such rules and regulations or that any portion of such
amounts will be recoverable under the indemnity.
Consistent with normal industry practices, substantially all of our crude
oil and natural gas leases require that, upon termination of economic
production, the working interest owners plug and abandon non-producing
wellbores, remove tanks, production equipment and flow lines and restore the
wellsite. We estimate, based on our year-end 2001 reserve report, the cost to
perform these tasks is approximately $19.3 million, net of salvage value and
other considerations.
As is common within the industry, we have entered into various commitments
and operating agreements related to the exploration and development of and
production from proved crude oil and natural gas properties and the marketing,
transportation, terminalling and storage of crude oil. It is management's
belief that such commitments will be met without a material adverse effect on
our financial position, results of operations or cash flows.
On September 18, 2002 Stocker Resources Inc. ("Stocker", a wholly owned
subsidiary of Plains Resources), filed a declaratory judgment action against
Commonwealth Energy Corporation (doing business as electricAmerica), or
Commonwealth, in the Superior Court of Orange County, California relating to
the termination of an electric service contract between Stocker and
Commonwealth. Pursuant to the agreement, Commonwealth had agreed to supply
Stocker with electricity and Stocker had obtained a $1.5 million performance
bond in favor of Commonwealth to secure its payment obligations under the
agreement. Stocker terminated the contract in accordance with its terms and
Commonwealth notified Stocker of its intent to draw upon the performance bond.
Stocker is seeking a declaratory judgment that it was entitled to terminate the
contract and that Commonwealth has no basis for proceeding against Stocker's
related performance bond. Also on September 18, 2002, Stocker was named a
defendant in an action brought by Commonwealth in the Superior Court of Orange
County, California for breach of the electric service contract. Commonwealth
alleges that Stocker breached the terms of the contract by the termination and
its implied covenant of good faith and fair dealing and is seeking unspecified
damages. Under the master separation agreement, we are required to indemnify
Stocker and Plains Resources for damages Plains Resources or Stocker incur as a
result of this action. At this time we are not in a position to express a
judgment concerning the potential exposure or likely outcome of this matter. We
intend to vigorously defend this matter.
In the ordinary course of our business, we are a claimant and/or defendant
in various other legal proceedings. We do not believe that the outcome of these
legal proceedings, individually or in the aggregate, will have a materially
adverse effect on our financial condition, results of operations or cash flows.
Industry Concentration
Financial instruments which potentially subject us to concentrations of
credit risk consist principally of accounts receivable with respect to our oil
and gas operations and derivative instruments related to our hedging
activities. Plains All American Pipeline, L.P. ("PAA"), in which Plains
Resources
F-21
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
holds a 25% interest, is the exclusive marketer/purchaser for all of our equity
oil production. This concentration has the potential to impact our overall
exposure to credit risk, either positively or negatively, in that PAA may be
affected by changes in economic, industry or other conditions. We do not
believe the loss of PAA as the exclusive purchaser of our equity production
would have a material adverse affect on our results of operations. We believe
PAA could be replaced by other purchasers under contracts with similar terms
and conditions. The contract counterparties for our derivative commodity
contracts are all major financial institutions with Standard & Poor's ratings
of A or better. Three of the financial institutions are participating lenders
in the PXP credit facility, with one such counterparty holding contracts that
represent approximately 32% of the fair value of all of our open positions at
September 30, 2002.
There are a limited number of alternative methods of transportation for our
production. Substantially all of our oil and gas production is transported by
pipelines, trucks and barges owned by third parties. The inability or
unwillingness of these parties to provide transportation services to us for a
reasonable fee could result in our having to find transportation alternatives,
increased transportation costs or involuntary curtailment of a significant
portion of our oil and gas production which could have a negative impact on
future results of operations or cash flows.
Note 7 -- Consolidating Financial Statements
PXP and Plains E&P Company are the co-issuers of the 8.75% notes discussed
in Note 4. The 8.75% notes are jointly and severally guaranteed on a full and
unconditional basis by Arguello Inc., Plains Illinois Inc., PMCT Inc. and
Plains Resources International Inc. (referred to as "Guarantor Subsidiaries").
The following financial information presents consolidating financial
statements, which include:
. PXP (the "Issuer");
. the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries");
. elimination entries necessary to consolidate the Issuer and Guarantor
Subsidiaries; and
. the company on a consolidated basis.
Plains E&P Company has no material assets or operations; accordingly,
Plains E&P Company has been omitted from the Issuer financial information.
F-22
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING BALANCE SHEET
SEPTEMBER 30, 2002
Guarantor Intercompany
Issuer Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------
(in thousands)
ASSETS
Current Assets
Cash and cash equivalents....................... $ 744 $ 22 $ -- $ 766
Accounts receivable and other current assets.... 19,693 7,836 -- 27,529
Commodity hedging contracts..................... 203 250 -- 453
Inventories..................................... 4,146 1,497 -- 5,643
-------- -------- ------- ---------
24,786 9,605 -- 34,391
-------- -------- ------- ---------
Property and Equipment, at cost
Oil and natural gas properties--full cost method
Subject to amortization....................... 495,693 116,822 -- 612,515
Not subject to amortization................... 20,941 14,538 -- 35,479
Other property and equipment.................... 1,373 198 -- 1,571
-------- -------- ------- ---------
518,007 131,558 -- 649,565
Less allowance for depreciation, depletion and
amortization.................................. (71,051) (90,807) -- (161,858)
-------- -------- ------- ---------
446,956 40,751 -- 487,707
-------- -------- ------- ---------
Investment in and Advances to Subsidiaries....... 34,721 (62,647) 27,926 --
-------- -------- ------- ---------
Other Assets..................................... 19,718 (760) -- 18,958
-------- -------- ------- ---------
$526,181 $(13,051) $27,926 $ 541,056
======== ======== ======= =========
LIABILITIES AND COMBINED OWNER'S EQUITY
Current Liabilities
Accounts payable and other current liabilities.. $ 48,229 $ 7,914 $ -- $ 56,143
Commodity hedging contracts..................... 15,172 9,708 -- 24,880
Payable to Plains Resources Inc................. 3,357 -- 3,357
Current maturities on long-term debt............ 511 -- -- 511
-------- -------- ------- ---------
67,269 17,622 -- 84,891
-------- -------- ------- ---------
Payable to Plains Resources Inc.................. -- -- -- --
-------- -------- ------- ---------
Long-Term Debt................................... 288,014 -- -- 288,014
-------- -------- ------- ---------
Other Long-Term Liabilities...................... 1,343 2,200 -- 3,543
-------- -------- ------- ---------
Deferred Income Taxes............................ 49,428 (4,947) -- 44,481
-------- -------- ------- ---------
Stockholder's Equity
Stockholder's equity............................ 134,730 (21,849) 21,849 134,730
Accumulated other comprehensive income.......... (14,603) (6,077) 6,077 (14,603)
-------- -------- ------- ---------
120,127 (27,926) 27,926 120,127
-------- -------- ------- ---------
$526,181 $(13,051) $27,926 $ 541,056
======== ======== ======= =========
F-23
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING BALANCE SHEET
December 31, 2001
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
-------- ------------ ------------ ---------
(in thousands)
ASSETS
Current Assets
Cash and cash equivalents....................... $ 11 $ 2 $ -- $ 13
Accounts receivable and other current assets.... 10,703 5,679 -- 16,382
Commodity hedging contracts..................... 13,872 7,915 -- 21,787
Inventories..................................... 3,252 1,377 -- 4,629
-------- -------- ------- ---------
27,838 14,973 -- 42,811
-------- -------- ------- ---------
Property and Equipment, at cost
Oil and natural gas properties--full cost method
Subject to amortization....................... 450,038 110,996 -- 561,034
Not subject to amortization................... 19,676 13,695 -- 33,371
Other property and equipment.................... 1,322 194 -- 1,516
-------- -------- ------- ---------
471,036 124,885 -- 595,921
Less allowance for depreciation, depletion and
amortization.................................. (56,137) (84,667) -- (140,804)
-------- -------- ------- ---------
414,899 40,218 -- 455,117
-------- -------- ------- ---------
Investment in and Advances to Subsidiaries....... (21,496) -- 21,496 --
-------- -------- ------- ---------
Other Assets..................................... 16,275 2,552 -- 18,827
-------- -------- ------- ---------
$437,516 $ 57,743 $21,496 $ 516,755
======== ======== ======= =========
LIABILITIES AND COMBINED OWNERS' EQUITY
Current Liabilities
Accounts payable and other current liabilities.. $ 29,822 $ 11,546 $ -- $ 41,368
Current maturities on long-term debt............ 511 -- -- 511
-------- -------- ------- ---------
30,333 11,546 -- 41,879
-------- -------- ------- ---------
Payable to Plains Resources Inc.................. 172,603 62,558 -- 235,161
-------- -------- ------- ---------
Long-Term Debt................................... 1,022 -- -- 1,022
-------- -------- ------- ---------
Other Long-Term Liabilities...................... -- 1,413 -- 1,413
-------- -------- ------- ---------
Deferred Income Taxes............................ 53,471 3,722 -- 57,193
-------- -------- ------- ---------
Combined Owners' Equity
Owner's equity.................................. 164,203 (25,889) 25,889 164,203
Accumulated other comprehensive income.......... 15,884 4,393 (4,393) 15,884
-------- -------- ------- ---------
180,087 (21,496) 21,496 180,087
-------- -------- ------- ---------
$437,516 $ 57,743 $21,496 $ 516,755
======== ======== ======= =========
F-24
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING STATEMENT OF INCOME
Nine Months Ended September 30, 2002
Guarantor Intercompany
Issuer Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------
(in thousands)
Revenues
Crude oil and liquids........................ $92,692 $36,871 $ -- $129,563
Natural gas.................................. 7,130 -- -- 7,130
Other........................................ -- 27 -- 27
------- ------- ------- --------
99,822 36,898 -- 136,720
------- ------- ------- --------
Costs and Expenses
Production expenses.......................... 38,142 18,684 -- 56,826
General and administrative................... 6,281 1,081 -- 7,362
Depreciation, depletion and amortization..... 15,126 6,136 -- 21,262
------- ------- ------- --------
59,549 25,901 -- 85,450
------- ------- ------- --------
Income from Operations........................ 40,273 10,997 -- 51,270
Other Income (Expense)
Equity in earnings of subsidiaries........... 4,039 -- (4,039) --
Expenses of terminated public equity offering (1,700) -- (1,700)
Interest expense............................. (9,600) (4,827) -- (14,427)
Interest and other income.................... (200) 314 -- 114
------- ------- ------- --------
Income Before Income Taxes 32,812 6,484 (4,039) 35,257
Income tax (expense) benefit
Current.................................... (1,711) (3,949) -- (5,660)
Deferred................................... (9,601) 1,504 -- (8,097)
------- ------- ------- --------
Net Income.................................... $21,500 $ 4,039 $(4,039) $ 21,500
======= ======= ======= ========
F-25
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING STATEMENT OF INCOME
Nine Months Ended September 30, 2001
Guarantor Intercompany
Issuer Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------
(in thousands)
Revenues
Crude oil and liquids............................ $ 97,090 $36,867 $ -- $133,957
Natural gas...................................... 26,870 -- -- 26,870
Other operating revenues......................... -- 468 -- 468
-------- ------- ------- --------
123,960 37,335 -- 161,295
-------- ------- ------- --------
Costs and Expenses
Production expenses.............................. 31,072 16,923 -- 47,995
General and administrative....................... 6,031 1,043 -- 7,074
Depreciation, depletion and amortization......... 13,475 3,524 -- 16,999
-------- ------- ------- --------
50,578 21,490 -- 72,068
-------- ------- ------- --------
Income from Operations............................ 73,382 15,845 -- 89,227
Other Income (Expense)
Equity in earnings of subsidiaries............... 8,616 -- (8,616) --
Interest expense................................. (7,853) (8,089) -- (12,942)
Interest and other income........................ 90 369 -- 459
-------- ------- ------- --------
Income Before Income Taxes and Cumulative
Effect of Accounting Change..................... 74,235 8,125 (8,616) 76,744
Income tax expense
Current........................................ (2,917) (2,263) -- (5,180)
Deferred....................................... (23,957) (486) -- (24,443)
-------- ------- ------- --------
Income Before Cumulative Effect of
Accounting Change............................... 47,361 5,376 (8,616) 47,121
Cumulative effect of accounting change, net of tax
benefit......................................... (1,762) 240 -- (1,522)
-------- ------- ------- --------
Net Income........................................ $ 45,599 $ 5,616 $(8,616) $ 45,599
======== ======= ======= ========
F-26
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING STATEMENT OF CASH FLOWS
Nine Months Ended September 30, 2002
Guarantor Intercompany
Issuer Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------
(in thousands)
Cash Flows From Operating Activities
Net income..................................... $ 21,500 $ 4,039 $(4,039) $ 21,500
Items not affecting cash flows from operating
activities:
Depreciation, depletion and amortization...... 15,126 6,136 -- 21,262
Equity in earnings of subsidiaries............ (4,039) -- 4,039 --
Deferred income taxes......................... 9,601 (1,504) -- 8,097
Other noncash items........................... 372 -- -- 372
Change in assets and liabilities from operating
activities:
Accounts receivable and other assets.......... (12,162) 1,152 -- (11,010)
Payable to Plains Resources Inc............... 3,357 -- -- 3,357
Accounts payable and other liabilities........ 18,407 (3,632) -- 14,775
--------- ------- ------- ---------
Net cash provided by operating activities...... 52,162 6,191 -- 58,353
--------- ------- ------- ---------
Cash Flows From Investing Activities
Acquisition, exploration and developments
costs........................................ (46,920) (6,669) -- (53,589)
Additions to other property and equipment...... (51) (4) -- (55)
--------- ------- ------- ---------
Net cash used in investing activities.......... (46,971) (6,673) -- (53,644)
--------- ------- ------- ---------
Cash Flows From Financing Activities
Principal payments on long-term debt........... (511) -- -- (511)
Change in revolving credit facility............ 90,700 -- -- 90,700
Proceeds from debt issuance.................... 196,752 -- -- 196,752
Debt issuance costs............................ (5,469) -- -- (5,469)
Contribution from Plains Resources Inc......... 5,000 -- -- 5,000
Distribution to Plains Resources Inc........... (311,964) -- -- (311,964)
Receipts from (payments to) Plains Resources
Inc.......................................... 21,034 502 -- 21,536
--------- ------- ------- ---------
Net cash provided by (used in) financing
activities................................... (4,458) 502 -- (3,956)
--------- ------- ------- ---------
Net increase (decrease) in cash and cash
equivalents.................................. 733 20 -- 753
Cash and cash equivalents, beginning of
period....................................... 11 2 -- 13
--------- ------- ------- ---------
Cash and cash equivalents, end of period....... $ 744 $ 22 $ -- $ 766
========= ======= ======= =========
F-27
PLAINS EXPLORATION & PRODUCTION COMPANY
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING STATEMENT OF CASH FLOWS
Nine Months Ended September 30, 2001
Guarantor Intercompany
Issuer Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------
(in thousands)
Cash Flows From Operating Activities
Net income..................................... $ 45,599 $ 8,616 $(8,616) $ 45,599
Items not affecting cash flows from operating
activities:
Depreciation, depletion and amortization...... 13,475 3,524 -- 16,999
Equity in earnings of subsidiaries............ (8,616) -- 8,616 --
Deferred income taxes......................... 23,957 486 -- 24,443
Cumulative effect of adoption of accounting
change...................................... 1,762 (240) -- 1,522
Change in derivative fair value............... (7) 1,062 -- 1,055
Other noncash items........................... (6) 727 -- 721
Change in assets and liabilities from operating
activities:
Accounts receivable and other assets.......... 7,691 (4,398) -- 3,293
Accounts payable and other liabilities........ 9,294 (855) -- 8,439
-------- -------- ------- --------
Net cash provided by operating activities..... 93,149 8,922 -- 102,071
-------- -------- ------- --------
Cash Flows From Investing Activities
Acquisition, exploration and developments costs (86,346) (13,000) -- (99,346)
Additions to other property and equipment...... (107) -- -- (107)
-------- -------- ------- --------
Net cash used in investing activities.......... (86,453) (13,000) -- (99,453)
-------- -------- ------- --------
Cash Flows From Financing Activities
Principal payments on long-term debt........... (511) -- -- (511)
Receipts from (payments to) Plains Resources
Inc.......................................... (6,425) 3,785 -- (2,640)
-------- -------- ------- --------
Net cash provided by (used in) financing
activities................................... (6,936) 3,785 -- (3,151)
-------- -------- ------- --------
Net increase (decrease) in cash and cash
equivalents.................................. (240) (293) -- (533)
Cash and cash equivalents, beginning of period. 240 296 -- 536
-------- -------- ------- --------
Cash and cash equivalents, end of period....... $ -- $ 3 $ -- $ --
======== ======== ======= ========
F-28
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
of Plains Resources Inc.
In our opinion, the combined financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of the Upstream Subsidiaries of Plains Resources Inc. (collectively,
the "Company") at December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States of America. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
As discussed in Note 2 to the combined financial statements, the Company
changed its method of accounting for derivative instruments and hedging
activities, effective January 1, 2001.
PricewaterhouseCoopers LLP
Houston, Texas
April 17, 2002, except as to Note 10 for which the date is September 30, 2002
F-29
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
COMBINED BALANCE SHEETS
December 31,
--------------------
2001 2000
--------- ---------
(In thousands)
ASSETS
Current Assets
Cash and cash equivalents......................... $ 13 $ 536
Accounts receivable and other current assets...... 16,382 32,878
Commodity hedging contracts....................... 21,787 --
Inventories....................................... 4,629 4,038
--------- ---------
42,811 37,452
--------- ---------
Property and Equipment, at cost
Oil and natural gas properties -- full cost method
Subject to amortization........................... 561,034 433,915
Not subject to amortization....................... 33,371 34,737
Other property and equipment...................... 1,516 1,389
--------- ---------
595,921 470,041
Less allowance for depreciation, depletion and
amortization.................................. (140,804) (116,697)
--------- ---------
455,117 353,344
--------- ---------
Other Assets....................................... 18,827 10,239
--------- ---------
$ 516,755 $ 401,035
========= =========
LIABILITIES AND COMBINED OWNERS' EQUITY
Current Liabilities
Accounts payable and other current liabilities.... $ 41,368 $ 43,802
Current maturities on long-term debt.............. 511 511
--------- ---------
41,879 44,313
--------- ---------
Payable to Plains Resources Inc.................... 235,161 224,996
--------- ---------
Long-Term Debt..................................... 1,022 1,533
--------- ---------
Other Long-Term Liabilities........................ 1,413 --
--------- ---------
Deferred Income Taxes.............................. 57,193 19,161
--------- ---------
Commitments and Contingencies (Note 6)
Combined Owners' Equity
Owners' equity.................................... 164,203 111,032
Accumulated other comprehensive income............ 15,884 --
--------- ---------
180,087 111,032
--------- ---------
$ 516,755 $ 401,035
========= =========
See notes to combined financial statements.
