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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2001
OR
[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number: 0-9808
PLAINS RESOURCES INC.
(Exact name of registrant as specified in its charter)
Delaware 13-2898764
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 Dallas Street, Suite 700
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 739-6700
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, par value $0.10 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: none
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [_]
On February 28, 2002, there were 23,649,537 shares of the registrant's
Common Stock outstanding. The aggregate value of the Common Stock held by non-
affiliates of the registrant (treating all executive officers and directors of
the registrant, for this purpose, as if they may be affiliates of the
registrant) was approximately $498,176,000 on February 28, 2002 (based on
$22.50 per share, the last sale price of the Common Stock as reported on the
New York Stock Exchange on such date).
DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III
of the Annual Report on Form 10-K is incorporated by reference to the
registrant's definitive proxy statement to be filed pursuant to Regulation 14A
for the registrant's 2002 Annual Meeting of Stockholders.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [_]
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PLAINS RESOURCES INC.
2001 FORM 10-K ANNUAL REPORT
Table of Contents
Page
----
Part I
Items 1 & 2. Business and Properties................................... 2
Item 3. Legal Proceedings......................................... 22
Item 4. Submission of Matters to a Vote of Security Holders....... 23
Part II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters...................................... 25
Item 6. Selected Financial Data................................... 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 28
Item 7A. Quantitative and Qualitative Disclosures About Market
Risks.................................................... 40
Item 8. Financial Statements and Supplementary Data............... 43
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...................... 43
Part III
Item 10. Directors and Executive Officers.......................... 44
Item 11. Executive Compensation.................................... 44
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................... 44
Item 13. Certain Relationships and Related Transactions............ 44
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K................................................. 45
i
FORWARD-LOOKING STATEMENTS
All statements, other than statements of historical fact, included in this
Annual Report on Form 10-K are forward-looking statements, including, but not
limited to, statements identified by the words "anticipate," "believe,"
"estimate," "expect," "plan," "intend" and "forecast" and similar expressions
and statements regarding our business strategy, plans and objectives of our
management for future operations. These statements reflect our current views
with respect to future events, based on what we believe are reasonable
assumptions. These statements, however, are subject to certain risks,
uncertainties and assumptions, including, but not limited to:
. uncertainties inherent in the exploration for and development and
production of oil and gas and in estimating reserves;
. unexpected future capital expenditures (including the amount and nature
thereof);
. impact of crude oil and natural 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 indemnity or
insurance, and
. general economic, market or business conditions.
If one or more of these risks or uncertainties materialize, or if any of
our underlying assumptions prove incorrect, our actual results may vary
materially from those in the forward-looking statements. Except as required by
applicable securities laws, we do not intend to update these forward-looking
statements and information. See Item 7.--"Management's Discussion and Analysis
of Financial Condition and Results of Operations--Critical Accounting Policies
and Factors That May Affect Future Results" for an additional discussion of
these risks and uncertainties.
CERTAIN DEFINITIONS
As used herein, the following terms have specific meanings as set forth
below:
Oil crude oil, condensate and natural gas liquids
Gas natural gas
Bbl barrel
MBbl thousand barrels
MMBbl million barrels
B/d barrels per day
Mcf thousand cubic feet
MMcf million cubic feet
Bcf billion cubic feet
MMBtu million British thermal units
BOE barrel of oil equivalent, with gas volumes
converted to oil barrels at a ratio of 6.0 Mcf
of gas to 1.0 barrel of oil
MBOE thousand barrels of oil equivalent
MMBOE million barrels of oil equivalent
NYMEX New York Mercantile Exchange
1
Upstream the portion of the oil and gas business that
acquires, exploits, develops, explores for
and produces oil and gas
Midstream the portion of the oil and gas business that
markets, gathers, transports and stores oil
Proved Reserve Additions the sum of additions from extensions,
discoveries, improved recovery, acquisitions
and revisions of previous estimates
Reserve Replacement Cost cost per BOE of reserves added during a
period calculated by using a fraction, of
which the numerator is equal to the costs
incurred for property acquisition,
exploration, exploitation and development
and of which the denominator is equal to
proved reserve additions
Reserve Replacement Ratio proved reserve additions for the period
divided by production for the period
Working Interest a cost-bearing interest under an oil and gas
lease that gives the holder the right to
develop and produce minerals under the lease
Net Revenue Interest the lessee's share of production after
satisfaction of all royalty and other non
cost-bearing interests
Gross Acre an acre of land in which an interest is owned
Net Acres the sum of the fractional working interests
owned in gross acres
Gross Oil and Gas Well a well in which an interest is owned
Net Oil and Gas Well obtained by multiplying the gross oil and gas
well by the working interest owned in the
applicable property
Present Value of Proved Reserves the pre-tax present value (discounted at 10%)
of estimated future cash inflows from proved
oil and gas reserves reduced by estimated
future operating expenses, development
expenditures and abandonment costs (net of
salvage value) associated therewith
Standardized Measure the present value of proved reserves reduced
by the present value (discounted at 10%) of
estimated future income taxes
References herein to "Plains Resources", "Plains", the "Company", "we",
"us" and "our" mean Plains Resources Inc.
PART I
Items 1 and 2. BUSINESS and PROPERTIES.
General
We are an independent energy company primarily engaged in the "upstream"
activities of acquiring, exploiting, developing, exploring for and producing
crude oil and natural gas in the United States. In addition, through our
ownership in Plains All American Pipeline, L.P., or PAA, we have interests in
the "midstream" activities of marketing, gathering, transporting, terminalling
and storing crude oil. See "--Plains All American Pipeline, L.P.".
Our core areas of operations are in (i) the Los Angeles Basin, the Arroyo
Grande field and the Mt. Poso field onshore California; (ii) the Point
Arguello field offshore California; (iii) the Illinois Basin in southern
Illinois; and (iv) the Sunniland Trend in south Florida. Our acquisition and
exploitation efforts are concentrated on mature but underdeveloped crude oil
producing properties that meet our targeted criteria. Generally, the
properties that we consider acquiring and exploiting consist of entire fields
where major integrated or large independent oil and natural gas companies own
100% or the
2
controlling interest. Typically these fields have produced significant volumes
since initial discovery, exhibit complex reservoir and geologic conditions
and, as a result thereof, are likely to have significant estimated remaining
reserves in place. Our management believes that it has developed a proven
record in acquiring and exploiting underdeveloped crude oil properties where
we can make substantial reserve additions and cash flow increases by
implementing improved production practices and recovery techniques and by
relatively low risk development drilling. An integral component of our
exploitation effort is to increase unit operating margins, and therefore cash
flow, by reducing unit production expenses and increasing wellhead price
realizations.