F-30
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
COMBINED STATEMENTS OF INCOME
Year Ended December 31,
----------------------------
2001 2000 1999
-------- -------- --------
(In thousands)
Revenues
Crude oil and liquids............................... $174,895 $126,434 $102,390
Natural gas......................................... 28,771 16,017 5,095
Other operating revenues............................ 473 -- --
-------- -------- --------
204,139 142,451 107,485
-------- -------- --------
Costs and Expenses
Production expenses................................. 63,795 56,228 50,527
General and administrative.......................... 10,210 6,308 4,367
Depreciation, depletion and amortization............ 24,105 18,859 13,329
-------- -------- --------
98,110 81,395 68,223
-------- -------- --------
Income from Operations............................... 106,029 61,056 39,262
Other Income (Expense)
Interest expense.................................... (17,411) (15,885) (14,912)
Interest and other income........................... 463 343 87
-------- -------- --------
Income Before Income Taxes and Cumulative Effect of
Accounting Change.................................. 89,081 45,514 24,437
Income tax expense
Current........................................... (6,014) (2,431) (505)
Deferred.......................................... (28,374) (14,334) (4,827)
-------- -------- --------
Income Before Cumulative Effect of Accounting Change. 54,693 28,749 19,105
Cumulative effect of accounting change, net of tax
benefit........................................... (1,522) -- --
-------- -------- --------
Net Income........................................... $ 53,171 $ 28,749 $ 19,105
======== ======== ========
Earnings Per Share Basic and Diluted.................
Income before cumulative effect of accounting change $ 2.26 $ 1.19 $ 0.79
Cumulative effect on accounting change.............. (.06) -- --
-------- -------- --------
Net income.......................................... $ 2.20 $ 1.19 $ 0.79
======== ======== ========
See notes to combined financial statements.
F-31
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
COMBINED STATEMENTS OF CASH FLOWS
Year Ended December 31,
-----------------------------
2001 2000 1999
--------- -------- --------
(In thousands)
Cash Flows From Operating Activities
Net income................................................. $ 53,171 $ 28,749 $ 19,105
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization.................. 24,105 18,859 13,329
Deferred income taxes..................................... 28,374 14,334 4,827
Cumulative effect of adoption of accounting change........ 1,522 -- --
Change in derivative fair value........................... 1,055 -- --
Other noncash items....................................... 996 -- --
Change in assets and liabilities from operating activities:
Accounts receivable and other assets...................... 9,197 7,597 (31,616)
Inventories............................................... (591) (195) (586)
Accounts payable and other liabilities.................... (1,021) 10,120 (450)
--------- -------- --------
Net cash provided by operating activities.................. 116,808 79,464 4,609
--------- -------- --------
Cash Flows From Investing Activities
Acquisition, exploration and developments costs............ (125,753) (70,505) (59,167)
Additions to other property and assets..................... (127) (366) (195)
--------- -------- --------
Net cash used in investing activities...................... (125,880) (70,871) (59,362)
--------- -------- --------
Cash Flows From Financing Activities
Principal payments of long-term debt....................... (511) (511) (511)
Receipts from (payments to) Plains Resources Inc........... 9,060 (12,621) 60,201
--------- -------- --------
Net cash provided by (used in) financing activities........ 8,549 (13,132) 59,690
--------- -------- --------
Net increase (decrease) in cash and cash equivalents....... (523) (4,539) 4,937
Cash and cash equivalents, beginning of year............... 536 5,075 138
--------- -------- --------
Cash and cash equivalents, end of year..................... $ 13 $ 536 $ 5,075
========= ======== ========
See notes to combined financial statements.
F-32
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
COMBINED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
------------------------
2001 2000 1999
------- ------- -------
(In thousands)
Net Income........................................................... $53,171 $28,749 $19,105
Other Comprehensive Income:
Unrealized gains on derivatives:
Cumulative effect of accounting change, net of taxes of $4,454.... 6,967 -- --
Unrealized gains arising during the year, net of taxes of $8,566.. 12,518 -- --
Reclassification adjustment for gains realized in net income, net
of tax benefit of $2,320....................................... (3,601) -- --
------- ------- -------
Other Comprehensive Income........................................... 15,884 -- --
------- ------- -------
Comprehensive Income................................................. $69,055 $28,749 $19,105
======= ======= =======
See notes to combined financial statements.
F-33
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
COMBINED STATEMENTS OF COMBINED OWNERS' EQUITY
Year Ended December 31,
-------------------------
2001 2000 1999
-------- -------- -------
(In thousands)
Owners' Equity
Balance, beginning of year........... $111,032 $ 82,283 $63,177
Net income........................... 53,171 28,749 19,105
Issuance of common stock............. -- -- 1
-------- -------- -------
Balance, end of year................. 164,203 111,032 82,283
-------- -------- -------
Accumulated Other Comprehensive Income
Balance, beginning of year........... -- -- --
Other comprehensive income........... 15,884 -- --
-------- -------- -------
Balance, end of year................. 15,884 -- --
-------- -------- -------
Combined Owners' Equity............... $180,087 $111,032 $82,283
======== ======== =======
See notes to combined financial statements.
F-34
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS
Note 1 -- Organization and significant accounting policies
Organization
The combined financial statements of the Upstream Subsidiaries of Plains
Resources Inc. (the "Companies", "our", or "we") include the accounts of
Stocker Resources, L.P., Arguello Inc., Plains Illinois, Inc., PMCT, Inc. and
Plains Resources International Inc. Arguello Inc., Plains Illinois, Inc., PMCT
Inc. and Plains Resources International Inc. are wholly-owned subsidiaries of
Plains Resources Inc. ("Plains"). Stocker Resources, L.P. is a limited
partnership of which Stocker Resources, Inc., a wholly owned subsidiary of
Plains, is the general partner (holding a 2.5% interest) and Plains is the
limited partner (holding a 97.5% interest). Stocker Resources, L.P. was renamed
Plains Exploration & Production Company and was subsequently converted to a
Delaware corporation known as Plains Exploration and Production Company. All
significant intercompany transactions have been eliminated.
The accompanying combined financial statements are presented on a carve-out
combined basis to include the historical operations of the businesses owned by
the Companies. In this context, no direct owner relationship existed among the
various operations comprising the businesses as described above. Accordingly,
Plains' net investment in the businesses (combined owners' equity) is shown in
lieu of stockholders' equity in the combined financial statements.
We are independent energy companies that are engaged in the "Upstream" oil
and gas business. The Upstream business acquires, exploits, develops, explores
for and produces crude oil and natural gas. Our Upstream activities are all
located in the United States.
Under the terms of a service agreement (the "Service Agreement"), Plains
provides the Companies with financial intermediary, treasury and other services
as may be required from time to time. Such services include, but are not
limited to: arranging financings and commercial transactions for the
procurement of funds and other commercial accommodations from financial
institutions and other lenders; disbursement of capital and operating funds in
the form of loans or intercompany advances; maintenance of financial records
and books of account; and cash management, including the processing of cash
receipts and disbursements.
These financial statements include allocations of direct and indirect
corporate and administrative costs of Plains. The methods by which such costs
are estimated and allocated to the Companies are deemed reasonable by Plains'
management; however, such allocations and estimates are not necessarily
indicative of the costs and expenses that would have been incurred had we
operated as a separate entity. Allocations of such costs are considered to be
related party transactions and are discussed in Note 4.
Significant accounting policies
Oil and Gas Properties. We follow the full cost method of accounting
whereby all costs associated with property acquisition, exploration,
exploitation and development activities are capitalized. Such costs include
internal general and administrative costs such as payroll and related benefits
and costs directly attributable to employees engaged in acquisition,
exploration, exploitation and development activities. General and
administrative costs associated with production, operations, marketing and
general corporate activities are expensed as incurred. These capitalized costs
along with our estimate of future development and abandonment costs, net of
salvage values and other considerations, are amortized to expense by the
unit-of-production method using engineers' estimates of proved oil and natural
gas reserves. The costs of unproved properties are excluded from
F-35
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
amortization until the properties are evaluated. Interest is capitalized on oil
and natural gas properties not subject to amortization and in the process of
development. Proceeds from the sale of oil and natural gas properties are
accounted for as reductions to capitalized costs unless such sales involve a
significant change in the relationship between costs and the estimated value of
proved reserves, in which case a gain or loss is recognized. Unamortized costs
of proved properties are subject to a ceiling which limits such costs to the
present value of estimated future cash flows from proved oil and natural gas
reserves of such properties (including the effect of any related hedging
activities) reduced by future operating expenses, development expenditures and
abandonment costs (net of salvage values), and estimated future income taxes
thereon.
Other Property and Equipment. Other property and equipment is recorded at
cost and consists primarily of office furniture and fixtures and computer
hardware and software. Acquisitions, renewals, and betterments are capitalized;
maintenance and repairs are expensed. Depreciation is provided using the
straight-line method over estimated useful lives of three to seven years. Net
gains or losses on property and equipment disposed of are included in interest
and other income in the period in which the transaction occurs.
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. Significant estimates made by management include
(1) crude oil and natural gas reserves, (2) depreciation, depletion and
amortization, including future abandonment costs, (3) income taxes and (4)
accrued liabilities. Although management believes these estimates are
reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand
deposits and funds invested in highly liquid instruments with original
maturities of three months or less. At December 31, 2001 and 2000, the majority
of cash and cash equivalents is concentrated in one institution and at times
may exceed federally insured limits. We periodically assess the financial
condition of the institution and believe that any possible credit risk is
minimal.
Inventory. Crude oil inventories are carried at the lower of cost to
produce or market value. Materials and supplies inventory is stated at the
lower of cost or market with cost determined on an average cost method.
Inventory consists of the following (in thousands):
December 31,
-------------
2001 2000
------ ------
Materials and supplies $4,201 $3,487
Crude oil............. 428 551
------ ------
$4,629 $4,038
====== ======
Other Assets. Other assets consists of the following (in thousands):
December 31,
---------------
2001 2000
------- -------
Land....................... $ 8,103 $ 8,103
Commodity hedging contracts 5,627 --
Other...................... 5,097 2,136
------- -------
$18,827 $10,239
======= =======
F-36
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
Federal and State Income Taxes. Income taxes are accounted for in
accordance with Statement of Financial Accounting Standards No. 109, Accounting
for Income Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax
liabilities and assets for the expected future tax consequences of events that
have been included in the financial statements or tax returns. Under this
method, deferred tax liabilities and assets are determined based on the
difference between the financial statement and tax bases of assets and
liabilities using tax rates in effect for the year in which the differences are
expected to reverse. A valuation allowance is established to reduce deferred
tax assets if it is more than likely than not that the related tax benefits
will not be realized.
The taxable income or loss of the Companies is included in the consolidated
income tax returns filed by Plains. Income tax obligations reflected in these
financial statements are based on the tax sharing agreement among all the
members of the consolidated group. Such agreement provides that income taxes
are calculated assuming the combined companies filed a separate income tax
return. Income taxes payable are included in Payable to Plains Resources, Inc.
in the combined balance sheet.
Revenue Recognition. Oil and gas revenue from our interests in producing
wells is recognized when the production is delivered and the title transfers.
Derivative Financial Instruments (Hedging). We utilize various derivative
instruments to reduce our exposure to fluctuations in the market price of crude
oil. The derivative instruments consist primarily of crude oil swap and option
contracts entered into with financial institutions.
Recent Accounting Pronouncements. The following Statements of Financial
Accounting Standards ("SFAS") were issued in June 2001: SFAS No. 141, Business
Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No.
143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets was also issued.
SFAS No. 141 requires the use of the purchase method of accounting for all
business combinations. It applies to all business combinations initiated after
June 30, 2001 and to all business combinations accounted for by the purchase
method that are completed after June 30, 2001. SFAS No. 142 requires that
goodwill as well as other intangible assets with indefinite lives not be
amortized but be tested annually for impairment and is effective for fiscal
years beginning after December 15, 2001. SFAS No. 144 addresses financial
accounting and reporting for the impairment of long-lived assets and long-lived
assets to be disposed of. It supersedes, with exceptions, SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of and is effective for fiscal years beginning after December 15,
2001. SFAS No. 141, No. 142 and No. 144 had no effect on our financial
statements. We will account for all future business combinations and any
related goodwill in accordance with the provisions of SFAS No. 141 and SFAS No.
142.
SFAS No. 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Subsequently, the asset retirement cost should be allocated to expense using a
systematic and rational method. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. The Company is currently assessing the impact of
SFAS No. 143 and at this time cannot reasonably estimate the effect of this
statement on its consolidated financial position, results of operations or cash
flows.
F-37
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
Note 2 -- Derivative instruments and hedging activities
Plains entered into various derivative instruments on behalf of the
Companies to reduce our exposure to fluctuations in the market price of crude
oil. The derivative instruments consist primarily of crude oil swap and option
contracts entered into with financial institutions. In accordance with the
terms of the Services Agreement, the gains and losses with respect to such
instruments have been allocated to the Companies. Oil revenues for the year
ended December 31, 2001 have been increased by $0.3 million and oil revenues
for the years ended December 31, 2000 and 1999 have been reduced by $72.8
million and $7.5 million, respectively, as a result of such transactions.
On January 1, 2001, we adopted Statement of Financial Accounting Standards
("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities"
as amended by SFAS 137 and SFAS 138 ("SFAS 133"). Under SFAS 133, all
derivative instruments are recorded on the balance sheet at fair value. If the
derivative does not qualify as a hedge or is not designated as a hedge, the
gain or loss on the derivative is recognized currently in earnings. To qualify
for hedge accounting, the derivative must qualify either as a fair value hedge,
cash flow hedge or foreign currency hedge. Currently, we use only cash flow
hedges and the remaining discussion will relate exclusively to this type of
derivative instrument. If the derivative qualifies for hedge accounting, the
gain or loss on the derivative is deferred in Other Comprehensive Income
("OCI"), a component of Combined Owners' Equity to the extent the hedge is
effective.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. Hedge accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in OCI related to cash flow
hedges that become ineffective remain unchanged until the related product is
delivered. If it is determined that it is probable that a hedged forecasted
transaction will not occur, deferred gains or losses on the hedging instrument
are recognized in earnings immediately.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured on a quarterly basis.
This process includes specific identification of the hedging instrument and the
hedge transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, we assess whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows
of hedged items. No amounts were excluded from the computation of hedge
effectiveness. At December 31, 2001, all open positions qualified for hedge
accounting.
Unrealized gains and losses on hedging instruments reflected in OCI and
adjustments to carrying amounts on hedged volumes are included in oil and gas
revenues in the period that the related volumes are delivered. Gains and losses
from hedging instruments, which represent hedge ineffectiveness as well as any
amounts excluded from the assessment of hedge effectiveness, are recognized
currently in oil and gas revenues. Effective October 2001, we implemented
Derivatives Implementation Group ("DIG") Issue G20, "Cash Flow Hedges:
Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash
Flow Hedge", which provides guidance for assessing the effectiveness on total
changes in an option's cash flows rather than only on changes in the option's
intrinsic value. Implementation of this DIG issue will reduce earnings
volatility since it allows us to include changes in the time value of purchased
options and collars in the assessment of hedge effectiveness. Time value
changes were previously recognized in current earnings since we excluded time
value changes from the assessment of hedge effectiveness. Oil and gas revenues
for
F-38
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
the year ended December 31, 2001 include a $3.1 million non-cash loss related
to the ineffective portion of the cash flow hedges representing the fair value
change in the time value of options for the nine months prior to the
implementation of DIG Issue G20.
We utilize various derivative instruments to hedge our exposure to price
fluctuations on crude oil sales. The derivative instruments consist primarily
of cash-settled crude oil option and swap contracts entered into with financial
institutions. We do not currently have any natural gas hedges. At December 31,
2001, we had the following open crude oil hedge positions:
Barrels Per
Day
------------
2002 2003
------ -----
Calls
Average price $35.17/bbl 9,000 --
Swaps
Average price $24.00/bbl 17,000 --
Average price $23.16/bbl -- 7,500
On January 1, 2001, in accordance with the transition provisions of SFAS
133, we recorded a gain of $7.0 million in OCI, representing the cumulative
effect of an accounting change to recognize at fair value all cash flow
derivatives. We recorded cash flow hedge derivative assets and liabilities of
$9.7 million and $4.2 million, respectively, and a net-of-tax non-cash charge
of $1.5 million was recorded in earnings as a cumulative effect adjustment.
For the year ended December 31, 2001, net unrealized gains of $8.9 million
were added to OCI, and the fair value of open positions increased $15.2 million.
At December 31, 2001, net unrealized gains on our option and swap contracts
included in OCI was $15.9 million. The related assets and liabilities were
included in commodity hedging contracts and other derivatives ($21.8 million),
other assets ($5.6 million), and deferred income taxes ($10.7 million). As of
December 31, 2001, $12.5 million of deferred net gains on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
the next twelve-month period.
Note 3 -- Long-term debt
Long-term debt and the related current maturities represents a note issued
in connection with the purchase of a production payment on certain of our
producing properties. The note bears interest at 8%, payable annually, and
requires an annual principal payment of $511,000 through 2004.
Note 4 -- Related party transactions
We use a centralized cash management system under which our cash receipts
are remitted to Plains and our cash disbursements are funded by Plains. We are
charged interest on any amounts, other than income taxes payable, due to Plains
at the average effective interest rate of Plains long-term debt. For the years
2001, 2000 and 1999 we were charged $20.4 million, $19.5 million and $18.3
million, respectively, of interest on amounts payable to Plains. Of such
amounts, $17.3 million, $15.7 million and $14.7 million was included in
interest expense in 2001, 2000 and 1999, respectively, and $3.1 million, $3.8
million and $3.6 million was capitalized in oil and gas properties in 2001,
2000 and 1999, respectively.
To compensate Plains for services rendered under the Services Agreement, we
are allocated direct and indirect corporate and administrative costs of Plains.
Such costs totaled $8.2 million, $3.9
F-39
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
million and $3.1 million in 2001, 2000 and 1999, respectively. Of such amounts,
$6.1 million, $2.8 million and $2.2 million was included in general and
administrative expense in 2001, 2000 and 1999, respectively, and $2.1 million,
$1.1 million and $0.9 million was capitalized in oil and gas properties in
2001, 2000 and 1999, respectively.
In addition, as discussed in Note 2, Plains entered into various derivative
instruments to reduce our exposure to decreases in the market price of crude
oil.
At December 31, 2001 Plains had $267.5 million principal amount of 10.25%
Senior Subordinated Notes due 2006 outstanding. Such notes are guaranteed by
the Companies on a full, unconditional, joint and several basis.
Plains All American Pipeline ("PAA"), an affiliate of Plains, is the
exclusive marketer/ purchaser for all of our equity crude oil production. The
marketing agreement provides that PAA will purchase for resale at market prices
all of our equity crude oil production, for which PAA charges a fee of $0.20
per barrel. In 2001, 2000 and 1999, we were paid $202.1 million, $222.7 million
and $114.6 million, respectively, for the purchase of crude oil under the
agreement, including the royalty share of production. Accounts receivable and
other current assets at December 31, 2001 and 2000 include $12.3 million and
$17.6 million, respectively, of amounts receivable from PAA with respect to oil
sales.
Note 5 -- Income taxes
Our taxable income or loss is included in the consolidated income tax
returns filed by Plains. Income tax obligations reflected in these financial
statements are based on the tax sharing agreement which provides that income
taxes are calculated assuming we filed a separate combined income tax return.
Currently payable income taxes are included in Payable to Plains Resources,
Inc. in the combined balance sheet.
Our deferred income tax assets and liabilities at December 31, 2001 and
2000 consist of the tax effect of income tax carryforwards and differences
related to the timing of recognition of certain types of costs as follows (in
thousands):
December 31,
------------------
2001 2000
-------- --------
U.S. Federal
Deferred tax assets:
Tax credit carryforwards...................................... $ -- $ 1,181
Other......................................................... 658 646
-------- --------
658 1,827
Deferred tax liabilities:
Net oil and gas acquisition, exploration and development costs (36,520) (15,807)
Commodity hedging contracts and other......................... (10,700) --
-------- --------
Net deferred tax liability.................................. (46,562) (13,980)
States
Deferred tax liability......................................... (10,631) (5,181)
-------- --------
Net deferred tax liability..................................... $(57,193) $(19,161)
======== ========
At December 31, 2001, for federal income tax purposes, we have no
carryforwards of regular tax net operating losses, alternative minimum tax
credits or enhanced oil recovery credits.
F-40
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
Set forth below is a reconciliation between the income tax provision
computed at the United States statutory rate on income before income taxes and
the income tax provision in the accompanying consolidated statements of income
(in thousands):
Year Ended
December 31,
-------------------------
2001 2000 1999
------- ------- -------
U.S. federal income tax provision at statutory rate............ $31,101 $15,935 $ 8,553
State income taxes, net of federal benefit..................... 4,758 2,232 1,211
Full cost ceiling test limitation.............................. -- -- (3,772)
Other.......................................................... (1,471) (1,402) (660)
------- ------- -------
Income tax expense on income before effect of accounting change 34,388 16,765 5,332
Income tax benefit allocated to cumulative effect of accounting
change....................................................... (1,042) -- --
------- ------- -------
Income tax provision........................................... $33,346 $16,765 $ 5,332
======= ======= =======
Note 6 -- Commitments, contingencies and industry concentration
Commitments and contingencies
We lease certain real property, equipment and operating facilities under
various operating leases. Future non-cancelable commitments related to these
items at December 31, 2001 total $53,100, all of which relates to 2002. Total
expenses related to such commitments for the years ended December 31, 2001,
2000 and 1999 were $41,000, $45,000 and $61,000, respectively.
Under the amended terms of an asset purchase agreement with respect to
certain of our onshore California properties, commencing with the year
beginning January 1, 2000, and each year thereafter, we are required to plug
and abandon 20% of the then remaining inactive wells, which currently aggregate
approximately 149. To the extent we elect not to plug and abandon the number of
required wells, we are required to escrow an amount equal to the greater of
$25,000 per well or the actual average plugging cost per well in order to
provide for the future plugging and abandonment of such wells. In addition, we
are required to expend a minimum of $600,000 per year in each of the ten years
beginning January 1, 1996, and $300,000 per year in each of the succeeding five
years to remediate oil contaminated soil from existing well sites, provided
there are remaining sites to be remediated. In the event we do not expend the
required amounts during a calendar year, we are required to contribute an
amount equal to 125% of the actual shortfall to an escrow account. We may
withdraw amounts from the escrow account to the extent we expend excess amounts
in a future year. Through December 31, 2001, we have not been required to make
contributions to an escrow account.
In connection with the acquisition of our interest in the Point Arguello
field, offshore California, we assumed our 26% share of (1) plugging and
abandoning all existing well bores, (2) removing conductors, (3) flushing
hydrocarbons from all lines and vessels and (4) removing/abandoning all
structures, fixtures and conditions created subsequent to closing. The seller
retained the obligation for all other abandonment costs, including but not
limited to (1) removing, dismantling and disposing of the existing offshore
platforms, (2) removing and disposing of all existing pipelines and (3)
removing, dismantling, disposing and remediation of all existing onshore
facilities.
Although we obtained environmental studies on our properties in California
and Illinois and we believe that such properties have been operated in
accordance with standard oil field practices, certain
F-41
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
of the fields have been in operation for more than 90 years, and current or
future local, state and federal environmental laws and regulations may require
substantial expenditures to comply with such rules and regulations. In
connection with the purchase of certain of our onshore California properties,
we received a limited indemnity for certain conditions if they violate
applicable local, state and federal environmental laws and regulations in
effect on the date of such agreement. We believe that we do not have any
material obligations for operations conducted prior to our acquisition of the
properties, other than our obligation to plug existing wells and those normally
associated with customary oil field operations of similarly situated
properties. There can be no assurance that current or future local, state or
federal rules and regulations will not require us to spend material amounts to
comply with such rules and regulations or that any portion of such amounts will
be recoverable under the indemnity.
Consistent with normal industry practices, substantially all of our crude
oil and natural gas leases require that, upon termination of economic
production, the working interest owners plug and abandon non-producing
wellbores, remove tanks, production equipment and flow lines and restore the
wellsite. We have estimated that the costs to perform these tasks is
approximately $12.0 million, net of salvage value and other considerations.
Such estimated costs are amortized to expense through the unit-of-production
method as a component of accumulated depreciation, depletion and amortization.
Results from operations for 2001, 2000 and 1999 include $0.5 million, $0.2
million and $0.2 million, respectively, of expense associated with these
estimated future costs. For valuation and realization purposes of the affected
crude oil and natural gas properties, these estimated future costs are also
deducted from estimated future gross revenues to arrive at the estimated future
net revenues and the Standardized Measure disclosed in Note 8.
As is common within the industry, we have entered into various commitments
and operating agreements related to the exploration and development of and
production from proved crude oil and natural gas properties and the marketing,
transportation, terminalling and storage of crude oil. It is management's
belief that such commitments will be met without a material adverse effect on
our financial position, results of operations or cash flows.
Industry concentration
Financial instruments which potentially subject us to concentrations of
credit risk consist principally of accounts receivable with respect to our oil
and gas operations and derivative instruments related to our hedging
activities. PAA is the exclusive marketer/purchaser for all of our equity oil
production. This concentration has the potential to impact our overall exposure
to credit risk, either positively or negatively, in that PAA may be affected by
changes in economic, industry or other conditions. We do not believe the loss
of PAA as the exclusive purchaser of our equity production would have a
material adverse affect on our results of operations. We believe PAA could be
replaced by other purchasers under contracts with similar terms and conditions.
The contract counterparties for our derivative commodity contracts are all
major financial institutions with Standard & Poor's ratings of A or better.
Three of the financial institutions are participating lenders in Plains'
revolving credit facility, with one such counterparty holding contracts that
represent approximately 37% of the fair value of all of Plains' open positions
at December 31, 2001.
There are a limited number of alternative methods of transportation for our
production. Substantially all of our oil and gas production is transported by
pipelines, trucks and barges owned by third parties. The inability or
unwillingness of these parties to provide transportation services to us for a
reasonable fee could result in our having to find transportation alternatives,
increased transportation
F-42
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
costs or involuntary curtailment of a significant portion of our oil and gas
production which could have a negative impact on future results of operations
or cash flows.
We, in the ordinary course of business, are a claimant and/or defendant in
various other legal proceedings. Management does not believe that the outcome
of these legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
Note 7 -- Financial instruments
The disclosure of the estimated fair value of financial instruments is made
in accordance with the requirements of Statement of Financial Accounting
Standards No. 107, Disclosures About Fair Value of Financial Instruments.
Considerable judgment is required to develop estimates of fair value. The use
of different assumptions or valuation methodologies may have a material effect
on estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. Derivative financial instruments included other assets are stated
at fair value. The carrying value of our payable to Plains approximates its
fair value, as interest rates are variable, based on prevailing market rates.
The fair value of our long-term debt is estimated to equal its carrying value.
Note 8 -- Crude oil and natural gas activities
Costs incurred
Our oil and natural gas acquisition, exploration, exploitation and
development activities are conducted in the United States. The following table
summarizes the costs incurred during the last three years (in thousands).
Year Ended December 31,
------------------------
2001 2000 1999
-------- ------- -------
Property acquisitions costs:
Unproved properties.................. $ 44 $ 73 $ 879
Proved properties.................... 1,645 1,953 2,496
Exploration costs..................... 286 293 796
Exploitation and development costs (1) 123,778 68,186 54,996
-------- ------- -------
$125,753 $70,505 $59,167
======== ======= =======
- --------
(1) Includes capitalized general and administrative expense of $6.2 million,
$5.2 million and $5.1 million in 2001, 2000 and 1999, respectively, and
capitalized interest expense of $3.1 million, $3.8 million and $3.6 million
in 2001, 2000 and 1999, respectively.
Capitalized costs
The following table presents the aggregate capitalized costs subject to
amortization relating to our crude oil and natural gas acquisition,
exploration, exploitation and development activities, and the aggregate related
accumulated DD&A (in thousands).
December 31,
--------------------
2001 2000
--------- ---------
Proved properties $ 561,034 $ 433,915
Accumulated DD&A. (139,797) (116,066)
--------- ---------
$ 421,237 $ 317,849
========= =========
F-43
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
The DD&A rate per equivalent unit of production was $2.70, $2.25 and $1.72
in 2001, 2000 and 1999, respectively.
Costs not subject to amortization
The following table summarizes the categories of costs comprising the amount
of unproved properties not subject to amortization (in thousands).
December 31,
-----------------------
2001 2000 1999
------- ------- -------
Acquisition costs... $27,523 $31,090 $38,252
Exploration costs... -- 425 504
Capitalized interest 5,848 3,222 4,443
------- ------- -------
$33,371 $34,737 $43,199
======= ======= =======
Unproved property costs not subject to amortization consist primarily of
acquisition costs related to unproved areas and capitalized interest. Costs are
transferred into the amortization base on an ongoing basis as the properties
are evaluated and proved reserves established or impairment determined. We will
continue to evaluate these properties and costs will be transferred into the
amortization base as the undeveloped areas are tested. Our onshore properties
and one offshore property consist of mature but underdeveloped crude oil
properties that were acquired from major or large independent oil and gas
companies. These fields were discovered from 1906 to 1981, and have produced
significant volumes since initial discovery, exhibit complex reservoir and
geologic conditions. Due to the nature of the reserves, the ultimate evaluation
of the properties will occur over a period of several years. We expect that 75%
of the costs not subject to amortization will be transferred to the
amortization base over the next three to five years and the remainder over the
next three to ten years. The leases covering the properties are held by
production and will not limit the time period for evaluation. Approximately 9%,
11% and 10% of the balance in unproved properties at December 31, 2001, related
to additions made in 2001, 2000 and 1999, respectively.
During 2001, 2000 and 1999, we capitalized $3.1 million, $3.8 million and
$3.6 million, respectively, of interest related to the costs of unproved
properties in the process of development.
Supplemental reserve information (unaudited)
The following information summarizes our net proved reserves of crude oil
(including condensate and natural gas liquids) and natural gas and the present
values thereof for the three years ended December 31, 2001. The following
reserve information is based upon reports of the independent petroleum
consulting firms of Netherland, Sewell & Associates, Inc., and Ryder Scott
Company in 2001, and H.J. Gruy and Associates, Inc., Netherland, Sewell &
Associates, Inc., and Ryder Scott Company in 2000 and 1999. The estimates are
in accordance with regulations prescribed by the SEC.
In management's opinion, the reserve estimates presented herein, in
accordance with generally accepted engineering and evaluation principles
consistently applied, are believed to be reasonable. However, there are
numerous uncertainties inherent in estimating quantities and values of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond our control. Reserve engineering is
a subjective process of estimating the
F-44
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
recovery from underground accumulations of crude oil and natural 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. Because all reserve estimates are to
some degree speculative, the quantities of crude oil and natural gas that are
ultimately recovered, production and operating costs, the amount and timing of
future development expenditures and future crude oil and natural gas sales
prices may all differ from those assumed in these estimates. In addition,
different reserve engineers may make different estimates of reserve quantities
and cash flows based upon the same available data. Therefore, the Standardized
Measure shown below represents estimates only and should not be construed as
the current market value of the estimated crude oil and natural gas reserves
attributable to our properties. In this regard, the information set forth in
the following tables includes revisions of reserve estimates attributable to
proved properties included in the preceding year's estimates. Such revisions
reflect additional information from subsequent exploitation and development
activities, production history of the properties involved and any adjustments
in the projected economic life of such properties resulting from changes in
product prices.
Decreases in the prices of crude oil and natural gas have had, and could
have in the future, an adverse effect on the carrying value of our proved
reserves and our revenues, profitability and cash flow. Almost all of our
reserve base (approximately 93% of year-end 2001 reserve volumes) is comprised
of crude oil properties that are sensitive to crude oil price volatility.
Estimated quantities of crude oil and natural gas reserves (unaudited)
The following table sets forth certain data pertaining to our proved and
proved developed reserves for the three years ended December 31, 2001 (in
thousands).
As of or for the Year Ended December 31,
-------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------
Oil Gas Oil Gas Oil Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
------- ------ ------- ------ ------- ------
Proved Reserves
Beginning balance................ 204,387 93,486 195,213 90,873 110,950 86,781
Revision of previous estimates... (13,093) (5,485) (5,601) (3,597) 47,510 (8,234)
Extensions, discoveries, improved
recovery and other additions... 40,218 11,571 22,429 9,252 37,393 15,488
Purchase of reserves in-place.... -- -- -- -- 6,442 --
Production....................... (8,219) (3,355) (7,654) (3,042) (7,082) (3,162)
------- ------ ------- ------ ------- ------
Ending balance................... 223,293 96,217 204,387 93,486 195,213 90,873
======= ====== ======= ====== ======= ======
Proved Developed Reserves
Beginning balance................ 105,679 52,184 100,758 49,255 68,167 58,445
======= ====== ======= ====== ======= ======
Ending balance................... 119,248 59,101 105,679 52,184 100,758 49,255
======= ====== ======= ====== ======= ======
F-45
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
Standardized measure of discounted future net cash flows (unaudited)
The Standardized Measure of discounted future net cash flows relating to
proved crude oil and natural gas reserves is presented below (in thousands):
December 31,
-------------------------------------
2001 2000 1999
----------- ----------- -----------
Future cash inflows............................... $ 3,662,137 $ 5,850,215 $ 4,389,337
Future development costs.......................... (305,261) (249,319) (193,409)
Future production expense......................... (1,714,132) (2,748,492) (1,558,492)
Future income tax expense......................... (537,252) (1,030,400) (881,167)
----------- ----------- -----------
Future net cash flows............................. 1,105,492 1,822,004 1,756,269
Discounted at 10% per year........................ (721,025) (1,032,566) (1,028,983)
----------- ----------- -----------
Standardized measure of discounted future net cash
flows........................................... $ 384,467 $ 789,438 $ 727,286
=========== =========== ===========
The Standardized Measure of discounted future net cash flows (discounted at
10%) from production of proved reserves was developed as follows:
1. An estimate was made of the quantity of proved reserves and the future
periods in which they are expected to be produced based on year-end
economic conditions.
2. In accordance with SEC guidelines, the engineers' estimates of future
net revenues from our proved properties and the present value thereof are
made using crude oil and natural gas sales prices in effect as of the dates
of such estimates and are held constant throughout the life of the
properties, except where such guidelines permit alternate treatment,
including the use of fixed and determinable contractual price escalations.
We have entered into various arrangements to fix or limit the NYMEX crude
oil price for a significant portion of our crude oil production.
Arrangements in effect at December 31, 2001 are discussed in Note 2. Such
arrangements are not reflected in the reserve reports. The overall average
year-end prices used in the reserve reports as of December 31, 2001, were
$15.31 per barrel of crude oil and $2.56 per Mcf of natural gas. Such
prices as of December 31, 2000 were $21.93 per barrel of crude oil and
$14.63 per Mcf of natural gas.
3. The future gross revenue streams were reduced by estimated future
operating costs (including production and ad valorem taxes) and future
development and abandonment costs, all of which were based on current costs.
4. The reports reflect the pre-tax Present Value of Proved Reserves to be
$0.6 billion, $1.3 billion and $1.1 billion at December 31, 2001, 2000 and
1999, respectively. SFAS No. 69 requires us to further reduce these
estimates by an amount equal to the present value of estimated income taxes
which might be payable by us in future years to arrive at the Standardized
Measure. Future income taxes were calculated by applying the statutory
federal and state income tax rate to pre-tax future net cash flows, net of
the tax basis of the properties involved and utilization of available tax
carryforwards related to oil and gas operations.
F-46
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
The principal sources of changes in the Standardized Measure of the future
net cash flows for the three years ended December 31, 2001, are as follows (in
thousands):
Year Ended December 31,
-------------------------------
2001 2000 1999
--------- --------- ---------
Balance, beginning of year................................. $ 789,438 $ 727,286 $ 183,630
Sales, net of production expenses.......................... (139,827) (86,237) (56,958)
Net change in sales and transfer prices, net of production
expenses................................................. (664,684) 94,159 623,369
Changes in estimated future development costs.............. (17,535) (16,097) (46,542)
Extensions, discoveries and improved recovery, net of costs 89,010 141,641 112,573
Previously estimated development costs incurred during the
year..................................................... 86,881 27,855 19,676
Purchase of reserves in-place.............................. -- -- 53,724
Revision of quantity estimates............................. (156,402) (68,163) 159,499
Accretion of discount...................................... 141,598 101,667 18,683
Net change in income taxes................................. 255,988 (132,673) (340,368)
--------- --------- ---------
Balance, end of year....................................... $ 384,467 $ 789,438 $ 727,286
========= ========= =========
Results of operations for oil and gas producing activities
The results of operations from oil and gas producing activities below
exclude non-oil and gas revenues, general and administrative expenses, interest
charges, interest income and interest capitalized. Income tax (expense) or
benefit was determined by applying the statutory rates to pretax operating
results (in thousands).