We seek to complement these efforts by committing a minor portion of our
capital to pursue higher risk exploration opportunities that offer potentially
higher rewards in areas synergistic to our acquisition and exploitation
activities. As part of our business strategy, we periodically evaluate
selling, and from time to time have sold, certain of our mature producing
properties that we consider to be non-strategic or fully valued. These sales
enable us to focus on our core properties, maintain our financial flexibility,
control our overhead and re-deploy the sales proceeds to activities that have
potentially higher financial returns.
At December 31, 2001 proved oil and gas reserves totaled 256.7 MMBOE,
comprised of 240.6 MMBbls of oil and 96.2 Bcf of gas. In 2001 we drilled 169
development wells, 168 of which were successful. In 2001 aggregate
acquisition, exploitation, development, and exploration expenditures totaled
$136.5 million, resulting in proved reserve additions of approximately 27.8
MMBOE, at a reserve replacement cost of $4.92 per BOE. During 2001
approximately 98% of our expenditures were on exploitation and development
activities.
During the five-year period ended December 31, 2001, we incurred aggregate
acquisition, exploitation, development, and exploration costs of approximately
$518.7 million, resulting in proved reserve additions of 177.7 MMBOE, at a
reserve replacement cost of $2.92 per BOE. During this period approximately
98% of our expenditures were on acquisitions, exploitation and development
activities.
To manage our exposure to commodity price risk, we routinely hedge a
portion of our crude oil production. For 2002 and 2003, we have entered into
various arrangements, using a combination of swaps and purchased puts and
calls. We intend to continue maintaining hedging arrangements for a
significant portion of our production. See Item 7A. -- "Quantitative and
Qualitative Disclosures about Market Risks".
Plains All American Pipeline, L.P.
PAA is a publicly-traded master limited partnership that is engaged in the
marketing, transportation and terminalling of crude oil and marketing
liquefied petroleum gas. Terminals are facilities where crude oil is
transferred to or from storage or a transportation system, such as a pipeline,
to another transportation system, such as trucks or another pipeline. The
operation of these facilities is called "terminalling". PAA is the exclusive
purchaser/marketer of all of our equity crude oil production.
The principal business of PAA consists of: gathering crude oil from the
fields where the crude oil is produced; interstate and intrastate
transportation of crude oil through pipelines, trucks or barges; storing crude
oil in storage tanks; transferring crude oil from pipelines and storage tanks
to trucks, barges or other pipelines through terminals; the purchase of crude
oil at the well and the bulk purchase of crude oil at pipeline and terminal
facilities; and the subsequent resale or exchange of crude oil at various
points along the crude oil distribution chain.
PAA owns and operates over 3,000 miles of gathering and mainline crude oil
pipelines located throughout the United States and Canada. In connection with
its terminalling and storage activities,
3
PAA owns and operates approximately 11.5 million barrels of above-ground crude
oil terminalling and storage facilities, including a 3.1 million barrel crude
oil terminalling and storage facility in Cushing, Oklahoma, the largest crude
oil trading hub in the United States and the designated delivery point for the
NYMEX. PAA recently announced plans to expand the Cushing facility by 2.2
million barrels, with 1.1 million barrels of the expansion expected to be
completed in mid-2002 and 1.1 million barrels expected to be completed in late
2002 or early 2003. PAA's operations are concentrated in Texas, Oklahoma,
California and Louisiana and in the Canadian provinces of Alberta,
Saskatchewan and Manitoba.
Our June 2001 Strategic Restructuring
On June 8, 2001, we sold a portion of our interests in PAA to a group of
investors and management of PAA for approximately $155.2 million. The assets
we sold in this restructuring included 52%, or approximately 5.2 million, of
the subordinated units of PAA, at $22 per unit, and an aggregate 54% ownership
interest in the general partner of PAA. We received approximately $110 million
in cash and 23,108 shares of our series F preferred stock value at $45.2
million as consideration for the sale. We recognized a pre-tax gain of $128.3
million in connection with this sale. In connection with our strategic
restructuring, the holders of the remaining shares of our series F preferred
stock converted their shares into 2.2 million shares of our common stock and
received from us a cash payment of approximately $2.5 million, equal to, with
respect to each share of our series F preferred stock converted, the accrued
dividends on each share from June 8, 2001 until the first date on which we
could cause conversion of the shares, plus a 20% premium on the amount of the
accrued dividends. Also, in connection with our strategic restructuring,
holders of our series H preferred stock converted an aggregate of 132,022
shares into approximately 4.4 million shares of our common stock. We also
granted management of PAA an option to acquire an additional 2% ownership
interest in the general partner of PAA, which PAA management exercised in
September 2001 by paying us $1.5 million in cash and notes. As a result of
this exercise we recognized a gain of $1.1 million.
As a result of our strategic restructuring, all of our series F preferred
stock and all but approximately 36,000 shares of our series H preferred stock
were retired or converted. The remaining outstanding shares of our series H
preferred stock were converted into 1.2 million shares of our common stock
during the third quarter of 2001.
The excess of the fair value of our Series F preferred stock redeemed as
consideration over the carrying value of such series F preferred stock ($21.4
million) is deemed to be a dividend to our preferred stockholders. As a
result, for purposes of determining our basic and diluted earnings per share,
we deducted this amount in determining our income available to our common
stockholders.
In exchange for the significant value we received for the subordinated
units (which are subordinated in right to distributions from PAA and are not
publicly traded) relative to the then current market price of the publicly
traded common units, we entered into a value assurance agreement with each of
the purchasers of the subordinated units. The value assurance agreements
require us to pay to the holders an amount per fiscal year, payable on a
quarterly basis, equal to the difference between $1.85 per unit and the actual
amount distributed during that period. The value assurance agreements will
expire upon the earlier of the conversion of the subordinated units to common
units, or June 8, 2006.
Also in connection with our strategic restructuring:
. we appointed James C. Flores as our Chairman of the Board and Chief
Executive Officer and we appointed a new Chief Operating Officer, Chief
Financial Officer, and General Counsel and Secretary;
. certain of our employees received transaction-related bonuses and other
payments and vested in benefits in accordance with the terms of our
employee benefit plans;
4
. we entered into a separation agreement with PAA whereby, among other
things, (1) we agreed to indemnify PAA, its general partner, and its
subsidiaries against (a) any claims related to the upstream business,
whenever arising, and (b) any claims related to federal or state
securities laws or the regulations of any self-regulatory authority, or
other similar claims, resulting from alleged acts or omissions by us,
our subsidiaries, PAA, or PAA's subsidiaries occurring on or before June
8, 2001, and (2) PAA agreed to indemnify us and our subsidiaries against
any claims related to the midstream business, whenever arising;
. we entered into a pension and employee benefits assumption and
transition agreement pursuant to which we and the general partner of PAA
agreed to the transition of certain employees to the general partner,
our provision of certain benefits with respect to the transfer, and our
provision of transition-related services;
. with respect to certain of our employees who transferred to the general
partner of PAA and who held in-the-money but unvested stock options to
acquire our common stock, which were subject to forfeiture due to the
transfer of employment, we agreed to substitute for the unvested options
a total contingent grant of 51,000 subordinated units with a value equal
to the discounted present value of the spread on the unvested options,
to vest on the same vesting schedule as the options, as a result of
which we recognized $0.5 million in noncash compensation expense; and
. we agreed to contribute 287,500 subordinated units to the general
partner of PAA to be used for performance option grants to officers and
key employees of the general partner.