Year Ended December 31,
----------------------------
2001 2000 1999
-------- -------- --------
Revenues from oil and gas producing activities...................... $204,139 $142,451 $107,485
Production costs.................................................... (63,795) (56,228) (50,527)
Depreciation, depletion and amortization............................ (23,707) (18,395) (13,101)
Income tax expense.................................................. (45,022) (24,981) (16,337)
======== ======== ========
Results of operations from producing activities (excluding corporate
overhead and interest costs)...................................... $ 71,615 $ 42,847 $ 27,520
======== ======== ========
Note 9 -- Consolidating Financial Statements
In conjunction with the anticipated issuance of debt securities, all
subsidiaries of Plains referred to in Note 1 will become 100% owned
subsidiaries of Stocker Resources, L.P. (currently known as Plains Exploration
& Production Company). Stocker Resources, L.P. will be co-issuing the debt
securities along with a 100% owned finance company with no material assets or
operations. The debt securities will be guaranteed on a full and unconditional
and joint and several basis by Arguello Inc. and Plains Illinois Inc., PMCT
Inc. and Plains Resources International Inc. (referred to as "Guarantor
Subsidiaries").
The following financial information presents consolidating financial
statements, which include:
. Issuer
. the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries")
. elimination entries necessary to consolidate the Issuer and the Guarantor
Subsidiaries; and
. the Companies on a consolidated basis.
F-47
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED BALANCE SHEET
December 31, 2001
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ ---------
(In thousands)
ASSETS
Current Assets
Cash and cash equivalents................... $ 11 $ 2 $ -- $ 13
Accounts receivable and other
current assets........................... 10,703 5,679 -- 16,382
Commodity hedging contracts................ 13,872 7,915 -- 21,787
Inventories................................ 3,252 1,377 -- 4,629
-------- -------- ------- ---------
27,838 14,973 -- 42,811
-------- -------- ------- ---------
Property and Equipment, at cost
Oil and natural gas properties -- full cost
method
Subject to amortization.................. 450,038 110,996 -- 561,034
Not subject to amortization.............. 19,676 13,695 -- 33,371
Other property and equipment............... 1,322 194 -- 1,516
-------- -------- ------- ---------
471,036 124,885 -- 595,921
Less allowance for depreciation,
depletion and amortization............... (56,137) (84,667) -- (140,804)
-------- -------- ------- ---------
414,899 40,218 -- 455,117
-------- -------- ------- ---------
Investment in and Advances to
Subsidiaries.............................. (21,496) -- 21,496 --
-------- -------- ------- ---------
Other Assets................................ 16,275 2,552 -- 18,827
-------- -------- ------- ---------
$437,516 $ 57,743 $21,496 $ 516,755
======== ======== ======= =========
LIABILITIES AND COMBINED OWNERS' EQUITY
Current Liabilities
Accounts payable and other current
liabilities.............................. $ 29,822 $ 11,546 $ -- $ 41,368
Current maturities on long-term debt....... 511 -- -- 511
-------- -------- ------- ---------
30,333 11,546 -- 41,879
-------- -------- ------- ---------
Payable to Plains Resources Inc............. 172,603 62,558 -- 235,161
-------- -------- ------- ---------
Long-Term Debt.............................. 1,022 -- -- 1,022
-------- -------- ------- ---------
Other Long-Term Liabilities................. -- 1,413 -- 1,413
-------- -------- ------- ---------
Deferred Income Taxes....................... 53,471 3,722 -- 57,193
-------- -------- ------- ---------
Combined Owners' Equity
Owners' equity............................. 164,203 (25,889) 25,889 164,203
Accumulated other comprehensive
income................................... 15,884 4,393 (4,393) 15,884
-------- -------- ------- ---------
180,087 (21,496) 21,496 180,087
-------- -------- ------- ---------
$437,516 $ 57,743 $21,496 $ 516,755
======== ======== ======= =========
F-48
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED BALANCE SHEET
December 31, 2000
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ ---------
(In thousands)
ASSETS
Current Assets
Cash and cash equivalents..................... $ 240 $ 296 $ -- $ 536
Accounts receivable and other
current assets.............................. 24,144 8,734 -- 32,878
Inventories................................... 2,666 1,372 -- 4,038
-------- -------- ------- ---------
27,050 10,402 -- 37,452
-------- -------- ------- ---------
Property and Equipment, at cost
Oil and natural gas
properties -- full cost method
Subject to amortization..................... 338,859 95,056 -- 433,915
Not subject to amortization................. 22,278 12,459 -- 34,737
Other property and equipment.................. 1,189 200 -- 1,389
-------- -------- ------- ---------
362,326 107,715 -- 470,041
Less allowance for depreciation, depletion and
amortization................................ (37,721) (78,976) -- (116,697)
-------- -------- ------- ---------
324,605 28,739 -- 353,344
-------- -------- ------- ---------
Investment in and Advances to
Subsidiaries................................. (37,417) -- 37,417 --
-------- -------- ------- ---------
Other Assets................................... 9,608 631 -- 10,239
-------- -------- ------- ---------
$323,846 $ 39,772 $37,417 $ 401,035
======== ======== ======= =========
LIABILITIES AND COMBINED OWNERS' EQUITY
Current Liabilities
Accounts payable and other current
liabilities................................. $ 29,665 $ 14,137 $ -- $ 43,802
Current maturities on long-term debt.......... 511 -- -- 511
-------- -------- ------- ---------
30,176 14,137 -- 44,313
Payable to Plains Resources Inc................ 161,789 63,207 -- 224,996
Long-Term Debt................................. 1,533 -- -- 1,533
Other Long-Term Liabilities.................... -- -- -- --
Deferred Income Taxes.......................... 19,316 (155) -- 19,161
Combined Owners' Equity........................ 111,032 (37,417) 37,417 111,032
-------- -------- ------- ---------
$323,846 $ 39,772 $37,417 $ 401,035
======== ======== ======= =========
F-49
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED STATEMENT OF INCOME
Year Ended December 31, 2001
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ --------
(In thousands)
Revenues
Crude oil and liquids......................... $124,250 $50,645 $ -- $174,895
Natural gas................................... 28,771 -- -- 28,771
Other operating revenues...................... -- 473 -- 473
-------- ------- -------- --------
153,021 51,118 -- 204,139
-------- ------- -------- --------
Costs and Expenses
Production expenses........................... 41,458 22,337 -- 63,795
General and administrative.................... 8,708 1,502 -- 10,210
Depreciation, depletion and
amortization................................ 18,413 5,692 -- 24,105
-------- ------- -------- --------
68,579 29,531 -- 98,110
-------- ------- -------- --------
Income from Operations......................... 84,442 21,587 -- 106,029
Other Income (Expense)
Equity in earnings of subsidiaries............ 11,528 -- (11,528) --
Interest expense.............................. (10,679) (6,732) -- (17,411)
Interest and other income..................... 94 369 -- 463
-------- ------- -------- --------
Income Before Income Taxes and Cumulative
Effect of Accounting Change.................. 85,385 15,224 (11,528) 89,081
Income tax expense
Current..................................... (2,832) (3,182) -- (6,014)
Deferred.................................... (27,620) (754) -- (28,374)
-------- ------- -------- --------
Income Before Cumulative Effect of
Accounting Change............................ 54,933 11,288 (11,528) 54,693
Cumulative effect of accounting change, net of
tax benefit................................. (1,762) 240 -- (1,522)
-------- ------- -------- --------
Net Income..................................... $ 53,171 $11,528 $(11,528) $ 53,171
======== ======= ======== ========
F-50
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED STATEMENT OF INCOME
Year Ended December 31, 2000
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ --------
(In thousands)
Revenues
Crude oil and liquids.................... $ 85,921 $40,513 $ -- $126,434
Natural gas.............................. 16,017 -- -- 16,017
-------- ------- ------- --------
101,938 40,513 -- 142,451
-------- ------- ------- --------
Costs and Expenses
Production expenses..................... 35,278 20,950 -- 56,228
General and administrative.............. 5,168 1,140 -- 6,308
Depreciation, depletion and amortization 15,450 3,409 -- 18,859
-------- ------- ------- --------
55,896 25,499 -- 81,395
-------- ------- ------- --------
Income from Operations.................... 46,042 15,014 -- 61,056
Other Income (Expense)
Equity in earnings of subsidiaries....... 6,859 -- (6,859) --
Interest expense......................... (10,212) (5,673) -- (15,885)
Interest and other income................ 213 130 -- 343
-------- ------- ------- --------
Income Before Income Taxes................ 42,902 9,471 (6,859) 45,514
Income tax expense
Current................................ (168) (2,263) -- (2,431)
Deferred............................... (13,985) (349) -- (14,334)
-------- ------- ------- --------
Net Income................................ $ 28,749 $ 6,859 $(6,859) $ 28,749
======== ======= ======= ========
F-51
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED STATEMENT OF INCOME
Year Ended December 31, 1999
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ --------
(In thousands)
Revenues
Crude oil and liquids............. $73,073 $29,317 $ -- $102,390
Natural gas....................... 5,095 -- -- 5,095
------- ------- ------- --------
78,168 29,317 -- 107,485
------- ------- ------- --------
Costs and Expenses
Production expenses............... 35,526 15,001 -- 50,527
General and administrative........ 3,469 898 -- 4,367
Depreciation, depletion and
amortization.................... 11,154 2,175 -- 13,329
------- ------- ------- --------
50,149 18,074 -- 68,223
------- ------- ------- --------
Income from Operations............. 28,019 11,243 -- 39,262
Other Income (Expense)
Equity in earnings of subsidiaries 4,782 -- (4,782) --
Interest expense.................. (9,447) (5,465) -- (14,912)
Interest and other income......... 44 43 -- 87
------- ------- ------- --------
Income Before Income Taxes......... 23,398 5,821 (4,782) 24,437
Income tax (expense) benefit......
Current......................... 1,038 (1,543) -- (505)
Deferred........................ (5,331) 504 -- (4,827)
------- ------- ------- --------
Net Income......................... $19,105 $ 4,782 $(4,782) $ 19,105
======= ======= ======= ========
F-52
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED STATEMENT OF CASH FLOWS
Year Ended December 31, 2001
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ ---------
(In thousands)
Cash Flows From Operating Activities
Net income............................... $ 53,171 $ 11,528 $(11,528) $ 53,171
Items not affecting cash flows from
operating activities:
Depreciation, depletion and amortization 18,413 5,692 -- 24,105
Equity in earnings of subsidiaries...... (11,528) 11,528
Deferred income taxes................... 27,620 754 -- 28,374
Cumulative effect of adoption of
accounting change..................... 1,762 (240) -- 1,522
Change in derivative fair value......... (7) 1,062 -- 1,055
Other noncash items..................... 263 733 -- 996
Change in assets and liabilities from
operating activities:
Accounts receivable and other assets.... 9,449 (252) -- 9,197
Inventories............................. (586) (5) -- (591)
Accounts payable and other liabilities.. 157 (1,178) -- (1,021)
--------- -------- -------- ---------
Net cash provided by operating
activities.............................. 98,714 18,094 -- 116,808
--------- -------- -------- ---------
Cash Flows From Investing Activities
Acquisition, exploration and
developments costs..................... (108,577) (17,176) -- (125,753)
Additions to other property and equipment (127) -- -- (127)
--------- -------- -------- ---------
Net cash used in investing activities... (108,704) (17,176) -- (125,880)
--------- -------- -------- ---------
Cash Flows From Financing Activities
Principal payments of long-term debt..... (511) -- -- (511)
Receipts from (payments to) Plains
Resources Inc........................... 10,272 (1,212) -- 9,060
--------- -------- -------- ---------
Net cash provided by (used in)
financing activities.................... 9,761 (1,212) -- 8,549
--------- -------- -------- ---------
Net increase (decrease) in cash and cash
equivalents............................ (229) (294) -- (523)
Cash and cash equivalents, beginning of
year................................... 240 296 -- 536
--------- -------- -------- ---------
Cash and cash equivalents, end of year... $ 11 $ 2 $ -- $ 13
========= ======== ======== =========
F-53
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED STATEMENT OF CASH FLOWS
Year Ended December 31, 2000
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ --------
(In thousands)
Cash Flows From Operating Activities
Net income.................................. $ 28,749 $ 6,859 $(6,859) $ 28,749
Items not affecting cash flows from
operating activities:
Depreciation, depletion and amortization... 15,450 3,409 -- 18,859
Equity in earnings of subsidiaries......... (6,859) 6,859 --
Deferred income taxes...................... 13,985 349 -- 14,334
Other noncash items........................ -- --
Change in assets and liabilities from
operating activities:
Accounts receivable and other assets....... 7,192 405 -- 7,597
Inventories................................ 228 (423) -- (195)
Accounts payable and other liabilities..... 9,745 375 -- 10,120
-------- -------- ------- --------
Net cash provided by operating activities... 68,490 10,974 -- 79,464
-------- -------- ------- --------
Cash Flows From Investing Activities
Acquisition, exploration and developments
costs..................................... (54,782) (15,723) -- (70,505)
Additions to other property and equipment... (359) (7) -- (366)
-------- -------- ------- --------
Net cash used in investing activities....... (55,141) (15,730) -- (70,871)
-------- -------- ------- --------
Cash Flows From Financing Activities
Principal payments of long-term debt........ (511) -- -- (511)
Receipts from (payments to) Plains
Resources Inc............................. (12,803) 182 -- (12,621)
-------- -------- ------- --------
Net cash provided by (used in)
financing activities...................... (13,314) 182 -- (13,132)
-------- -------- ------- --------
Net increase (decrease) in cash and
cash equivalents.......................... 35 (4,574) -- (4,539)
Cash and cash equivalents, beginning of year 205 4,870 -- 5,075
-------- -------- ------- --------
Cash and cash equivalents, end of year...... $ 240 $ 296 $ -- $ 536
======== ======== ======= ========
F-54
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
CONSOLIDATING COMBINED STATEMENT OF CASH FLOWS
Year Ended December 31, 1999
Guarantor Intercompany
Issuer Subsidiaries Eliminations Combined
------ ------------ ------------ --------
(In thousands)
Cash Flows From Operating Activities
Net income............................... $ 19,105 $ 4,782 $(4,782) $ 19,105
Items not affecting cash flows from
operating activities:
Depreciation, depletion and amortization 11,154 2,175 -- 13,329
Equity in earnings of subsidiaries...... (4,782) 4,782 --
Deferred income taxes................... 5,331 (504) -- 4,827
Other noncash items.....................
Change in assets and liabilities from
operating activities:
Accounts receivable and other assets.... (24,329) (7,287) -- (31,616)
Inventories............................. 38 (624) -- (586)
Accounts payable and other liabilities.. (13,669) 13,219 -- (450)
-------- ------- ------- --------
Net cash provided by operating activities (7,152) 11,761 -- 4,609
-------- ------- ------- --------
Cash Flows From Investing Activities
Acquisition, exploration and
developments costs..................... (51,348) (7,819) -- (59,167)
Additions to other property and equipment (154) (41) -- (195)
-------- ------- ------- --------
Net cash used in investing activities.... (51,502) (7,860) -- (59,362)
-------- ------- ------- --------
Cash Flows From Financing Activities
Principal payments of long-term debt..... (511) -- -- (511)
Receipts from (payments to) Plains
Resources Inc.......................... 59,232 969 -- 60,201
-------- ------- ------- --------
Net cash provided by (used in)
financing activities................... 58,721 969 -- 59,690
-------- ------- ------- --------
Net increase (decrease) in cash and
cash equivalents....................... 67 4,870 -- 4,937
Cash and cash equivalents, beginning
of year................................ 138 -- -- 138
-------- ------- ------- --------
Cash and cash equivalents, end of year... $ 205 $ 4,870 $ -- $ 5,075
======== ======= ======= ========
F-55
UPSTREAM SUBSIDIARIES OF PLAINS RESOURCES INC.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (Continued)
Note 10 -- Capitalization
On September 30, 2002, the Companies were capitalized with 24.2 million
shares of common stock, all of which are owned by Plains. In accordance with
SEC Staff Accounting Bulletin No. 98, this capitalization has been
retroactively reflected for purposes of calculating earnings per share for all
periods presented in the accompanying combined statements of income. In
computing EPS, no adjustments were made to reported net income, and no
potential common stock exists. The weighted average shares outstanding for
computing both basic and diluted EPS was 24.2 million shares for all periods
presented.
Note 11 -- Subsequent Event (unaudited)
On September 18, 2002 Stocker Resources Inc., or Stocker, our general
partner before we converted from a limited partnership to a corporation, filed
a declaratory judgment action against Commonwealth Energy Corporation (doing
business as electricAmerica), or Commonwealth, in the Superior Court of Orange
County, California relating to the termination of an electric service contract
between Stocker and Commonwealth. Pursuant to the agreement, Commonwealth had
agreed to supply Stocker with electricity and Stocker had obtained a $1.5
million performance bond in favor of Commonwealth to secure its payment
obligations under the agreement. Stocker terminated the contract in accordance
with its terms and Commonwealth notified Stocker of its intent to draw upon the
performance bond. Stocker is seeking a declaratory judgment that it was
entitled to terminate the contract and that Commonwealth has no basis for
proceeding against Stocker's related performance bond. Also on September 18,
2002, Stocker was named a defendant in an action brought by Commonwealth in the
Superior Court of Orange County, California for breach of the electric service
contract. Commonwealth alleges that Stocker breached the terms of the contract
by the termination and its implied covenant of good faith and fair dealing and
is seeking unspecified damages. We will be required to indemnify Stocker for
damages, if any, it incurs as a result of this action. We understand that
Stocker intends to defend its rights vigorously in this matter.
At this time, the Companies are not in a position to express a judgment
concerning the potential exposure or likely outcome of this matter.
F-56
ANNEX A
LETTER OF TRANSMITTAL
LETTER OF TRANSMITTAL
To Tender For Exchange
83/4% Series A Senior Subordinated Notes Due 2012
of
PLAINS EXPLORATION & PRODUCTION COMPANY
PLAINS E&P COMPANY
Pursuant to the Prospectus Dated , 2002
THIS OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON UNLESS
EXTENDED BY PLAINS EXPLORATION & PRODUCTION COMPANY AND PLAINS E&P COMPANY IN
THEIR SOLE DISCRETION (THE "EXPIRATION DATE"). TENDERS OF NOTES MAY BE
WITHDRAWN AT ANY TIME PRIOR TO THE EXPIRATION DATE.
The Exchange Agent for the Exchange Offer is:
JPMORGAN CHASE BANK
By Mail: By Facsimile: By Hand:
JPMorgan Chase Bank (713) 577-5200 JPMorgan Chase Bank
600 Travis, Suite 1500 Attention: Rebecca Newman 600 Travis, Suite 1500
Houston, Texas 77002 Houston, Texas 77002
Attention: Rebecca Newman Confirm by Telephone: Attention: Rebecca Newman
(713) 216-4931
Attention: Rebecca Newman
DELIVERY OF THIS LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET
FORTH ABOVE OR TRANSMISSION OF INSTRUCTIONS VIA FACSIMILE TO A NUMBER OTHER
THAN AS LISTED ABOVE WILL NOT CONSTITUTE A VALID DELIVERY.
HOLDERS WHO WISH TO BE ELIGIBLE TO RECEIVE SERIES B NOTES IN TO THE
EXCHANGE OFFER MUST VALIDLY TENDER (AND NOT WITHDRAW) THEIR SERIES A NOTES TO
THE EXCHANGE AGENT ON OR PRIOR TO THE EXPIRATION DATE.
This Letter of Transmittal is to be used by holders ("Holders") of 83/4%
Series A Senior Subordinated Notes due 2012 (the "Series A notes") of Plains
Exploration & Production Company and Plains E&P Company (together, the
"Issuers") to receive 83/4% Series B Senior Subordinated Notes due 2012 (the
"Series B notes") if: (i) certificates representing Series A notes are to be
physically delivered to the Exchange Agent herewith by such Holders; (ii)
tender of Series A notes is to be made by book-entry transfer to the Exchange
Agent's account at The Depository Trust Company ("DTC") pursuant to the
procedures set forth under the caption "The Exchange Offer--Procedures for
Tendering Series A Notes Book-Entry Delivery Procedures" in the Prospectus
dated , 2002 (the "Prospectus"); or (iii) tender of Series A notes is
to be made according to the guaranteed delivery procedures set forth under the
caption "The Exchange Offer--Procedures for Tendering Series A
Notes--Guaranteed Delivery" in the Prospectus, and, in each case, instructions
are not being transmitted through the DTC Automated Tender Offer Program
("ATOP"). The undersigned hereby acknowledges receipt of the Prospectus. All
capitalized terms used herein and not defined shall have the meanings ascribed
to them in the Prospectus.
A-1
Holders of Series A notes that are tendering by book-entry transfer to the
Exchange Agent's account at DTC can execute the tender through ATOP, for which
the transaction will be eligible. DTC participants that are accepting the
exchange offer as set forth in the Prospectus and this Letter of Transmittal
(together, the "Exchange Offer") must transmit their acceptance to DTC which
will edit and verify the acceptance and execute a book-entry delivery to the
Exchange Agent's account at DTC. DTC will then send an Agent's Message to the
Exchange Agent for its acceptance. Delivery of the Agent's Message by DTC will
satisfy the terms of the Offer as to execution and delivery of a Letter of
Transmittal by the participant identified in the Agent's Message. DTC
participants may also accept the Exchange Offer by submitting a notice of
guaranteed delivery through ATOP.
Delivery of documents to DTC does not constitute delivery to the exchange agent.
If a Holder desires to tender Series A notes pursuant to the Exchange Offer
and time will not permit this Letter of Transmittal, certificates representing
such Series A notes and all other required documents to reach the Exchange
Agent, or the procedures for book-entry transfer cannot be completed, on or
prior to the Expiration Date, then such Holder must tender such Series A notes
according to the guaranteed delivery procedures set forth under the caption
"The Exchange Offer-- Procedures for Tendering Series A Notes--Guaranteed
Delivery" in the Prospectus. See Instruction 2.
The undersigned should complete, execute and deliver this Letter of
Transmittal to indicate the action the undersigned desires to take with respect
to the Exchange Offer.
TENDER OF SERIES A NOTES
[_] CHECK HERE IF TENDERED SERIES A NOTES ARE ENCLOSED HEREWITH.
[_] CHECK HERE IF TENDERED SERIES A NOTES ARE BEING DELIVERED BY BOOK-
ENTRY TRANSFER MADE TO THE ACCOUNT MAINTAINED BY THE EXCHANGE AGENT
WITH DTC AND COMPLETE THE FOLLOWING:
Name of Tendering Institution: ______________________________________
Account Number: _____________________________________________________
Transaction Code Number: ____________________________________________
-------------------------------------------------------------------------
[_] CHECK HERE IF TENDERED SERIES A NOTES ARE BEING DELIVERED PURSUANT TO
A NOTICE OF GUARANTEED DELIVERY PREVIOUSLY SENT TO THE EXCHANGE
AGENT AND COMPLETE THE FOLLOWING:
Name(s) of Registered Holder(s): ____________________________________
Window Ticker Number (if any): ______________________________________
Date of Execution of Notice of Guaranteed Delivery: _________________
Name of Eligible Institution that Guaranteed Delivery: ______________
A-2
List below the Series A notes to which this Letter of Transmittal relates.
The name(s) and address(es) of the registered Holder(s) should be printed, if
not already printed below, exactly as they appear on the Series A notes
tendered hereby. The Series A notes and the principal amount of Series A notes
that the undersigned wishes to tender would be indicated in the appropriate
boxes. If the space provided is inadequate, list the certificate number(s) and
principal amount(s) on a separately executed schedule and affix the schedule to
this Letter of Transmittal.
DESCRIPTION OF SERIES A NOTES
- ---------------------------------------------------------------------------------------------------------------------
Name(s) and Address(es)
of Registered Holder(s) Aggregate Principal Principal Total Principal
(Please fill in, if blank) Certificate Amount Amount Amount of
See Instruction 3. Number(s)* Represented** Tendered** Series A Notes
- ---------------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------
----------------------------------------------------------------------------------
----------------------------------------------------------------------------------
----------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
*Need not be completed by Holders tendering by book-entry transfer.
**Unless otherwise specified, the entire aggregate principal amount represented by the Series A notes described above
will be deemed to be tendered. See Instruction 4.
NOTE: SIGNATURES MUST BE PROVIDED BELOW.
PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.
Ladies and Gentlemen:
The undersigned hereby tenders to Plains Exploration & Production Company
and Plains E&P Company (together, the "Issuers"), upon the terms and subject to
the conditions set forth in their Prospectus dated , 2002 (the
"Prospectus"), receipt of which is hereby acknowledged, and in accordance with
this Letter of Transmittal (which together constitute the "Exchange Offer"),
the principal amount of Series A notes indicated in the foregoing table
entitled "Description of Series A Notes" under the column heading "Principal
Amount Tendered." The undersigned represents that it is duly authorized to
tender all of the Series A notes tendered hereby which it holds for the account
of beneficial owners of such Series A notes ("Beneficial Owner(s)") and to make
the representations and statements set forth herein on behalf of such
Beneficial Owner(s).
Subject to, and effective upon, the acceptance for purchase of the
principal amount of Series A notes tendered herewith in accordance with the
terms and subject to the conditions of the Exchange Offer, the undersigned
hereby sells, assigns and transfers to, or upon the order of, the Issuers, all
right, title and interest in and to all of the Series A notes tendered hereby.
The undersigned hereby irrevocably constitutes and appoints the Exchange Agent
the true and lawful agent and attorney-in-fact of the undersigned (with full
knowledge that the Exchange Agent also acts as the agent of the Issuers) with
respect to such Series A notes, with full powers of substitution and revocation
(such power of attorney being deemed to be an irrevocable power coupled with an
interest) to (i) present such Series A notes and all evidences of transfer and
authenticity to, or transfer ownership of, such Series A notes on the account
books maintained by DTC to, or upon the order of, the Issuers, (ii) present
such Series A notes for transfer of ownership on the books of the Issuers, and
(iii) receive all benefits and otherwise exercise all rights of beneficial
ownership of such Series A notes, all in accordance with the terms and
conditions of the Exchange Offer as described in the Prospectus.
A-3
By accepting the Exchange Offer, the undersigned hereby represents and
warrants that:
(i) the Series B notes to be acquired by the undersigned and any
Beneficial Owner(s) in connection with the Exchange Offer are being
acquired by the undersigned and any Beneficial Owner(s) in the ordinary
course of business of the undersigned and any Beneficial Owner(s),
(ii) the undersigned and each Beneficial Owner are not participating,
do not intend to participate, and have no arrangement or understanding with
any person to participate, in the distribution of the Series B notes,
(iii) except as indicated below, neither the undersigned nor any
Beneficial Owner is an "affiliate," as defined in Rule 405 under the
Securities Act of 1933, as amended (together with the rules and regulations
promulgated thereunder, the "Securities Act"), of the Issuers, and
(iv) the undersigned and each Beneficial Owner acknowledge and agree
that (x) any person participating in the Exchange Offer with the intention
or for the purpose of distributing the Series B notes must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with a secondary resale of the Series B notes acquired by such
person with a registration statement containing the selling securityholder
information required by Item 507 of Regulation S-K of the Securities and
Exchange Commission (the "SEC") and cannot rely on the interpretation of
the Staff of the SEC set forth in the no-action letters that are noted in
the section of the Prospectus entitled "The Exchange Offer--Registration
Rights" and (y) any broker-dealer that pursuant to the Exchange Offer
receives Series B notes for its own account in exchange for Series A notes
which it acquired for its own account as a result of market-making
activities or other trading activities must deliver a prospectus meeting
the requirements of the Securities Act in connection with any resale of
such Series B notes.
If the undersigned is a broker-dealer that will receive Series B notes for
its own account in exchange for Series A notes that were acquired as the result
of market-making activities or other trading activities, it acknowledges that
it will deliver a prospectus in connection with any resale of such Series B
notes. By so acknowledging and by delivering a prospectus, a broker-dealer
shall not be deemed to admit that it is an "underwriter" within the meaning of
the Securities Act.
The undersigned understands that tenders of Series A notes may be withdrawn
by written notice of withdrawal received by the Exchange Agent at any time
prior to the Expiration Date in accordance with the Prospectus. In the event of
a termination of the Exchange Offer, the Series A notes tendered pursuant to
the Exchange Offer will be returned to the tendering Holders promptly (or, in
the case of Series A notes tendered by book-entry transfer, such Series A notes
will be credited to the account maintained at DTC from which such Series A
notes were delivered). If the Issuers make a material change in the terms of
the Exchange Offer or the information concerning the Exchange Offer or waives a
material condition of such Exchange Offer, the Issuers will disseminate
additional Exchange Offer materials and extend such Exchange Offer, if and to
the extent required by law.
The undersigned understands that the tender of Series A notes pursuant to
any of the procedures set forth in the Prospectus and in the instructions
hereto will constitute the undersigned's acceptance of the terms and conditions
of the Exchange Offer. The Issuers' acceptance for exchange of Series A notes
tendered pursuant to any of the procedures described in the Prospectus will
constitute a binding agreement between the undersigned and the Issuers in
accordance with the terms and subject to the conditions of the Exchange Offer.
For purposes of the Exchange Offer, the undersigned understands that validly
tendered Series A notes (or defectively tendered Series A notes with respect to
which the Issuers have, or have caused to be, waived such defect) will be
deemed to have been accepted by the Issuers if, as and when the Issuers give
oral or written notice thereof to the Exchange Agent.
A-4
The undersigned hereby represents and warrants that the undersigned has
full power and authority to tender, sell, assign and transfer the Series A
notes tendered hereby, and that when such tendered Series A notes are accepted
for purchase by the Issuers, the Issuers will acquire good title thereto, free
and clear of all liens, restrictions, charges and encumbrances and not subject
to any adverse claim or right. The undersigned and each Beneficial Owner will,
upon request, execute and deliver any additional documents deemed by the
Exchange Agent or by the Issuers to be necessary or desirable to complete the
sale, assignment and transfer of the Series A notes tendered hereby.
All authority conferred or agreed to be conferred by this Letter of
Transmittal shall not be affected by, and shall survive the death or incapacity
of the undersigned and any Beneficial Owner(s), and any obligation of the
undersigned or any Beneficial Owner(s) hereunder shall be binding upon the
heirs, executors, administrators, trustees in bankruptcy, personal and legal
representatives, successors and assigns of the undersigned and such Beneficial
Owner(s).
The undersigned understands that the delivery and surrender of any Series A
notes is not effective, and the risk of loss of the Series A notes does not
pass to the Exchange Agent or the Issuers, until receipt by the Exchange Agent
of this Letter of Transmittal, or a manually signed facsimile hereof, properly
completed and duly executed, together with all accompanying evidences of
authority and any other required documents in form satisfactory to the Issuers.
All questions as to form of all documents and the validity (including time of
receipt) and acceptance of tenders and withdrawals of Series A notes will be
determined by the Issuers, in their discretion, which determination shall be
final and binding.
Unless otherwise indicated herein under "Special Issuance Instructions,"
the undersigned hereby requests that any Series A notes representing principal
amounts not tendered or not accepted for exchange be issued in the name(s) of
the undersigned (and in the case of Series A notes tendered by book-entry
transfer, by credit to the account of DTC), and Series B notes issued in
exchange for Series A notes pursuant to the Exchange Offer be issued to the
undersigned. Similarly, unless otherwise indicated herein under "Special
Delivery Instructions," the undersigned hereby requests that any Series A notes
representing principal amounts not tendered or not accepted for exchange and
Series B notes issued in exchange for Series A notes pursuant to the Exchange
Offer be delivered to the undersigned at the address shown below the
undersigned's signature(s). In the event that the "Special Issuance
Instructions" box or the "Special Delivery Instructions" box is, or both are,
completed, the undersigned hereby requests that any Series A notes representing
principal amounts not tendered or not accepted for purchase be issued in the
name(s) of, certificates for such Series A notes be delivered to, and Series B
notes issued in exchange for Series A notes pursuant to the Exchange Offer be
issued in the name(s) of, and be delivered to, the person(s) at the address(es)
so indicated, as applicable. The undersigned recognizes that the Issuers have
no obligation pursuant to the "Special Issuance Instructions" box or "Special
Delivery Instructions" box to transfer any Series A notes from the name of the
registered Holder(s) thereof if the Issuers do not accept for exchange any of
the principal amount of such Series A notes so tendered.
A-5
[_] CHECK HERE IF YOU OR ANY BENEFICIAL OWNER FOR WHOM YOU HOLD SERIES A
NOTES IS AN AFFILIATE OF THE ISSUERS.
[_] CHECK HERE IF YOU OR ANY BENEFICIAL OWNER FOR WHOM YOU HOLD SERIES A
NOTES TENDERED HEREBY IS A BROKER-DEALER WHO ACQUIRED SUCH NOTES
DIRECTLY FROM THE ISSUERS OR AN AFFILIATE OF THE ISSUERS.
[_] CHECK HERE AND COMPLETE THE LINES BELOW IF YOU OR ANY BENEFICIAL
OWNER FOR WHOM YOU HOLD SERIES A NOTES TENDERED HEREBY IS A BROKER-
DEALER WHO ACQUIRED SUCH NOTES IN MARKET-MAKING OR OTHER TRADING
ACTIVITIES. IF THIS BOX IS CHECKED, THE ISSUERS WILL SEND 10 ADDITIONAL
COPIES OF THE PROSPECTUS AND 10 COPIES OF ANY AMENDMENTS OR
SUPPLEMENTS THERETO TO YOU OR SUCH BENEFICIAL OWNER AT THE ADDRESS
SPECIFIED IN THE FOLLOWING LINES.
Name: ___________________________________
Address: ________________________________
________________________________
A-6
- --------------------------------------------------- ------------------------------------------------
SPECIAL ISSUANCE INSTRUCTIONS SPECIAL DELIVERY INSTRUCTIONS
(See Instructions 1, 5, 6 and 7) (See Instructions 1, 5, 6 and 7)
To be completed ONLY if Series A notes in To be completed ONLY if Series A notes in
a principal amount not tendered or not ac- a principal amount not tendered or not
cepted for exchange are to be issued in the accepted for exchange or Series B notes are
name of, or Series B notes are to be issued in to be sent to someone other than the
the name of, someone other than the person(s) whose signature(s) appear(s) within
person(s) whose signature(s) appear(s) within this Letter of Transmittal or to an address
this Letter of Transmittal or issued to an ad- different from that shown in the box entitled
dress different from that shown in the box enti- "Description of Series A Notes" within this
tled "Description of Series A Notes" within this Letter of Transmittal.
Letter of Transmittal.
Issue: [_] Series A notes [_] Series B notes..
Issue: [_] Series A notes [_] Series B notes.. (check as applicable)
(check as applicable)
Name _________________________________________
Name ___________________________________________ (Please Print)
(Please Print)
Address ______________________________________
Address ________________________________________ (Please Print)
(Please Print)
______________________________________________
________________________________________________ (Zip Code)
(Zip Code)
______________________________________________
________________________________________________ (Tax Identification or Social Security Number)
(Tax Identification or Social Security Number) (See Substitute Form W-9 Herein)
(See Substitute Form W-9 Herein)
- --------------------------------------------------- ------------------------------------------------
A-7
PLEASE SIGN HERE
(To be completed by all tendering Holders of Series A notes
regardless of whether Series A notes are being physically delivered herewith)
This Letter of Transmittal must be signed by the registered Holder(s) exactly as name(s)
appear(s) on certificate(s) for Series A notes or, if tendered by a participant in DTC exactly as such
participant's name appears on a security position listing as owner of Series A notes, or by the
person(s) authorized to become registered Holder(s) by endorsements and documents transmitted
herewith. If signature is by trustees, executors, administrators, guardians, attorneys-in-fact, officers
of corporations or others acting in a fiduciary or representative capacity, please set forth full title and
see Instruction 5.