As a result of our reduced ownership of PAA and our inability to control
PAA's operations, our minority interest in PAA is accounted for using the
equity method of accounting effective January 1, 2001. Under this method, we
no longer consolidate the assets, liabilities and operating activities of PAA.
Rather, we record our proportionate share of PAA's net assets and results of
operations.
As of December 31, 2001, our aggregate ownership interest in PAA was
approximately 29%, which was comprised of (1) a 44% interest in the general
partner of PAA, (2) 45%, or approximately 4.5 million, of the subordinated
units and (3) 24%, or approximately 7.9 million, of the common units,
including approximately 1.3 million class B common units.
Based on PAA's current annual distribution rate of $2.05 per unit, we would
receive an annual distribution from PAA of approximately $27.6 million,
including $1.0 million for our 44% of the general partner incentive
distribution. The general partner of PAA is entitled to receive incentive
distributions if the amount PAA distributes with respect to any quarter
exceeds levels specified in PAA's partnership agreement. Under the quarterly
incentive distribution provisions, generally the general partner is entitled
to 15% of distributions in excess of $0.45 per unit, 25% of distributions in
excess or $0.495 per unit and 50% of distributions in excess of $0.675 per
unit. Based on the current $2.05 annual distribution level ($0.5125 quarterly)
and the current units outstanding, the general partner's incentive
distribution is forecast to be approximately $2.2 million, of which we would
receive 44%.
Unauthorized Trading Losses
In November 1999, we discovered that a former employee of PAA had engaged
in unauthorized trading activity, resulting in a loss of approximately $174.0
million, which includes associated costs and legal expenses. A full
investigation into the unauthorized trading activities by outside legal
counsel and independent accountants and consultants determined that the vast
majority of the losses occurred from March through November 1999, and the
impact warranted a restatement of previously reported financial information
for 1999 and 1998. Approximately $7.1 million of the unauthorized trading
losses was recognized in 1998 and the remainder in 1999. In 2000, we
recognized an additional $8.0 million charge for litigation related to the
unauthorized trading losses.
5
The unauthorized trading and associated losses resulted in a default of
certain covenants under PAA's then-existing credit facilities and significant
short-term cash and letter of credit requirements. In December 1999, PAA
executed amended credit facilities and obtained default waivers from all of
its lenders. PAA paid approximately $13.7 million to its lenders in connection
with the amended credit facilities. In connection with the amendments, we
loaned approximately $114.0 million to PAA. We financed the $114.0 million
that we loaned PAA with: the issuance of a new series of our Series F
preferred stock for proceeds of $50.0 million; cash distributions of
approximately $9.0 million received from PAA in November 1999; and $55.0
million of borrowings under our revolving credit facility. In May 2000, PAA
entered into new bank credit agreements to refinance their existing bank debt
and repay the $114.0 million owed to us.
After the public announcement of the trading losses, class actions were
filed against us and PAA. Derivative lawsuits have also been filed in the
United States District Court of the Southern District of Texas and the
Delaware Chancery Court, Newcastle County. Agreements have been reached to
settle all of the class actions and the Delaware and Texas derivative actions.
The securities class actions settlement and the Delaware derivative action
settlement have been approved by the courts. The Texas derivative action
settlement, which does not contemplate any cash payment by us, is pending
court approval. See Item 3.--"Legal Proceedings".
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
Securities and Exchange Commission, or SEC, which requires the application of
year-end prices for each year, held constant throughout the projected reserve
life.
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......... 223,162 93,486 218,922 90,873 120,208 86,781
Revision of previous
estimates................ (15,457) (5,485) (9,834) (3,597) 62,895 (8,234)
Extensions, discoveries,
improved recovery and
other additions.......... 42,210 11,571 22,429 9,252 37,393 15,488
Sale of reserves in-
place.................... -- -- -- -- -- --
Purchase of reserves in-
place.................... -- -- -- -- 6,442 --
Production................ (9,279) (3,355) (8,355) (3,042) (8,016) (3,162)
------- ------ ------- ------ ------- ------
Ending balance............ 240,636 96,217 223,162 93,486 218,922 90,873
======= ====== ======= ====== ======= ======
Proved Developed Reserves
Beginning balance......... 123,532 52,184 120,141 49,255 73,264 58,445
======= ====== ======= ====== ======= ======
Ending balance............ 134,704 59,101 123,532 52,184 120,141 49,255
======= ====== ======= ====== ======= ======
6
The following table sets forth the Present Value of Proved Reserves at
December 31, 2001, 2000 and 1999.
2001 2000 1999
-------- ---------- ----------
(in thousands)
Proved developed.............................. $475,219 $1,020,023 $ 721,151
Proved undeveloped............................ 194,545 325,369 524,898
-------- ---------- ----------
Total Proved.................................. $669,764 $1,345,392 $1,246,049
======== ========== ==========
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.
Reservoir engineering is a subjective process of estimating the 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 Present Value of Proved
Reserves shown above 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. The information set forth in the preceding
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. See Item 7.--"Management's Discussion and Analysis of
Financial Condition and Results of Operations--Critical Accounting Policies
and Factors That May Affect Future Results".
In accordance with the SEC guidelines, the reserve engineers' estimates of
future net revenues from our 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. The crude oil price in effect
at December 31, 2001 is based on the year-end crude oil price with variations
based on location and quality of crude oil. The overall average prices used in
the reserve reports as of December 31, 2001 were $14.91 per barrel of oil and
$2.56 per Mcf of gas. See "Product Markets and Major Customers". Historically,
the prices for oil and gas have been volatile and are likely to continue to be
volatile in the future. See Item 7.--"Management's Discussion and Analysis of
Financial Condition and Results of Operations--Critical Accounting Policies
and Factors That May Affect Future Results".
Since December 31, 2000, we have not filed any estimates of total proved
net oil or gas reserves with any federal authority or agency other than the
SEC.
7
The following table sets forth certain information with respect to our
reserves over the last five years.