___________________________________________________________________________________________________________
___________________________________________________________________________________________________________
Signature(s) of Registered Holder(s) or Authorized Signatory
(See guarantee requirement below)
Dated: ____________________________________________________________________________________________________
Name(s): __________________________________________________________________________________________________
(Please Print)
Capacity (Full Title): ____________________________________________________________________________________
Address: __________________________________________________________________________________________________
___________________________________________________________________________________________________________
(Including Zip Code)
Area Code and Telephone No.: ______________________________________________________________________________
Tax Identification or Social Security Number: _____________________________________________________________
COMPLETE ACCOMPANYING SUBSTITUTE FORM W-9
SIGNATURE GUARANTEE
(If Required--See Instructions 1 and 5)
_______________________________________
(Authorized Signature)
_______________________________________
(Name of Firm)
[place seal here]
A-8
INSTRUCTIONS
Forming Part of The Terms and Conditions of The Exchange Offer
1. Signature Guarantees. Signatures of this Letter of Transmittal must be
guaranteed by a recognized member of the Medallion Signature Guarantee Program
or by any other "eligible guarantor institution," as such term is defined in
Rule 17Ad-15 promulgated under the Exchange Act (each of the foregoing, an
"Eligible Institution"), unless the Series A notes tendered hereby are tendered
(i) by a registered Holder of Series A notes (or by a participant in DTC whose
name appears on a security position listing as the owner of such Series A
notes) that has not completed either the box entitled "Special Issuance
Instructions" or the box entitled "Special Delivery Instructions" on this
Letter of Transmittal, or (ii) for the account of an Eligible Institution. If
the Series A notes are registered in the name of a person other than the signer
of this Letter of Transmittal, if Series A notes not accepted for exchange or
not tendered are to be returned to a person other than the registered Holder or
if Series B notes are to be issued in the name of or sent to a person other
than the registered Holder, then the signatures on this Letter of Transmittal
accompanying the tendered Series A notes must be guaranteed by an Eligible
Institution as described above. See Instruction 5.
2. Delivery of Letter of Transmittal and Series A Notes. This Letter of
Transmittal is to be completed by Holders if (i) certificates representing
Series A notes are to be physically delivered to the Exchange Agent herewith by
such Holders; (ii) tender of Series A notes is to be made by book-entry
transfer to the Exchange Agent's account at DTC pursuant to the procedures set
forth under the caption "The Exchange offer--Procedures for Tendering Series A
Notes--Book-Entry Delivery Procedures" in the Prospectus; or (iii) tender of
Series A notes is to be made according to the guaranteed delivery procedures
set forth under the caption "The Exchange Offer--Procedures for Tendering
Series A Notes--Guaranteed Delivery" in the Prospectus. All physically
delivered Series A notes, or a confirmation of a book-entry transfer into the
Exchange Agent's account at DTC of all Series A notes delivered electronically,
as well as a properly completed and duly executed Letter of Transmittal (or
manually signed facsimile thereof), any required signature guarantees and any
other documents required by this Letter of Transmittal, must be received by the
Exchange Agent at one of its addresses set forth on the cover page hereto on or
prior to the Expiration Date, or the tendering Holder must comply with the
guaranteed delivery procedures set forth below. Delivery of documents to DTC
does not constitute delivery to the Exchange Agent.
If a Holder desires to tender Series A notes pursuant to the Exchange Offer
and time will not permit this Letter of Transmittal, certificates representing
such Series A notes and all other required documents to reach the Exchange
Agent, or the procedures for book-entry transfer cannot be completed, on or
prior to the Expiration Date, such Holder must tender such Series A notes
pursuant to the guaranteed delivery procedures set forth under the caption "The
Exchange Offer--Procedures for Tendering Series A Notes--Guaranteed Delivery"
in the Prospectus. Pursuant to such procedures, (i) such tender must be made by
or through an Eligible Institution; (ii) a properly completed and duly executed
Notice of Guaranteed Delivery, substantially in the form provided by the
Issuers, or an Agent's Message with respect to guaranteed delivery that is
accepted by the Issuers, must be received by the Exchange Agent, either by hand
delivery, mail, telegram, or facsimile transmission, on or prior to the
Expiration Date; and (iii) the certificates for all tendered Series A notes, in
proper form for transfer (or confirmation of a book-entry transfer or all
Series A notes delivered electronically into the Exchange Agent's account at
DTC pursuant to the procedures for such transfer set forth in the Prospectus),
together with a properly completed and duly executed Letter of Transmittal (or
manually signed facsimile thereof) and any other documents required by this
Letter of Transmittal, or in the case of a book-entry transfer, a properly
transmitted Agent's Message, must be received by the Exchange Agent within two
business days after the date of the execution of the Notice of Guaranteed
Delivery.
A-9
The method of delivery of this Letter of Transmittal, the Series A notes
and all other required documents, including delivery through DTC and any
acceptance or agent's message delivered through ATOP, is at the election and
risk of the tendering Holder and, except as otherwise provided in this
Instruction 2, delivery will be deemed made only when actually received by the
Exchange Agent. If delivery is by mail, it is suggested that the Holder use
properly insured, registered mail with return receipt requested, and that the
mailing be made sufficiently in advance of the Expiration Date to permit
delivery to the Exchange Agent prior to such date.
No alternative, conditional or contingent tenders will be accepted. All
tendering Holders, by execution of this Letter of Transmittal (or a facsimile
thereof), waive any right to receive any notice of the acceptance of their
Series A notes for exchange.
3. Inadequate Space. If the space provided herein is inadequate, the
certificate numbers and/or the principal amount represented by Series A notes
should be listed on separate signed schedule attached hereto.
4. Partial Tenders. (Not applicable to Holders who tender by book-entry
transfer). If Holders wish to tender less than the entire principal amount
evidenced by a Series A note submitted, such Holders must fill in the principal
amount that is to be tendered in the column entitled "Principal Amount
Tendered." The minimum permitted tender is $1,000 in principal amount of Series
A notes. All other tenders must be in integral multiples of $1,000 in principal
amount. In the case of a partial tender of Series A notes, as soon as
practicable after the Expiration Date, new certificates for the remainder of
the Series A notes that were evidenced by such Holder's old certificates will
be sent to such Holder, unless otherwise provided in the appropriate box on
this Letter of Transmittal. The entire principal amount that is represented by
Series A notes delivered to the Exchange Agent will be deemed to have been
tendered, unless otherwise indicated.
5. Signatures on Letter of Transmittal, Instruments of Transfer and
Endorsements. If this Letter of Transmittal is signed by the registered
Holder(s) of the Series A notes tendered hereby, the signatures must correspond
with the name(s) as written on the face of the certificate(s) without
alteration, enlargement or any change whatsoever. If this Letter of Transmittal
is signed by a participant in DTC whose name is shown as the owner of the
Series A notes tendered hereby, the signature must correspond with the name
shown on the security position listing as the owner of the Series A notes.
If any of the Series A notes tendered hereby are registered in the name of
two or more Holders, all such Holders must sign this Letter of Transmittal. If
any of the Series A notes tendered hereby are registered in different names on
several certificates, it will be necessary to complete, sign and submit as many
separate Letters of Transmittal as there are different registrations of
certificates.
If this Letter of Transmittal or any Series A note or instrument of
transfer is signed by a trustee, executor, administrator, guardian,
attorney-in-fact, agent, officer of a corporation or other person acting in a
fiduciary or representative capacity, such person should so indicate when
signing, and proper evidence satisfactory to the Issuers of such person's
authority to so act must be submitted.
When this Letter of Transmittal is signed by the registered Holder(s) of
the Series A notes listed herein and transmitted hereby, no endorsements of
Series A notes or separate instruments of transfer are required unless Series B
notes are to be issued, or Series A notes not tendered or exchanged are to be
issued, to a person other than the registered Holder(s), in which case
signatures on such Series A notes or instruments of transfer must be guaranteed
by an Eligible Institution.
A-10
If this Letter of Transmittal is signed other than by the registered
Holder(s) of the Series A notes listed herein, the Series A notes must be
endorsed or accompanied by appropriate instruments of transfer, in either case
signed exactly as the name(s) of the registered Holder(s) appear on the Series
A notes and signatures on such Series A notes or instruments of transfer are
required and must be guaranteed by an Eligible Institution, unless the
signature is that of an Eligible Institution.
6. Special Issuance and Delivery Instructions. If certificates for Series
B notes or unexchanged or untendered Series A notes are to be issued in the
name of a person other than the signer of this Letter of Transmittal, or if
Series B notes or such Series A notes are to be sent to someone other than the
signer of this Letter of Transmittal or to an address other than that shown
herein, the appropriate boxes on this Letter of Transmittal should be
completed. All Series A notes tendered by book-entry transfer and not accepted
for payment will be returned by crediting the account at DTC designated herein
as the account for which such Series A notes were delivered.
7. Transfer Taxes. Except as set forth in this Instruction 7, the Issuers
will pay or cause to be paid any transfer taxes with respect to the transfer
and sale of Series A notes to it, or to its order, pursuant to the Exchange
Offer. If Series B notes, or Series A notes not tendered or exchanged are to be
registered in the name of any persons other than the registered owners, or if
tendered Series A notes are registered in the name of any persons other than
the persons signing this Letter of Transmittal, the amount of any transfer
taxes (whether imposed on the registered Holder or such other person) payable
on account of the transfer to such other person must be paid to the Issuers or
the Exchange Agent (unless satisfactory evidence of the payment of such taxes
or exemption therefrom is submitted) before the Series B notes will be issued.
8. Waiver of Conditions. The conditions of the Exchange Offer may be
amended or waived by the Issuers, in whole or in part, at any time and from
time to time in the Issuers' discretion, in the case of any Series A notes
tendered.
9. Substitute Form W-9. Each tendering owner of a Note (or other payee)
is required to provide the Exchange Agent with a correct taxpayer
identification number ("TIN"), generally the owner's social security or federal
employer identification number, and with certain other information, on
Substitute Form W-9, which is provided hereafter under "Important Tax
Information," and to certify that the owner (or other payee) is not subject to
backup withholding. Failure to provide the information on the Substitute Form
W-9 may subject the tendering owner (or other payee) to a $50 penalty imposed
by the Internal Revenue Service and 31% federal income tax withholding. The box
in Part 3 of the Substitute Form W-9 may be checked if the tendering owner (or
other payee) has not been issued a TIN and has applied for a TIN or intends to
apply for a TIN in the near future. If the box in Part 3 is checked and the
Exchange Agent is not provided with a TIN within 60 days of the date on the
Substitute Form W-9, the Exchange Agent will withhold 31% until a TIN is
provided to the Exchange Agent.
10. Broker-dealers Participating in the Exchange Offer. If no
broker-dealer checks the last box on page 6 of this Letter of Transmittal, the
Issuers have no obligation under the Registration Rights Agreement to allow the
use of the Prospectus for resales of the Series B notes by broker-dealers or to
maintain the effectiveness of the Registration Statement of which the
Prospectus is a part after the consummation of the Exchange Offer.
11. Requests for Assistance or Additional Copies. Any questions or
requests for assistance or additional copies of the Prospectus, this Letter of
Transmittal or the Notice of Guaranteed Delivery may be directed to the
Exchange Agent at the telephone numbers and location listed above. A Holder or
owner may also contact such Holder's or owner's broker, dealer, commercial bank
or trust company or nominee for assistance concerning the Exchange Offer.
A-11
IMPORTANT: This Letter of Transmittal (or a facsimile hereof), together
with certificates representing the Series A notes and all other required
documents or the Notice of Guaranteed Delivery, must be received by the
Exchange Agent on or prior to the Expiration Date.
IMPORTANT TAX INFORMATION
Under federal income tax law, an owner of Series A notes whose tendered
Series A notes are accepted for exchange is required to provide the Exchange
Agent with such owner's current TIN on Substitute Form W-9 below. If such owner
is an individual, the TIN is his or her social security number. If the Exchange
Agent is not provided with the correct TIN, the owner or other recipient of
Series B notes may be subject to a $50 penalty imposed by the Internal Revenue
Service. In addition, any interest on Series B notes paid to such owner or
other recipient may be subject to 31% backup withholding tax.
Certain owners of Notes (including, among others, all corporations and
certain foreign individuals) are not subject to these backup withholding and
reporting requirements. In order for a foreign individual to qualify as an
exempt recipient, that owner must submit to the Exchange Agent a properly
completed Internal Revenue Service Forms W-8ECI, W-8BEN, W-8EXP or W-8IMY
(collectively, a "Form W-8"), signed under penalties of perjury, attesting to
that individual's exempt status. A Form W-8 can be obtained from the Exchange
Agent. See the enclosed "Guidelines for Certification of Taxpayer
Identification Number on Substitute Form W-9" for additional instructions.
Backup withholding is not an additional tax. Rather, the federal income tax
liability of persons subject to backup withholding will be reduced by the
amount of tax withheld. If withholding results in an overpayment of taxes, a
refund may be obtained from the Internal Revenue Service.
Purpose of Substitute Form W-9
To prevent backup withholding the owner is required to notify the Exchange
Agent of the owner's current TIN (or the TIN of any other payee) by completing
the following form, certifying that the TIN provided on Substitute Form W-9 is
correct (or that such owner is awaiting a TIN), and that (i) the owner is
exempt from withholding, (ii) the owner has not been notified by the Internal
Revenue Service that the owner is subject to backup withholding as a result of
failure to report all interest or dividends or (iii) the Internal Revenue
Service has notified the owner that the owner is no longer subject to backup
withholding.
What Number to Give The Exchange Agent
The Holder is required to give the Exchange Agent the TIN (e.g., social
security number or employer identification number) of the owner of the Series A
notes. If the Series A notes are registered in more than one name or are not
registered in the name of the actual owner, consult the enclosed "Guidelines
for Certification of Taxpayer Identification Number on Substitute Form W-9,"
for additional guidance on which number to report.
A-12
- ---------------------------------------------------------------------------------------------------------------
PART 1--PLEASE PROVIDE YOUR TIN IN
THE BOX AT RIGHT AND CERTIFY BY Social Security Number(s) or
SIGNING AND DATING BELOW. Employer Identification Number
-----------------------------------------------
------------------------------------------------------------------------------------
SUBSTITUTE
Form W-9 PART 2--CERTIFICATION
Department of The ------------------------------------------------------------------------------------
Treasury ------------------------------------------------------------------------------------
Internal Revenue Service UNDER PENALTIES OF PERJURY, I CERTIFY THAT:
Payer's Request for (1) The number shown on this form is my correct taxpayer identification
Taxpayer Identification number (or I am waiting for a number to be issued to me), and
No. ("TIN")
(2) I am not subject to backup withholding because: (a) I am exempt from
backup withholding, or (b) I have not been notified by the Internal Revenue
Service ("IRS") that I am subject to backup withholding as a result of a
failure to report all interest or dividends, or (c) the IRS has notified me that
I am no longer subject to backup withholding
Signature________________________________ Date
- - ------------------------------------------------------------------------------------
CERTIFICATION INSTRUCTIONS--You must cross out item (2) above if you have been notified by the IRS
that you are subject to backup withholding because of underreporting interest or dividends on your tax return.
- ---------------------------------------------------------------------------------------------------------------
PART 3--Awaiting TIN [ ]
- ---------------------------------------------------------------------------------------------------------------
NOTE: FAILURE TO COMPLETE AND RETURN THIS FORM MAY RESULT IN A $50 PENALTY
IMPOSED BY THE INTERNAL REVENUE SERVICE AND BACKUP WITHHOLDING OF 31%.
PLEASE REVIEW THE ENCLOSED GUIDELINES FOR CERTIFICATION OF TAXPAYER
IDENTIFICATION NUMBER ON SUBSTITUTE FORM W-9 FOR ADDITIONAL DETAILS.
YOU MUST COMPLETE THE FOLLOWING CERTIFICATE IF YOU CHECKED THE BOX IN
PART 3 OF SUBSTITUTE FORM W-9.
- ----------------------------------------------------------------------------------------------------------------
CERTIFICATE OF AWAITING TAXPAYER IDENTIFICATION NUMBER
I certify under penalties of perjury that a taxpayer identification number has not been issued to me, and either
(1) I have mailed or delivered an application to receive a taxpayer identification number to the appropriate
Internal Revenue Service Center or Social Security Administration Office, or (2) I intend to mail or deliver an
application in the near future. I understand that if I do not provide a taxpayer identification number within 60
days of the date in this form, 31% of all reportable cash payments made to me will be withheld until I provide
a taxpayer identification number.
Signature __________________________________________ Date
- ----------------------------------------------------------------------------------------------------------------
A-13
GUIDELINES FOR CERTIFICATION OF TAXPAYER IDENTIFICATION
NUMBER ON SUBSTITUTION FORM W-9
Guidelines for Determining the Proper Identification Number to Give the
Payer--Social Security numbers have nine digits separated by two hyphens: i.e.
000-00-0000. Employer identification numbers have nine digits separated by only
one hyphen: i.e. 00-0000000. The table below will help determine the number to
give the payer.
- --------
(1) List first and circle the name of the person whose number you furnish.
(2) Circle the minor's name and furnish the minor's Social Security number.
(3) Circle the ward's, minor's or incompetent person's name and furnish such
person's social security number.
(4) Show the name of the owner. If the owner does not have an employer
identification number, furnish the owner's social security number.
(5) List first and circle the name of the legal trust, estate, or pension trust.
Note: If no name is circled when there is more than one name, the number will
be considered to be that of the first name listed.
A-14
----------------------------------------------------------------------------
For this type of account: Give the
SOCIAL SECURITY
number of--
----------------------------------------------------------------------------
1. An individual's account The individual
2. Two or more individuals (joint The actual owner of the
account) account or, if combined
funds, the first individual
on the account(1)
3. Husband and wife (joint account) The actual owner of the
account or, if joint funds,
either person(1)
4. Custodian account of a minor The minor(2)
(Uniform Gift to Minors Act)
5. Adult and minor (joint account) The adult or, if the minor is
the only contributor, the
minor(1)
6. Account in the name of guardian or The ward, minor, or
committee for a designated ward, incompetent person(3)
minor, or incompetent person
7. a A revocable savings trust account The grantor-trustee(1)
(in which grantor is also trustee)
b Any "trust" account that is not a The actual owner(1)
legal or valid trust under State law
8. Sole proprietorship account The owner(4)
----------------------------------------------------------------------------
--------------------------------------------------------------------------
For this type of account: Give the EMPLOYER
IDENTIFICATION
number of--
--------------------------------------------------------------------------
9. A valid trust, estate, or pension trust The legal entity (do not
furnish the identifying
number of the personal
representative or trustee
unless the legal entity itself
is not designated in the
account title.)(5)
10. Corporate account The corporation
11. Religious, charitable, or educational The organization
organization account
12. Partnership account held in the The partnership
name of the business
13. Association, club, or other tax- The organization
exempt organization
14. A broker or registered nominee The broker or nominee
15. Account with the Department of The public entity
Agriculture in the name of a public
entity (such as a State or local
government, school district, or
prison) that receives agricultural
program payments
--------------------------------------------------------------------------
GUIDELINES FOR CERTIFICATION OF TAXPAYER IDENTIFICATION
NUMBER ON SUBSTITUTE FORM W-9
Page 2
Obtaining a Number
If you do not have a taxpayer identification number or you do not know your
number, obtain Form SS-5, Application for a Social Security Number Card (for
resident individuals), Form SS-4, Application for Employer Identification
Number (for businesses and all other entities), or Form W-7 for International
Taxpayer Identification Number (for alien individuals required to file U.S. tax
returns), at an office of the Social Security Administration or the Internal
Revenue Service.