As of or for the Year Ended December 31,
----------------------------------------------------------
2001 2000 1999 1998 1997
-------- ---------- ---------- -------- --------
(in thousands, except ratios and per unit
amounts)
Present Value of Proved
Reserves(1)............ $669,764 $1,345,392 $1,246,049 $226,943 $510,993
Proved Reserves
Oil (MBbls)............ 240,636(1) 223,162 218,922 120,208 151,627
Gas (MMcf)............. 96,217 93,486 90,873 86,781 60,350
MBOE................... 256,673 238,743 234,068 134,672 161,685
Reserve Replacement
Ratio.................. 282% 153% 1,263% (229)%(2) 603%
Reserve Replacement Cost
per BOE................ $ 4.92 $ 5.98 $ 0.68 $ (5.46)(2) $ 2.71
Capital costs incurred.. $136,475 $ 80,928 $ 72,979 $100,935 $127,378
Percentage of total
capital costs
Acquisition............ 1% 3% 5% 10 % 34%
Development............ 98% 96% 89% 88 % 65%
Exploration............ 1% 1% 6% 2 % 1%
Average year-end
realized oil price, per
Bbl(3)................. $ 14.91 $ 21.02 $ 20.94 $ 7.96 $ 13.91
Average year-end
realized gas price, per
Mcf.................... $ 2.56 $ 14.63 $ 2.77 $ 1.68 $ 2.13
December 31 NYMEX WTI
spot price............. $ 19.84 $ 26.80 $ 25.60 $ 12.05 $ 18.34
- --------
(1) We have reduced the pre-tax present value of proved reserves and the
future net revenues of certain properties to reflect applicable
abandonment costs and, with respect to the LA Basin properties, a net
profits interest owned by a third party. Approximately 8.8 MMBOE of our
proved reserves in the L.A. Basin at December 31, 2001 are subject to a
50% net profits interest.
(2) The reserve replacement ratio and reserve replacement cost per BOE for
1998 are negative due to a negative volume revision related to low crude
oil prices at December 31, 1998.
(3) The average year-end oil price is based on the price in effect at year-
end with adjustments based on the location and quality of the oil.
Acquisition and Exploitation Activities
Acquisition and Exploitation Strategy
We are continually engaged in the exploitation and development of our
existing property base and the evaluation and pursuit of additional
underdeveloped properties for acquisition. We generally focus on mature but
underdeveloped producing crude oil properties in areas where we believe
substantial reserve additions and cash flow increases can be made through
relatively low-risk drilling, improved production practices and recovery
techniques and improved operating margins. We seek to improve a property's
operating margin by reducing costs, investing capital to increase production
rates and enhancing the marketing arrangements of the crude oil production.
We seek to acquire a majority interest in the properties we have identified
and to act as operator of those properties. When we purchase properties, we
then implement our exploitation plan 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 the
initial acquisition, we may also seek to increase our interest in the
properties through acquisitions of offsetting acreage, farmout drilling
arrangements and the purchase of minority interests in the properties.
By implementing our exploitation plan, we seek to increase cash flows and
enhance the value of our asset base. The results of these activities are
reflected in additions and revisions to proved reserves. During the five-year
period ending December 31, 2001, additions to proved reserves totaled 120.4
MMBOE or approximately 282% of cumulative net production for this period.
These reserves were added at an aggregate average cost of $3.80 per BOE. This
activity excludes 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 $1.08 per BOE.
8
We believe that our properties in our four core areas hold potential for
additional increases in production, reserves and cash flow. However, our
ability to achieve such increases could be adversely affected by future
decreases in the demand for crude oil and natural gas, operating risks,
unavailability of capital, adverse changes in governmental regulations or
other currently unforeseen developments. Accordingly, we can give no assurance
that such increases will be achieved.
During 2002, we expect to spend approximately $77 million on the
development and exploitation of our crude oil and natural gas properties.
Approximately $52 million of these capital expenditures are for exploitation
projects in onshore California. Activities to be conducted include development
drilling and a variety of primary and secondary recovery projects that we
believe will expand our proved developed reserve base, offset normal
production decline and potentially generate a year-over-year production
increase of approximately 3-5%. The 2002 capital program incorporates the
results of various analyses and field studies and includes the drilling of
approximately 82 total wells, including 10 injection wells and numerous
injection realignment related workovers.
Exploitation Projects
The following table sets forth certain information with respect to our
crude oil and gas properties (dollars in millions):
California Properties
------------------------------------
Arroyo Mt. Sunniland Illinois Point
LA Basin Montebello Grande Poso Trend Basin Arguello
--------- ---------- ------ ----- --------- -------- --------
Year(s) Acquired........ 1992 1997 1997 1998 1993/1994 1995 1999
Year(s) Discovered...... 1924-1966 1917 1906 1926 1943-1978 1905 1981
Proved reserves at
acquisition--MMBOE..... 17.7 23.3 19.9 7.7 5.0 17.3 6.4
Year Ended December 31,
2001
Capital Expenditures... $ 74.7 $ 13.0 $ 10.6 $10.3 $ 6.9 $12.5 $ 5.6
Sales--MMBOE........... 4.1 0.8 0.6 0.8 1.1 1.0 1.4
Gross Margin(1)........ $ 78.5 $ 11.1 $ 7.1 $13.4 $ 5.4 $14.5 $15.4
As of December 31, 2001:
Proved Reserves--
MMBOE................. 114.0(2) 27.6 60.8 9.3 17.3 21.1 5.0
Proved Developed
Reserves--MMBOE....... 79.9 15.5 12.0 4.6 15.5 13.3 3.8
Future Net Revenues.... $806.3 $185.7 $413.2 $45.1 $34.7 $55.7 $ 6.9
Present Value of Proved
Reserves.............. $357.7 $ 71.4 $126.1 $22.5 $26.5 $10.5 $ 6.9
- --------
(1) Revenues less production expenses. Excludes $0.9 million ($0.09 per BOE)
of hedging losses.
(2) Approximately 8.8 MMBOE of our proved reserves at December 31, 2001 are
subject to a 50% net profits interest.
(3) We have reduced the pre-tax present value of proved reserves and the
future net revenues of certain properties to reflect applicable
abandonment costs and, with respect to the LA Basin properties, a net
profits interest owned by a third party.
Onshore California. In 1992, we acquired Stocker Resources, a sole purpose
company formed in 1990 to acquire substantially all of Chevron USA's producing
crude 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 the 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 crude 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
9
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 an average of approximately 14,000 BOE per day
during the fourth quarter of 2001.
In 2001 we spent $74.7 million on capital projects on the LA Basin
properties, the most significant of which were the drilling of 42 production
and 15 injection wells. In 2002 we expect to spend $38 million on capital
projects which will include drilling 22 production wells and 4 injection
wells, performing numerous recompletions and workovers, and modifying various
production and injection facilities.
In March 1997, we expanded our operations in the LA Basin with the
acquisition of Chevron's interest in the Montebello field. We acquired a 100%
working interest (99.2% net revenue interest) in 55 producing crude oil wells
and related facilities and approximately 450 acres of surface fee land. Our
net average daily production from this field has increased from approximately
930 BOE per day at the time of acquisition to approximately 2,400 BOE per day
during the fourth quarter of 2001. 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 were the drilling of 17
production and 6 injection wells. In 2002 we expect to spend $11 million on
capital projects which include the drilling of 12 production wells and 6
injection wells, performing numerous workovers and increasing the capacity of
the production and injection facilities.
In November 1997, we acquired a 100% working interest (97% net revenue
interest) in the Arroyo Grande field located in San Luis Obispo County,
California from subsidiaries of Shell Oil Company ("Shell"). 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 the acquisition date, was producing approximately 1,600
BOE per day (approximately 1,500 BOE net to our interest) of 14 degree API
gravity crude oil from 70 wells. Since acquiring this property we have drilled
additional wells to downsize the injection patterns in the currently developed
area from 5 acres to 1.25 acres to accelerate recoveries, and realigned steam
injection within these areas to increase the efficiency of the recovery
process. It is also noteworthy that steam injection was curtailed by about 50%
immediately following the acquisition due to low crude prices. Although crude
prices subsequently rebounded, injection was maintained at this low rate
pending analysis of the saturation inputs provided by the infill drilling
program, and in 2001 due to excessive natural gas fuel costs. As a result,
base volumes declined considerably, but this decline was offset by the
contributions from producing wells 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 were the drilling of 19 production and 11
injection wells and the installation of a gas processing facility to reduce
third-party fuel gas purchases. In 2002 we expect to spend $2 million on
capital projects which include the recompletion of 5 wells. Although no
capital is required and little upward volume impact is expected in 2002, we
also plan to increase steam injection to near pre-acquisition levels in early
2002. Our net average daily production from this field was approximately 1,900
BOE per day during the fourth quarter of 2001.
During 1998, we acquired the Mt. Poso field from Aera Energy LLC. The field
is located near Bakersfield, California, in Kern County. At acquisition, the
field was producing 900 BOE per day of 15 to 17 degree API gravity crude 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. In 2001 we spent $10.3 million on capital projects in the Mt. Poso
field, the most significant
10
of which were the drilling of 43 production wells and recompletion of 38
wells. In 2002 we expect to spend $1 million on capital projects to optimize
the producing infrastructure. Our net average daily production from this field
was approximately 2,000 BOE per day during the fourth quarter of 2001.
South Florida. Our properties in the Sunniland Trend in south Florida
produced an average of approximately 2,900 MBbls of oil per day in 2001 and
accounted for 11% of our total sales volumes. In 2001 we spent $6.9 million on
capital projects in the Sunniland Trend, primarily facility enhancements and
abandonment of inactive wells. In 2002 we expect to spend $6 million on well
abandonments and infrastructure projects.
Illinois Basin. Our properties in the Illinois Basin produced an average of
approximately 2,700 MBbls of oil per day in 2001 and accounted for 11% of our
total sales volumes. In 2001 we spent $12.5 million on capital projects in the
Illinois Basin, the most significant of which were the drilling of 42
production and 9 injection wells and various water injection realignment
projects. In 2002 we expect to spend $9 million on capital projects which
include drilling 38 production wells.
Offshore California. In July 1999 we acquired Chevron's 26.3% working
interest in the Point Arguello Unit and the various partnerships owning the
associated transportation, processing and marketing infrastructure and a 26.3%
right to participate in the adjacent Rocky Point Unit. We assumed Chevron's
26.3% share of costs related to: (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. Chevron 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. We are the operator of record
for both the Point Arguello Unit and the Rocky Point Unit.
In 2001 we spent $5.6 million on capital projects in the Point Arguello
Unit, the most significant of which were the drilling of 6 production wells
and a number of recompletion and stimulation workovers. In 2002 we expect to
spend $4 million on capital projects which include converting 5 wells to
electric submersible lift systems, and various recompletions and stimulations.
We are currently seeking regulatory approval to allow near-term development of
the adjacent Rocky Point Unit by drilling extended-reach wells from the Point
Arguello platforms. While several critical regulatory permits and other
agreements remain to be finalized among the working interest owners, and a
larger rig must be procured, we believe the resolution of these issues may
potentially allow drilling of Rocky Point to occur in 2003.
At acquisition our net average daily production from this unit was 5,200
BOE per day. During the fourth quarter of 2001 our net average daily
production was approximately 4,400 BOE per day.
11
Productive Wells and Acreage
As of December 31, 2001, we had working interests in 2,071 gross (2,045
net) active producing oil wells. The following table sets forth certain
information with respect to our developed and undeveloped acreage as of
December 31, 2001.
December 31, 2001
-----------------------------
Developed Undeveloped
Acres(1) Acres(2)
------------- ---------------
Gross Net Gross Net(3)
------ ------ ------- -------
Onshore California............................. 8,889 8,844 8,928 5,296
Offshore California(4)......................... 15,326 4,033 41,720 1,449
Florida........................................ 12,025 12,025 75,034 72,581
Illinois....................................... 16,622 14,628 13,737 5,500
Indiana........................................ 1,155 854 1,280 575
Kansas......................................... -- -- 48,147 37,647
Kentucky....................................... -- -- 1,321 521
Louisiana...................................... -- -- 4,875 4,858
------ ------ ------- -------
Total........................................ 54,017 40,384 195,042 128,427
====== ====== ======= =======
- --------
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether such acreage
contains proved reserves.
(3) Less than 10% of total net undeveloped acres are covered by leases that
expire from 2002 through 2004.
(4) Does not include 6,200 acres under an option agreement, in which we have
the right to acquire a 26.315% interest.
Drilling Activities
Certain information with regard to our 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
----- ----- ----- ----- ----- -----
Exploratory Wells:
Oil........................................ -- -- -- -- -- --
Natural gas................................ -- -- -- -- -- --
Dry........................................ 1.0 0.5 -- -- 1.0 0.5
----- ----- ----- ----- ----- -----
Total.................................... 1.0 0.5 -- -- 1.0 0.5
===== ===== ===== ===== ===== =====
Development Wells:
Oil........................................ 168.0 163.4 158.0 156.0 105.0 105.0
Natural gas................................ - - -- -- -- --
Dry........................................ 1.0 1.0 2.0 2.0 -- --
----- ----- ----- ----- ----- -----
Total.................................... 169.0 164.4 160.0 158.0 105.0 105.0
===== ===== ===== ===== ===== =====
Total Wells:
Oil........................................ 168.0 163.4 158.0 156.0 105.0 105.0
Natural gas................................ -- -- -- -- -- --
Dry........................................ 2.0 1.5 2.0 2.0 1.0 0.5
----- ----- ----- ----- ----- -----
Total.................................... 170.0 164.9 160.0 158.0 106.0 105.5
===== ===== ===== ===== ===== =====
See "--Acquisition and Exploitation Activities" and "--Productive Wells and
Acreage" for additional information regarding exploitation activities,
including waterflood patterns, workovers and recompletions.