To complete Substitute Form W-9, if you do not have a taxpayer identification
number, write "Applied For" in the space for the taxpayer identification number
in Part 1, sign and date the Form, and give it to the requester. Generally, you
will then have 60 days to obtain a taxpayer identification number and furnish
it to the requester. If the requester does not receive your taxpayer
identification number within 60 days, backup withholding, if applicable, will
begin and will continue until you furnish your taxpayer identification number
to the requester.
Payees Exempt from Backup Withholding
Payees specifically exempted from backup withholding on ALL payments include
the following:
. A corporation.
. A financial institution.
. An organization exempt from tax under section 501(a), or an individual
retirement plan, or a custodial account under section 403(b)(7).
. The United States or any agency or instrumentality thereof.
. A State, the District of Columbia, a possession of the United States, or
any subdivision or instrumentality thereof.
. A foreign government, a political subdivision of a foreign government, or
any agency or instrumentality thereof.
. An international organization or any agency, or instrumentality thereof.
. A registered dealer in securities or commodities registered in the United
States or a possession of the United States.
. A real estate investment trust.
. A common trust fund operated by a bank under section 584(a).
. An exempt charitable remainder trust, or a non-exempt trust described in
section 4947(a)(1).
. An entity registered at all times during the tax year under the investment
Company Act of 1940.
. A foreign central bank of issue.
. Unless otherwise noted herein, all reference below to section numbers or to
regulations are references to the Internal Revenue Code and the regulations
promulgated thereunder.
Payments of dividends and patronage dividends not generally subject to backup
withholding include the following:
. Payments to nonresident aliens subject to withholding under section 1441.
. Payments to partnerships not engaged in a trade or business in the United
States and which have at least one nonresident partner.
. Payments of patronage dividends where the amount received is not paid in
money.
. Payments made by certain foreign organizations.
. Payments made to a nominee.
Payments of interest not generally subject to backup withholding include the
following:
. Payments of interest on obligations issued by individuals. NOTE: You may be
subject to backup withholding if (i) this interest is $600 or more, and
(ii) the interest is paid in the course of the payer's trade or business
and (iii) you have not provided your correct taxpayer identification number
to the payer.
. Payments of tax-exempt interest (including exempt-interest dividends under
section 852).
. Payments described in section 6049(b)(5) to nonresident aliens.
. Payments on tax-free covenant bonds under section 1451.
. Payments made by certain foreign organizations.
. Payments made to a nominee.
Exempt payees described above should file a Substitute Form W-9 to avoid
possible erroneous backup withholding. FILE THIS FORM WITH THE PAYER, FURNISH
YOUR TAXPAYER IDENTIFICATION NUMBER, WRITE "EXEMPT" ON THE FACE OF THE FORM,
AND RETURN IT TO THE PAYER.
Certain payments other than interest dividends, and patronage dividends, that
are not subject to information reporting are also not subject to backup
withholding. For details, see the regulations under sections 6041, 6041A(a),
6045, and 6050A.
Privacy Act Notices. Section 6109 requires most recipients of dividends,
interest, or other payments to give taxpayer identification numbers to payers
who must report the payments to the IRS. The IRS uses the numbers for
identification purposes and to help verify the accuracy of your tax return.
Payers must be given the numbers whether or not recipients are required to file
tax returns. Payers must generally withhold 31% of taxable interest, dividends,
and certain other payments to a payee who does not furnish a taxpayer
identification number to a payer. Certain penalties may also apply.
Penalties
(1) Penalty for Failure to Furnish Taxpayer Identification Number.--If you fail
to furnish your taxpayer identification number to a payer, you are subject to a
penalty of $50 for each such failure unless your failure is due to reasonable
cause and not to willful neglect.
(2) Failure to Report Certain Dividend and Interest Payments.--If you fail to
include any portion of an includible payment for interest, dividends, or
patronage dividends in gross income and such failure is due to negligence, a
penalty of 20% is imposed on any portion of an underpayment attributable to the
failure.
(3) Civil Penalty for False Information With Respect To Withholding.--If you
make a false statement with no reasonable basis which results in no imposition
of backup withholding, you are subject to a penalty of $500.
(4) Criminal Penalty for Falsifying Information.--If you falsify certifications
or affirmations, you are subject to criminal penalties including fines and/or
imprisonment.
FOR ADDITIONAL INFORMATION CONTACT YOUR TAX CONSULTANT OR THE INTERNAL REVENUE
SERVICE.
A-15
ANNEX B
NOTICE OF GUARANTEED DELIVERY
NOTICE OF GUARANTEED DELIVERY
Plains Exploration & Production Company
Plains E&P Company
Offer to Exchange
8 3/4% Series B Senior Subordinated Notes due 2012 for any and all
outstanding 8 3/4% Series A Senior Subordinated Notes due 2012
As set forth in the Prospectus dated , 2002 (as the same may be
amended from time to time, the "Prospectus"), of Plains Exploration &
Production Company and Plains E&P Company (together, the "Issuers") under the
caption of "The Exchange Offer--Procedures for Tendering Series A
Notes--Guaranteed Delivery," this form or one substantially equivalent hereto
must be used to accept the Issuers' offer (the "Exchange Offer") to exchange
their 83/4% Series B Senior Subordinated Notes due 2012 (the "Series B notes"),
which have been registered under the Securities Act of 1933, as amended (the
"Securities Act"), for an equal principal amount of their 8 3/4% Series A
Senior Subordinated Notes due 2012 (the "Series A notes"), if (i) certificates
representing the Series A notes to be exchanged are not lost but are not
immediately available, or (ii) time will not permit all required documents to
reach the Exchange Agent prior to the Expiration Date. This form may be
delivered by an eligible institution by mail or hand delivery or transmittal,
via facsimile, to the Exchange Agent at its address set forth below not later
than 5:00 p.m., New York City time, on . All capitalized terms used
herein but not defined herein shall have the meanings ascribed to them in the
Prospectus.
The Exchange Agent for the Exchange Offer is:
JPMorgan Chase Bank
By Mail: By Facsimile:
JPMorgan Chase Bank (713) 577-5200
600 Travis, Suite 1500 Attention: Rebecca Newman
Houston, Texas 77002
Attention: Rebecca Newman Confirm by Telephone:
(713) 216-4931
Attention: Rebecca Newman
Delivery or transmission via facsimile of this notice of guaranteed
delivery to an address other than as set forth above will not constitute a
valid delivery.
B-1
Ladies and Gentlemen:
The undersigned hereby tender(s) for exchange to the Issuers, upon the
terms and subject to the conditions set forth in the Prospectus and the Letter
of Transmittal, receipt of which is hereby acknowledged, the principal amount
of the Series A notes as set forth below pursuant to the guaranteed delivery
procedures set forth in the Prospectus under the caption of "The Exchange
Offer--Procedures for Tendering Series A Notes--Guaranteed Delivery."
The undersigned understands and acknowledges that the Exchange Offer will
expire at 5:00 p.m., New York City time, on , unless extended by the
Issuers. With respect to the Exchange Offer, "Expiration Date" means such time
and date, or if the Exchange Offer is extended, the latest time and date to
which the Exchange Offer is so extended by the Issuers.
All authority herein conferred or agreed to be conferred by the Notice of
Guaranteed Delivery shall survive the death or incapacity of the undersigned
and every obligation of the undersigned under this Notice of Guaranteed
Delivery shall be binding upon the heirs, personal representatives, executors,
administrators, successors and assigns, trustees in bankruptcy and other legal
representatives of the undersigned.
Name of Firm: _ _________________________
Address: ______ Name: ___________________
_______________ Title: __________________
Area Code and
Telephone No.: Date: ___________________
DO NOT SEND SERIES A NOTES WITH THIS FORM. ACTUAL SURRENDER OF SERIES A
NOTES MUST BE MADE PURSUANT TO, AND BE ACCOMPANIED BY, THE LETTER OF
TRANSMITTAL.
B-2
SIGNATURES Principal Amount of Series A Notes Exchanged:
_____________________________________ $ _______________________________________________
Signature of Owner
Certificate Nos. of Series A Notes (if available)
_____________________________________ _________________________________________________
Signature of Owner (if more than one) _________________________________________________
Dated: ________________________, 2002
Name(s): ____________________________
(Please Print)
Address: ____________________________
_____________________________________
_____________________________________
(Include Zip Code)
Area Code and
Telephone No.: ______________________
Capacity (full title),
if signing in a
representative capacity: ____________
Taxpayer Identification or
Social Security No.: ________________
B-3
GUARANTEE
(NOT TO BE USED FOR SIGNATURE GUARANTEE)
The undersigned, a member firm of a registered national securities exchange
or of the National Association of Securities Dealers, Inc. or a commercial bank
or trust company having an office or a correspondent in the United States, or
is otherwise an "eligible guaranteed institution" within the meaning of Rule
17Ad-15 under the Securities Exchange Act of 1934, as amended, hereby
guarantees that, within three New York Stock Exchange trading days from the
date of this Notice of Guaranteed Delivery, a properly completed and duly
executed Letter of Transmittal (or a facsimile thereof), together with
certificates representing the Series A notes tendered hereby in proper form for
transfer (or confirmation of the book-entry transfer of such Series A notes
into the account of JPMorgan Chase Bank (the "Trust Company") at a book-entry
transfer facility, pursuant to the Trust Company's account at a book-entry
transfer facility, pursuant to the procedure for book-entry transfer set forth
in the Prospectus under the caption "The Exchange Offer--Procedures for
Tendering Series A Notes--Book-Entry Delivery Procedures"), and any other
required documents will be deposited by the undersigned with the Trust Company.
Name of Firm: _ ______________
Address: ______ Name: ________
_______________ Title: _______
Area Code and
Telephone No.: Date: ________
DO NOT SEND SERIES A NOTES WITH THIS FORM. ACTUAL SURRENDER OF SERIES A
NOTES MUST BE MADE PURSUANT TO, AND BE ACCOMPANIED BY, THE LETTER OF
TRANSMITTAL.
B-4
Part II
INFORMATION NOT REQUIRED IN PROSPECTUS.
Item 20. Indemnification of Directors and Officers
The discussion below summarizes the material indemnification provisions of
our Certificate of Incorporation and Bylaws and Section 145 of the GCL.
Our Certificate of Incorporation provides that we must indemnify to the
full extent authorized or permitted by law any person made, or threatened to be
made, a party to any action, suit or proceeding (whether civil, criminal or
otherwise) by reason of fact that he, his testator or intestate, is or was one
of our directors or officers or by reason of the fact that such director or
officer, at our request, is or was serving any other corporation, partnership,
joint venture, trust, employee benefit plan or other enterprise, in any
capacity. The rights to indemnification set forth above are not exclusive of
any other rights to which such person may be entitled under any statute,
provision of our Certificate of Incorporation or bylaws, agreements, vote of
stockholders or disinterested directors or otherwise.
Additionally, our Bylaws provide for mandatory indemnification to at least
the extent specifically allowed by Section 145 of the Delaware General
Corporation Law (the "GCL"). Our Bylaws generally follow the language of
Section 145 of the GCL, but in addition specify that any director, officer,
employee or agent may apply to any court of competent jurisdiction in the State
of Delaware for indemnification to the extent otherwise permissible under the
Bylaws, notwithstanding any contrary determination denying indemnification made
by the Board, by independent legal counsel, or by the stockholders, and
notwithstanding the absence of any determination with respect to
indemnification. The Bylaws also specify certain circumstances in which a
finding is required that the person seeking indemnification acted in good
faith, for purposes of determining whether indemnification is available. Under
the Bylaws, a person shall be deemed to have acted in good faith and in a
manner he reasonably believed to be in or not opposed to our best interests,
or, with respect to any criminal action or proceeding, to have had no
reasonable cause to believe his conduct was unlawful, if his action is based on
our records or books of account or those of another enterprise, or on
information supplied to him by our officers or the officers of another
enterprise in the course of their duties, or on the advice of our legal counsel
or the legal counsel of another enterprise or on information or records given
or reports made to us or to another enterprise by an independent certified
public accountant or by an appraiser or other expert selected with reasonable
care by us or another enterprise.
Pursuant to Section 145 of the GCL, we generally have the power to
indemnify our current and former directors, officers, employees and agents
against expenses and liabilities that they incur in connection with any suit to
which they are, or are threatened to be made, a party by reason of their
serving in such positions so long as they acted in good faith and in a manner
they reasonably believed to be in, or not opposed to, our best interests, and
with respect to any criminal action, they had no reasonable cause to believe
their conduct was unlawful. With respect to suits by or in our right, however,
indemnification is generally limited to attorneys' fees and other expenses and
is not available if such person is adjudged to be liable to us unless the court
determines that indemnification is appropriate. The statute expressly provides
that the power to indemnify authorized thereby is not exclusive of any rights
granted under any bylaw, agreement, vote of stockholders or disinterested
directors, or otherwise. We also have the power to purchase and maintain
insurance for such persons.
Reference is also made to the Purchase Agreement contained in Exhibit 1.1
hereto, which provides for the indemnification of our officers and directors
against certain liabilities.
II-1
Item 21. Exhibits
(a) Exhibits
Exhibit
Number Description
- ------ -----------
1.1*** Purchase Agreement dated June 28, 2002 among Plains Exploration & Production
Company, Plains E&P Company, Arguello Inc., Plains Illinois Inc., Plains Resources
International Inc., PMCT Inc., and J.P. Morgan Securities Inc., Goldman Sachs & Co., Banc
One Capital Markets, Inc., BNP Paribas Securities Corp., Fleet Securities, Inc. and Fortis
Investment Services LLC.
3.1 Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company's
Amendment No. 2 to Form S-1 filed on October 3, 2002).
3.2 Bylaws (incorporated by reference to Exhibit 3.2 to the Company's Amendment No. 2 to
Form S-1 filed on October 3, 2002).
4.1 Indenture dated July 3, 2002 among Plains Exploration & Production Company, Plains E&P
Company, Arguello Inc., Plains Illinois Inc., Plains Resources International Inc., PMCT Inc.,
and J.P. Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.2 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
4.2 Form of 83/4% Senior Subordinated Note (incorporated by reference to Exhibit 4.3 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
4.3 Registration Rights Agreement dated July 3, 2002 by and among Plains Exploration &
Production Company, Plains E&P Company, Arguello Inc., Plains Illinois Inc. (incorporated
by reference to Exhibit 4.4 to the Company's Amendment No. 1 to
Form S-1 filed on August 28, 2002).
5.1*** Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of securities being
offered.
10.1 Master Separation Agreement dated July 3, 2002 between Plains Exploration & Production
Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.1 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.2 Plains Exploration and Production Company Transition Services Agreement dated July 3,
2002 between Plains Exploration & Production Company and Plains Resources Inc.
(incorporated by reference to Exhibit 10.2 to the Company's Amendment No. 1 Form S-1
filed on August 28, 2002).
10.3 Plains Resources Inc. Transition Services Agreement dated July 3, 2002 between Plains
Resources Inc. and Plains Exploration & Production Company (incorporated by reference to
Exhibit 10.3 to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.4 Second Amended and Restated Tax Allocation Agreement dated November 20, 2002
between Plains Exploration & Production Company and Plains Resources Inc.
(incorporated by reference to Exhibit 10.4 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.5 Technical Services Agreement dated July 3, 2002 between Plains Exploration & Production
Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.5 to the
Company's Amendment No.1 to Form S-1 filed on August 28, 2002).
10.6 Intellectual Property Agreement dated July 3, 2002 between Plains Exploration &
Production Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.6
to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.7 Employee Matters Agreement dated July 3, 2002 between Plains Exploration & Production
Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.7 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
II-2
Exhibit
Number Description
- ------ -----------
10.8 Purchase and Sale Agreement dated June 4, 1999, by and among Plains Resources Inc.,
Chevron U.S.A., Inc., and Chevron Pipe Line Company (incorporated by reference to
Exhibit 10.7 to the Company's Form S-1 filed on June 21, 2002).
10.9 Crude Oil Marketing Agreement dated as of November 23, 1998 among Plains Resources
Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains
Marketing (incorporated by reference to Exhibit 10.8 to the Company's Form S-1 filed on
June 21, 2002).
10.10 Letter Agreement dated as of October 23, 2001 by and between Plains Marketing and
Stocker Resources, L.P. (incorporated by reference to Exhibit 10.9 to the Company's Form
S-1 filed on June 21, 2002).
10.11 Credit Agreement dated July 3, 2002 among Plains Exploration & Production Company,
JPMorgan Chase Bank, as Administrative Agent, Bank One, NA (Main Office Chicago) and
Fleet National Bank, as Syndication Agents, BNPParibas and Fortis Capital Corp., as
Documentation Agents, and the Lenders party thereto (incorporated by reference to Exhibit
10.11 to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.12 First Amendment, effective as of July 19, 2002, to Credit Agreement dated as of July 3,
2002 among Plains Exploration & Production Company, as Borrower, JPMorgan Chase
Bank, as administrative agent, Bank One, NA and Fleet National Bank, as Syndication
Agents, BNP Paribas and Fortis Capital Corp., as Documentation Agents and the Lender
Party thereto (incorporated by reference to Exhibit 10.12 to the Company's Amendment No.
1 to Form S-1 filed on August 28, 2002).
10.13 Employment Agreement, dated as of September 19, 2002, between Plains Exploration &
Production Company and James C. Flores (incorporated by reference to Exhibit 10.13 to
the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.14 Employment Agreement, dated as of September 19, 2002, between Plains Exploration &
Production Company and John T. Raymond (incorporated by reference to Exhibit 10.14 to
the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.15 Employment Letter Agreement, dated as of August 20, 2002, between Plains Exploration &
Production Company and Stephen A. Thorington (incorporated by reference to Exhibit
10.15 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.16 Employment Letter Agreement, dated as of September 19, 2002, between Plains
Exploration & Production Company and Timothy T. Stephens (incorporated by reference to
Exhibit 10.16 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.17 Restricted Stock Agreement, dated as of September 25, 2002, between Plains Exploration
& Production Company and James C. Flores (incorporated by reference to Exhibit 10.17 to
the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.18 Restricted Stock Agreement, dated as of September 25, 2002, between Plains Exploration
& Production Company and John T. Raymond (incorporated by reference to Exhibit 10.18
to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.19 Stock Appreciation Rights Agreement, dated as of September 3, 2002, between Plains
Exploration & Production Company and Stephen A. Thorington (incorporated by reference
to Exhibit 10.19 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.20 Restricted Stock Agreement, dated as of September 25, 2002, between Plains Exploration
& Production Company and Timothy T. Stephens (incorporated by reference to Exhibit
10.20 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.21 Plains Exploration & Production Company 2002 Stock Incentive Plan (incorporated by
reference to Exhibit 10.21 to the Company's Amendment No. 2 to Form S-1 filed on
October 4, 2002).
10.22 Amendment No. 1 to Employee Matters Agreement, dated as of September 18, 2002,
between Plains Resources Inc. and Plains Exploration & Production Company
(incorporated by reference to Exhibit 10.22 to the Company's Amendment No. 2 to Form
S-1 filed on October 4, 2002).
II-3
Exhibit
Number Description
- ------ -----------
10.23 Omnibus Agreement dated as of November 17, 1998 among Plains Resources Inc., Plains
All American Pipeline, Plains Marketing, All American Pipeline, and Plains Holdings Inc.
(fka Plains All American Inc.) (incorporated by reference to Exhibit 10.23 to the Company's
Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.24 Amendment No. 1 to Master Separation Agreement, dated as of November 20, 2002,
between Plains Resources Inc. and Plains Exploration & Production Company
(incorporated by reference to Exhibit 10.24 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.25 Amendment No. 2 to Employee Matters Agreement, dated as of November 20, 2002,
between Plains Resources Inc. and Plains Exploration & Production Company
(incorporated by reference to Exhibit 10.25 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.26 Amendment No. 1 to Employment Agreement, dated as of November 20, 2002, between
Plains Exploration & Production Company and James C. Flores (incorporated by reference
to Exhibit 10.26 to the Company's Amendment No. 1 to Form 10 filed on November 21,
2002).
10.27 Amendment No. 1 to Employment Agreement, dated as of November 20, 2002, between
Plains Exploration & Production Company and John T. Raymond (incorporated by
reference to Exhibit 10.27 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.28 Amendment No. 1 to Employment Letter Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and Stephen A. Thorington
(incorporated by reference to Exhibit 10.28 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.29 Amendment No. 1 to Restricted Stock Award Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and James C. Flores (incorporated by
reference to Exhibit 10.29 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.30 Amendment No. 1 to Restricted Stock Award Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and John T. Raymond (incorporated by
reference to Exhibit 10.30 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.31 Amendment No. 1 to Stock Appreciation Rights Agreement, dated as of November 20,
2002, between Plains Exploration & Production Company and Stephen A. Thorington
(incorporated by reference to Exhibit 10.31 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.32 Amendment No. 1 to Restricted Stock Award Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and Timothy T. Stephens (incorporated
by reference to Exhibit 10.32 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.33 Plains Exploration & Production Company 2002 Transition Stock Incentive Plan
(incorporated by reference to Exhibit 10.33 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.34 Plains Exploration & Production Company 2002 Rollover Stock Plan (incorporated by
reference to Exhibit 10.34 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
12.1* Calculation of Earnings to Fixed Charges.
II-4
Exhibit
Number Description
- ------ -----------
21.1 Subsidiaries of Plains Exploration & Production Company (incorporated by reference to
Exhibit 21.1 to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
23.1*** Consent of Akin Gump Strauss Hauer & Feld LLP (included in its opinion filed as Exhibit 5.1
hereto).
23.2* Consent of PriceWaterhouseCoopers LLP.
23.3* Consent of Netherland, Sewell & Associates, Inc.
23.4* Consent of Ryder Scott Company.
23.5* Consent of H.J. Gruy & Associates, Inc.
24.1*** Power of attorney (included on signature page).
25.1*** Form T-1 Statement of Eligibility under the Trust Indenture Act of 1939 of JPMorgan Chase
Bank.
- --------
* Filed herewith.
*** Previously filed.
(b) Financial Statement Schedules
No financial statement schedules are included herein. All other schedules
for which provision is made in the applicable accounting regulation of the
Commission are not required under the related instructions, are inapplicable,
or the information is included in the consolidated financial statements, and
have therefore been omitted.
(c) Reports, Opinions, and Appraisals
None.
II-5
Item 22. Undertakings
(a) Regulation S-K, Item 512 Undertakings
(1) The undersigned registrant hereby undertakes:
(i) To file, during any period in which offers or sales are being
made, a post-effective amendment to this registration statement:
(a) To include any prospectus required by Section 10(a)(3) of
the Securities Act of 1933;
(b) 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.
Notwithstanding the foregoing, any increase or decrease in volume
of securities offered (if the total dollar value of securities
offered would not exceed that which was registered) and any
deviation from the low or high end of the estimated maximum
offering range may be reflected in the form of prospectus filed
with the Commission pursuant to Rule 424(b) if, in the aggregate,
the changes in volume and price represent no more than a 20%
change in the maximum offering price set forth in the "Calculation
of Registration Fee" table in the effective registration statement.
(c) 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;
(ii) 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 that time shall
be deemed to be the initial bona fide offering thereof.
(iii) 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.
(2) Registration on Form S-4 of Securities Offered for Resale
(i) The undersigned hereby undertakes as follows: that prior to any
public reoffering of the securities registered hereunder through the use of
a prospectus which is a part of this registration statement, by any person
or party who is deemed to be an underwriter within the meaning of Rule
145(c), the issuer undertakes that such reoffering prospectus will contain
the information called for by the applicable registration form with respect
to reofferings by persons who may be deemed underwriters, in addition to
the information called for by the other items of the applicable form.
(ii) The registrant undertakes that every prospectus: (a) that is filed
pursuant to the paragraph immediately preceding, or (b) that purports to
meet the requirements of section 10(s)(3) of the Act and is used in
connection with an offering of securities subject to Rule 415, will be
filed as a part of an amendment to the registration statement and will not
be used until such
II-6
amendment is effective, and that, for purposes 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 that time shall be
deemed to be the initial bona fide offering thereof.
(3) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is 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 to 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.
(4) The undersigned registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Item 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.
(5) The undersigned 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.
II-7
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, each registrant
has duly caused this registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston, State of Texas,
on November 22, 2002.
PLAINS EXPLORATION & PRODUCTION
COMPANY
By: /s/ JOHN T. RAYMOND
-----------------------------
John T. Raymond
President and Chief Operating
Officer
PLAINS E&P COMPANY
By: /s/ STEPHEN A. THORINGTON
-----------------------------
Stephen A. Thorington
Vice President and Chief
Financial Officer
ARGUELLO INC.
By: /s/ JOHN T. RAYMOND
-----------------------------
John T. Raymond
President
PLAINS ILLINOIS INC.
By: /s/ JOHN T. RAYMOND
-----------------------------
John T. Raymond
President
PLAINS RESOURCES INTERNATIONAL
INC.
By: /s/ JOHN T. RAYMOND
-----------------------------
John T. Raymond
President
PMCT INC.
By: /s/ JOHN T. RAYMOND
-----------------------------
John T. Raymond
President
II-8
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed below by the following persons in the
capacities indicated on November 22, 2002.
Signature Title
--------- -----
* Chairman of the Board and Chief Executive
--------------------- Officer of Plains Exploration & Production
James C. Flores Company (Principal Executive Officer)
President and Director of Plains E&P Company
(Principal Executive Officer)
Director of PMCT Inc.
* President and Director of Arguello Inc., Plains
--------------------- Illinois Inc. and Plains Resources International
John T. Raymond Inc. (Principal Executive Officer)
President of PMCT Inc. (Principal Executive
Officer)
* Executive Vice President and Chief Financial
--------------------- Officer of Plains Exploration & Production
Stephen A. Thorington Company (Principal Financial Officer)
Vice President, Chief Financial Officer and
Director of Plains E&P Company (Principal
Financial and Accounting Officer)
Vice President and Treasurer of Arguello Inc.
and Plains Illinois Inc. (Principal Financial and
Accounting Officer)
Vice President, Treasurer and Director of Plains
Resources International Inc. and PMCT Inc.
(Principal Financial and Accounting Officer)
* Senior Vice President--Accounting and
--------------------- Treasurer of Plains Exploration & Production
Cynthia A. Feeback Company (Principal Accounting Officer)
* Director of Plains E&P Company, Arguello Inc.,
--------------------- Plains Illinois Inc., Plains Resources
Timothy T. Stephens International Inc. and PMCT Inc.
* Director of Plains Exploration & Production
--------------------- Company
Jerry L. Dees
* Director of Plains Exploration & Production
--------------------- Company
Tom H. Delimitros
* Director of Plains Exploration & Production
--------------------- Company
John H. Lollar
*By: /s/ JOHN T. RAYMOND
-------------------------
John T. Raymond
Attorney-in-Fact
II-9
EXHIBIT INDEX
Exhibit
Number Description
- ------ -----------
1.1*** Purchase Agreement dated June 28, 2002 among Plains Exploration & Production
Company, Plains E&P Company, Arguello Inc., Plains Illinois Inc., Plains Resources
International Inc., PMCT Inc., and J.P. Morgan Securities Inc., Goldman Sachs & Co., Banc
One Capital Markets, Inc., BNP Paribas Securities Corp., Fleet Securities, Inc. and Fortis
Investment Services LLC.
3.1 Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company's
Amendment No. 2 to Form S-1 filed on October 3, 2002).
3.2 Bylaws (incorporated by reference to Exhibit 3.2 to the Company's Amendment No. 2 to
Form S-1 filed on October 3, 2002).
4.1 Indenture dated July 3, 2002 among Plains Exploration & Production Company, Plains E&P
Company, Arguello Inc., Plains Illinois Inc., Plains Resources International Inc., PMCT Inc.,
and J.P. Morgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.2 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
4.2 Form of 83/4% Senior Subordinated Note (incorporated by reference to Exhibit 4.3 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
4.3 Registration Rights Agreement dated July 3, 2002 by and among Plains Exploration &
Production Company, Plains E&P Company, Arguello Inc., Plains Illinois Inc. (incorporated
by reference to Exhibit 4.4 to the Company's Amendment No. 1 to
Form S-1 filed on August 28, 2002).
5.1*** Opinion of Akin Gump Strauss Hauer & Feld LLP as to the legality of securities being
offered.
10.1 Master Separation Agreement dated July 3, 2002 between Plains Exploration & Production
Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.1 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.2 Plains Exploration and Production Company Transition Services Agreement dated July 3,
2002 between Plains Exploration & Production Company and Plains Resources Inc.
(incorporated by reference to Exhibit 10.2 to the Company's Amendment No. 1 Form S-1
filed on August 28, 2002).
10.3 Plains Resources Inc. Transition Services Agreement dated July 3, 2002 between Plains
Resources Inc. and Plains Exploration & Production Company (incorporated by reference to
Exhibit 10.3 to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.4 Second Amended and Restated Tax Allocation Agreement dated November 20, 2002
between Plains Exploration & Production Company and Plains Resources Inc.
(incorporated by reference to Exhibit 10.4 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.5 Technical Services Agreement dated July 3, 2002 between Plains Exploration & Production
Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.5 to the
Company's Amendment No.1 to Form S-1 filed on August 28, 2002).
10.6 Intellectual Property Agreement dated July 3, 2002 between Plains Exploration &
Production Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.6
to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.7 Employee Matters Agreement dated July 3, 2002 between Plains Exploration & Production
Company and Plains Resources Inc. (incorporated by reference to Exhibit 10.7 to the
Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.8 Purchase and Sale Agreement dated June 4, 1999, by and among Plains Resources Inc.,
Chevron U.S.A., Inc., and Chevron Pipe Line Company (incorporated by reference to
Exhibit 10.7 to the Company's Form S-1 filed on June 21, 2002).
Exhibit
Number Description
- ------ -----------
10.9 Crude Oil Marketing Agreement dated as of November 23, 1998 among Plains Resources
Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains
Marketing (incorporated by reference to Exhibit 10.8 to the Company's Form S-1 filed on
June 21, 2002).
10.10 Letter Agreement dated as of October 23, 2001 by and between Plains Marketing and
Stocker Resources, L.P. (incorporated by reference to Exhibit 10.9 to the Company's Form
S-1 filed on June 21, 2002).
10.11 Credit Agreement dated July 3, 2002 among Plains Exploration & Production Company,
JPMorgan Chase Bank, as Administrative Agent, Bank One, NA (Main Office Chicago) and
Fleet National Bank, as Syndication Agents, BNPParibas and Fortis Capital Corp., as
Documentation Agents, and the Lenders party thereto (incorporated by reference to Exhibit
10.11 to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
10.12 First Amendment, effective as of July 19, 2002, to Credit Agreement dated as of July 3,
2002 among Plains Exploration & Production Company, as Borrower, JPMorgan Chase
Bank, as administrative agent, Bank One, NA and Fleet National Bank, as Syndication
Agents, BNP Paribas and Fortis Capital Corp., as Documentation Agents and the Lender
Party thereto (incorporated by reference to Exhibit 10.12 to the Company's Amendment No.
1 to Form S-1 filed on August 28, 2002).
10.13 Employment Agreement, dated as of September 19, 2002, between Plains Exploration &
Production Company and James C. Flores (incorporated by reference to Exhibit 10.13 to
the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.14 Employment Agreement, dated as of September 19, 2002, between Plains Exploration &
Production Company and John T. Raymond (incorporated by reference to Exhibit 10.14 to
the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.15 Employment Letter Agreement, dated as of August 20, 2002, between Plains Exploration &
Production Company and Stephen A. Thorington (incorporated by reference to Exhibit
10.15 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.16 Employment Letter Agreement, dated as of September 19, 2002, between Plains
Exploration & Production Company and Timothy T. Stephens (incorporated by reference to
Exhibit 10.16 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.17 Restricted Stock Agreement, dated as of September 25, 2002, between Plains Exploration
& Production Company and James C. Flores (incorporated by reference to Exhibit 10.17 to
the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.18 Restricted Stock Agreement, dated as of September 25, 2002, between Plains Exploration
& Production Company and John T. Raymond (incorporated by reference to Exhibit 10.18
to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.19 Stock Appreciation Rights Agreement, dated as of September 3, 2002, between Plains
Exploration & Production Company and Stephen A. Thorington (incorporated by reference
to Exhibit 10.19 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.20 Restricted Stock Agreement, dated as of September 25, 2002, between Plains Exploration
& Production Company and Timothy T. Stephens (incorporated by reference to Exhibit
10.20 to the Company's Amendment No. 2 to Form S-1 filed on October 4, 2002).
10.21 Plains Exploration & Production Company 2002 Stock Incentive Plan (incorporated by
reference to Exhibit 10.21 to the Company's Amendment No. 2 to Form S-1 filed on
October 4, 2002).
10.22 Amendment No. 1 to Employee Matters Agreement, dated as of September 18, 2002,
between Plains Resources Inc. and Plains Exploration & Production Company
(incorporated by reference to Exhibit 10.22 to the Company's Amendment No. 2 to Form
S-1 filed on October 4, 2002).
10.23 Omnibus Agreement dated as of November 17, 1998 among Plains Resources Inc., Plains
All American Pipeline, Plains Marketing, All American Pipeline, and Plains Holdings Inc.
(fka Plains All American Inc.) (incorporated by reference to Exhibit 10.23 to the Company's
Amendment No. 2 to Form S-1 filed on October 4, 2002).
Exhibit
Number Description
- ------ -----------
10.24 Amendment No. 1 to Master Separation Agreement, dated as of November 20, 2002,
between Plains Resources Inc. and Plains Exploration & Production Company
(incorporated by reference to Exhibit 10.24 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.25 Amendment No. 2 to Employee Matters Agreement, dated as of November 20, 2002,
between Plains Resources Inc. and Plains Exploration & Production Company
(incorporated by reference to Exhibit 10.25 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.26 Amendment No. 1 to Employment Agreement, dated as of November 20, 2002, between
Plains Exploration & Production Company and James C. Flores (incorporated by reference
to Exhibit 10.26 to the Company's Amendment No. 1 to Form 10 filed on November 21,
2002).
10.27 Amendment No. 1 to Employment Agreement, dated as of November 20, 2002, between
Plains Exploration & Production Company and John T. Raymond (incorporated by
reference to Exhibit 10.27 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.28 Amendment No. 1 to Employment Letter Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and Stephen A. Thorington
(incorporated by reference to Exhibit 10.28 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.29 Amendment No. 1 to Restricted Stock Award Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and James C. Flores (incorporated by
reference to Exhibit 10.29 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.30 Amendment No. 1 to Restricted Stock Award Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and John T. Raymond (incorporated by
reference to Exhibit 10.30 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.31 Amendment No. 1 to Stock Appreciation Rights Agreement, dated as of November 20,
2002, between Plains Exploration & Production Company and Stephen A. Thorington
(incorporated by reference to Exhibit 10.31 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.32 Amendment No. 1 to Restricted Stock Award Agreement, dated as of November 20, 2002,
between Plains Exploration & Production Company and Timothy T. Stephens (incorporated
by reference to Exhibit 10.32 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
10.33 Plains Exploration & Production Company 2002 Transition Stock Incentive Plan
(incorporated by reference to Exhibit 10.33 to the Company's Amendment No. 1 to Form 10
filed on November 21, 2002).
10.34 Plains Exploration & Production Company 2002 Rollover Stock Plan (incorporated by
reference to Exhibit 10.34 to the Company's Amendment No. 1 to Form 10 filed on
November 21, 2002).
12.1* Calculation of Earnings to Fixed Charges.
21.1 Subsidiaries of Plains Exploration & Production Company (incorporated by reference to
Exhibit 21.1 to the Company's Amendment No. 1 to Form S-1 filed on August 28, 2002).
23.1*** Consent of Akin Gump Strauss Hauer & Feld LLP (included in its opinion filed as Exhibit 5.1
hereto).
Exhibit
Number Description
- ------ -----------
23.2* Consent of PriceWaterhouseCoopers LLP.
23.3* Consent of Netherland, Sewell & Associates, Inc.
23.4* Consent of Ryder Scott Company.
23.5* Consent of H.J. Gruy & Associates, Inc.
24.1*** Power of attorney (included on signature page).
25.1*** Form T-1 Statement of Eligibility under the Trust Indenture Act of 1939 of JPMorgan Chase
Bank.
- --------
* Filed herewith.
*** Previously filed.