12
Production and Sales
The following table presents certain information with respect to crude oil
and natural gas production attributable to our properties, the revenue derived
from the sale of such production, average sales prices received and average
production costs during the three years ended December 31, 2001, 2000 and
1999.
Year Ended December 31,
----------------------------
2001 2000 1999
-------- -------- --------
(in thousands except as
noted)
Sales:
Oil (MBbls)..................................... 9,279 8,355 8,016
Gas (MMcf)...................................... 3,355 3,042 3,163
MBOE............................................ 9,838 8,862 8,543
Revenue:
Oil............................................. $186,476 $133,325 $111,128
Gas............................................. 28,771 16,017 5,095
-------- -------- --------
$215,247 $149,342 $116,223
======== ======== ========
Average sales price (in dollars):
Oil
Average NYMEX price per bbl..................... $ 26.01 $ 30.25 $ 19.25
Average hedge gain (loss) per bbl............... (0.10) (9.66) (1.39)
Average differential per bbl.................... (5.81) (4.63) (4.00)
-------- -------- --------
Average realized price per bbl.................. 20.10 15.96 13.86
Gas
Average price per Mcf........................... 8.58 5.26 1.61
Average price per BOE............................. 21.88 16.85 13.61
Production expenses ($/BOE)....................... 7.24 7.01 6.51
Pursuant to a crude oil marketing agreement, PAA is the exclusive purchaser
of all of our equity oil production.
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 such production are subject to wide
fluctuations and depend on numerous factors beyond our control, including
seasonality, the condition of the United States and world economies
(particularly the manufacturing sector), foreign imports, political conditions
in other oil-producing and gas-producing countries, the actions of the
Organization of Petroleum Exporting Countries and domestic government
regulation, legislation and policies. 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.
See Item 7.--"Management's Discussion and Analysis of Financial Condition and
Results of Operations--Critical Accounting Policies and Factors That May
Affect Future Results".
Certain of our operations in California that have interruptible electrical
contracts from time to time have been adversely impacted by electrical service
interruptions. We estimate that our oil and gas production for 2000 and 2001
was adversely affected by approximately 43,000 BOE and 60,000 BOE,
respectively, as a result of such interruptions. Although under recent
regulatory rulings we believe that our operations will only be affected if
rolling blackouts occur, and we have made operational changes to mitigate the
effects of electrical interruptions, there can be no assurance that our
operations will not be adversely impacted in the future by the California
power market. Although we are not currently
13
experiencing any significant involuntary curtailment of our crude oil or
natural gas production, market, logistic, economic and regulatory factors may
in the future materially affect our ability to sell our production.
To manage our exposure to commodity price risks, we utilize various
derivative instruments to hedge our exposure to price fluctuations on crude
oil sales. Our hedging arrangements provide us protection on the hedged
volumes if crude oil prices decline below the prices at which these hedges are
set, however, ceiling prices in our hedges may cause us to receive less
revenue on the hedged volumes than we would receive in the absence of hedges.
We do not currently have any natural gas hedges. See Item 7A--"Quantitative
and Qualitative Disclosures about Market Risks".
Substantially all of our 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.
Deregulation of gas prices has increased competition and volatility of
natural gas prices. Prices received for our natural gas are subject to
seasonal variations and other fluctuations. All of our gas production is
currently sold under various arrangements at spot indexed prices.
PAA is the exclusive purchaser of all of our equity oil production. The
following table reflects for the years ended December 31, 2000 and 1999,
during which periods PAA was consolidated in our financial statements,
customers accounting for more than 10% of consolidated sales (excluding
hedging effects):
Percentage of
Consolidated
Sales
---------------
Year Ended
December 31,
---------------
Customer 2000 1999
-------- ------ ------
Marathon Ashland Petroleum(1).............................. 12% --
Sempra Energy Trading Corporation(1)....................... -- 22%
Koch Oil Company(1)........................................ -- 18%
Percentage of
Oil and Gas
Sales(2)
---------------
Chevron.................................................... 43% 39%
Equiva Trading Company..................................... 23% --
Tosco Refining Company..................................... -- 19%
Conoco Inc................................................. -- 11%
Marathon Ashland Petroleum................................. 13% 16%
- --------
(1) These customers pertain to the operations of PAA. Represents percentage
of oil and gas sales revenues, plus marketing, transportation, storage
and terminalling revenues.
(2) These percentages represent the entities that purchased our equity crude
production from PAA.
If we were to lose PAA as the exclusive purchaser of our equity production,
we believe such loss would not have a material adverse effect on our results
of operations. We believe PAA could be replaced by other purchasers under
contracts with similar terms and conditions.
Competition
Our competitors include major integrated oil and natural gas companies, and
numerous independent oil and natural gas companies, individuals and drilling
and income programs. Many of our larger competitors possess and employ
financial and personnel resources substantially greater than
14
those available to us. Such companies are able to pay more for productive
crude oil and natural 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
natural 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 natural gas industry and
its individual participants. The failure to comply with such rules and
regulations can result in substantial penalties. The regulatory burden on the
oil and natural 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 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 U.S. Environmental Protection Agency, or
EPA, community-right-to-know regulations, and similar state statutes require
that certain information be maintained about hazardous materials used or
produced in operations and that this information be provided to 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.
Regulation of Production
The production of crude oil and natural 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
natural gas properties, the establishment of maximum rates of production from
crude oil and natural 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 natural gas and several states have indicated interest in
revising applicable regulations. The effect of these regulations is to limit
the amount of oil and natural gas we can produce from our wells and to limit
the number of wells or the locations at which we can drill. Moreover, each
state generally imposes an ad valorem, production or severance tax with
respect to production and sale of crude oil, natural 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 U.S. Department of Transportation, or DOT,
with respect to the design, installation, testing, construction, operation,
replacement, and management of pipeline facilities. In addition, we must
15
permit access to and copying of records, and must make certain reports and
provide information as required by the Secretary of Transportation. Comparable
regulation exists in the states in which we conduct pipeline operations. 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 Natural Gas
The FERC regulates interstate natural gas pipeline transportation rates and
service conditions. Although the FERC does not regulate natural gas producers
such as us, the agency's actions are intended to foster increased competition
within all phases of the natural 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 natural gas industry will have on our gas sales efforts.
Additional proposals and/or proceedings that might affect the natural gas
industry may be considered by the FERC, the U.S. Congress, or state regulatory
bodies. We cannot predict when or if any of these proposals may become
effective or what effect, if any, they may have on our operations. We do not
believe, however, that our operations will be affected any differently than
other gas producers with which we compete.
Environmental Regulation
General
Numerous federal, state and local laws and regulations governing the
discharge of materials into the environment or otherwise relating to the
protection of the environment affect our operations and costs. In particular,
our activities in connection with storage and transportation of crude oil and
other liquid hydrocarbons and our use of facilities for treating, processing
or otherwise handling hydrocarbons and wastes are subject to stringent
environmental laws and regulations. Our operations and properties are subject
to extensive and changing federal, state and local laws and regulations
relating to environmental protection, including the generation, storage,
handling, emission, transportation and discharge of materials into the
environment, and relating to safety and health. 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, compliance with existing and anticipated
laws and regulations increases our overall cost of business, including our
capital costs to construct, maintain and upgrade 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.
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 such laws and regulations on our
operations. Violation of these environmental laws and regulations and any
associated permits can result in the imposition of significant administrative,
civil and criminal penalties, injunctions and construction bans or delays. A
discharge of hydrocarbons or hazardous substances into the environment could,
to the extent such event is not insured, subject us to 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.
16
Although we obtained environmental studies on our properties in California,
the Sunniland Trend and the Illinois Basin, 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 approximately 90
years, and current or future local, state and federal environmental laws and
regulations may require substantial expenditures to remediate the properties
or to otherwise comply with such rules and regulations. In December 1995, we
negotiated an agreement with Chevron, a prior owner of certain of the LA Basin
properties, to remediate sections of the properties impacted by prior drilling
and production operations. Under this agreement, Chevron agreed to investigate
and potentially remediate specific areas contaminated with hazardous
components, such as volatile organic substances and heavy metals, and we
agreed to excavate and remediate nonhazardous crude oil contaminated soils. We
are obligated to construct and operate (for the next 10 years) a minimum of
five acres of bioremediation cells for crude oil contaminated soils designated
for excavation and treatment by Chevron. Although we believe that we do not
have any material obligations for operations conducted before our acquisition
of the properties from Chevron, other than our obligation to plug existing
wells and those normally associated with customary oil field operations of
similarly situated properties (such as the Chevron agreement described above),
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 from Chevron, either under the December 1995 agreement or the
limited indemnity from Chevron contained in the original purchase agreement.
A portion of our Sunniland Trend properties is located within the Big
Cypress National Preserve and our operations therein are subject to
regulations administered by the National Park Service, or NPS. Under such
regulations, a master plan of operations has been approved by the Regional
Director of the NPS. The master plan of operations is a comprehensive plan of
practices and procedures for our drilling and production operations designed
to minimize the effect of such operations on the environment. We must modify
the master plan of operations and secure permits from the NPS for new wells
that require the use of additional land for drilling operations. The master
plan of operations also requires that we restore the surface property affected
by drilling and production operations upon cessation of these activities. We
do not anticipate that expenditures required to comply with such regulations
will have a material adverse effect on our operations.
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, a species of bird designated as a federal threatened species
under the Endangered Species Act, or ESA. Approximately 40 pairs of
gnatcatchers are believed to inhabit the property. In addition, our 450 acres
have been or will shortly be committed to the Natural Community Conservation
Program/Coastal Sage Scrub Project, a voluntary conservation program. A
variety of existing laws, rules and guidelines govern activities that can be
conducted on properties that contain coastal sage scrub and gnatcatchers.
These laws, rules and guidelines generally limit the scope of operations that
can be conducted on such properties to those activities that do not materially
interfere with such vegetation, the gnatcatcher or its habitat. The ESA
provides for criminal penalties for willful violations of the ESA. 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. Although there can be no assurance that the presence of
coastal sage scrub and gnatcatchers on the Montebello Field and existing or
future laws, rules and guidelines will not prohibit or limit our operations
and our planned activities or future commercial and/or residential
development, we believe that we will be able to operate the existing wells and
realize the reserve potential identified in our acquisition analysis without
undue restrictions or prohibitions.
17
Water
The Oil Pollution Act, as amended, or OPA, was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972, as amended, or
FWPCA, and other statutes as they pertain to prevention and response to oil
spills. The OPA subjects owners of facilities to strict, joint and potentially
unlimited liability for containment and removal costs, natural resource
damages, and certain other consequences of an oil spill, where such spill is
into navigable waters (broadly defined), along shorelines or in the exclusive
economic zone of the U.S. The OPA establishes a liability limit for onshore
facilities of $350.0 million; however, a party cannot take advantage of this
liability limit if the spill is caused by gross negligence or willful
misconduct or resulted from a violation of a federal safety, construction, or
operating regulation. If a party fails to report a spill or cooperate in the
cleanup, the liability limits likewise do not apply. In the event of an oil
spill into navigable waters, substantial liabilities could be imposed upon us.
States in which we operate have also enacted similar laws. Regulations have
been or are currently being developed under OPA and state laws that may also
impose additional regulatory burdens on our operations.
The FWPCA imposes restrictions and strict controls regarding the discharge
of produced waters and other oil and gas wastes into navigable waters. Permits
must be obtained to discharge pollutants into state and federal waters. The
FWPCA provides for civil, criminal, and administrative penalties for
unauthorized discharges, and, along with OPA, imposes substantial potential
liability for the costs of removal, remediation and damages. We believe that
compliance with existing permits and compliance with foreseeable new permit
requirements will not have a material adverse effect on our financial
condition or results of operations. In addition, the Coastal Zone Management
Act authorizes state implementation and development of programs of management
measures for non-point source pollution to restore and protect coastal waters.
Pursuant to the FWPCA, the United States Corps of Engineers, with oversight
by the EPA, administers a complex program that regulates activities in wetland
areas. Some of our operations may be in areas that have been designated as
wetlands and, as such, would be subject to permitting requirements. Failure to
properly obtain a permit or violation of permit terms could result in the
issuance of compliance orders, restorative injunctions and a host of civil,
criminal and administrative penalties. We believe that we are currently in
substantial compliance with these permitting requirements.
Some states maintain groundwater protection programs that require permits
for discharges or operations that may impact groundwater conditions. We
believe that we are in substantial compliance with these state requirements.
Air Emissions
Our operations are subject to the federal Clean Air Act, as amended, and
comparable state and local statutes. We believe that our operations are in
substantial compliance with these statutes in all states in which we operate.
Amendments to the federal Clean Air Act enacted in late 1990 required most
industrial operations in the U.S. to incur capital expenditures in order to
meet air emission control standards developed by the EPA and state
environmental agencies. In addition, these amendments included a new operating
permit for major sources, which applied to some of our facilities.
Implementation of these amendments has not had a material adverse effect on
our financial condition or results of operations.
Solid Waste
We generate wastes, including hazardous wastes, that are subject to the
requirements of the federal Resource Conservation and Recovery Act, or RCRA
and comparable state statutes. The EPA
18
is considering the adoption of stricter disposal standards for non-hazardous
wastes, including oil and gas wastes. We are not currently required to comply
with a substantial portion of the RCRA requirements because our operations
generate minimal quantities of hazardous wastes. However, it is possible that
additional wastes, which could include wastes currently generated as non-
hazardous wastes during operations, will in the future be designated as
"hazardous wastes." Hazardous wastes are subject to more rigorous and costly
treatment, storage, transportation and disposal requirements than are non-
hazardous wastes. On August 8, 1998, the EPA added four petroleum refining
wastes to the list of RCRA hazardous wastes. While the full impact of this new
rule has yet to be determined, the rule may impose increased expenditures and
operating expenses on us, which may require us to assume additional
obligations relating to the treatment, storage, transportation and disposal of
certain petroleum refining wastes that were not previously regulated as
hazardous waste. Additional changes in the regulations could result in
additional capital expenditures or operating expenses for us as well as the
industry in general.
Hazardous Substances
The Comprehensive Environmental Response, Compensation and Liability Act,
as amended, or CERCLA, also known as "Superfund," and comparable state laws
impose liability, without regard to fault or the legality of the original act,
on certain classes of persons that contributed to the release or threatened
release of a "hazardous substance" into the environment. These persons include
the current and past owners or operators of the site or sites where the
release occurred and companies that disposed or transported or arranged for
the disposal or transportation of the hazardous substances found at the site.
Under CERCLA, such persons may be subject to joint and several liability for
the costs of cleaning up the hazardous substances that have been released into
the environment, for damages to natural resources, and for the costs of
certain health studies. CERCLA also authorizes the EPA and, in some instances,
third parties to act in response to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. It is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by hazardous substances or other pollutants released into the
environment. In the course of our ordinary operations, we may generate waste
that falls within CERCLA's definition of a "hazardous substance." We may be
jointly and severally liable under CERCLA for all or part of the costs
required to clean up sites at which such hazardous substances have been
disposed of or released into the environment. We may be subject to third party
lawsuits seeking damages for hazardous substances released into the
environment.
We currently own or lease, and have in the past owned or leased, properties
where hydrocarbons are being or have been handled. Although we have utilized
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed of or released on or
under the properties owned or leased by us or on or under other locations
where these wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes were not under our control. These
properties and wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators), to clean up contaminated property (including
contaminated groundwater) or to perform remedial plugging operations to
prevent future contamination.
Hazardous Materials Transportation Requirements
The DOT regulations affecting pipeline safety require pipeline operators to
implement measures designed to reduce the environmental impact of oil
discharge from onshore oil pipelines. These regulations require operators to
maintain comprehensive spill response plans, including extensive spill
19
response training for pipeline personnel. In addition, DOT regulations contain
detailed specifications for pipeline operation and maintenance. We believe our
operations are in substantial compliance with such regulations.
Other Business Matters
We must continually acquire, explore for, develop or exploit new crude oil
and natural gas reserves to replace those produced or sold. Without successful
drilling, acquisition or exploitation operations, our crude oil and natural
gas reserves and revenues will decline. Drilling activities are subject to
numerous risks, including the risk that no commercially viable crude oil or
natural gas production will be obtained. Our decision to purchase, explore,
exploit or develop an interest or property will depend in part on the
evaluation of data obtained through geophysical and geological analyses and
engineering studies, the results of which are often inconclusive or subject to
varying interpretations. See "--Oil and Gas Reserves". The cost of drilling,
completing and operating wells is often uncertain. Drilling may be curtailed,
delayed or canceled as a result of many factors, including title problems,
weather conditions, compliance with government permitting requirements,
shortages of or delays in obtaining equipment, reductions in product prices or
limitations in the market for products. The availability of a ready market for
our crude oil and natural gas production also depends on a number of factors,
including the demand for and supply of crude oil and natural gas and the
proximity of reserves to pipelines or trucking and terminal facilities. See
"--Product Markets and Major Customers". Natural gas wells may be shut in for
lack of a market or due to inadequacy or unavailability of natural gas
pipeline or gathering system capacity.
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 cause us to seek transportation alternatives, which in
turn could result in increased transportation costs to us or involuntary
curtailment of a significant portion of our oil and gas production.
Our operations are subject to all of the risks normally incident to the
exploration for and the production of crude oil and natural gas, including
blowouts, cratering, oil spills and fires, each of which could result in
damage to or destruction of crude oil and natural gas wells, production
facilities or other property, or injury to persons. The relatively deep
drilling conducted by us from time to time involves increased drilling risks
of high pressures and mechanical difficulties, including stuck pipe, collapsed
casing and separated cable. Our operations in California, including
transportation of crude oil by pipelines within the city 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 the area. Although we maintain insurance coverage
considered to be customary in the industry, we are not fully insured against
certain of these risks, including, in certain instances, earthquake risk in
California, either because such insurance is not available or because of high
premium costs.
A pipeline may experience damage as a result of an accident or other
natural disaster. These hazards can cause personal injury and loss of life,
severe damage to and destruction of property and equipment, pollution or
environmental damages and suspension of operations. We maintain insurance of
various types that we consider to be adequate to cover our operations and
properties. The insurance covers all of our assets in amounts considered
reasonable. The insurance policies are subject to deductibles that we consider
reasonable and not excessive. Our insurance does not cover every potential
risk associated with operating pipelines. 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.
20
The occurrence of a significant event not fully insured or indemnified
against, or the failure of a party to meet its indemnification obligations,
could materially and adversely affect our operations and financial condition.
We believe that we are adequately insured for public liability and property
damage to others with respect to our operations. With respect to all of our
coverage, no assurance can be given that we will be able to maintain adequate
insurance in the future at rates we consider reasonable.
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 interferes with the use of such 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 natural gas industry,
minimal investigation of title is made at the time of acquisition of
undeveloped properties. Title investigation is made and title opinions of
local counsel are generally obtained only before commencement of drilling
operations. We believe that we have satisfactory title to all of our other
assets. Although title to such properties are subject to encumbrances in
certain cases, such as customary interests generally retained in connection
with acquisition of real property, liens related to environmental liabilities
associated with historical operations, liens for current taxes and other
burdens and minor easements, restrictions and other encumbrances to which the
underlying properties were subject at the time of acquisition by us, we
believe that none of such burdens will materially detract from the value of
such properties or from our interest therein or will materially interfere with
their use in the operation of our business.
Federal and Foreign Taxation
At December 31, 2001, we had remaining federal income tax net operating
loss, or NOL, carryforwards of approximately $51.8 million and approximately
$34.1 million of alternative minimum tax, or AMT, net operating loss
carryforwards available as a deduction against future AMT income. In addition,
we had approximately $3.8 million of enhanced oil recovery credits, $5.1
million of AMT credits and $7.0 million of statutory depletion carryforwards
at December 31, 2001. The NOL carryforwards expire in 2019. The value of these
carryforwards depends on our ability to generate federal taxable income. In
addition, for AMT purposes, only 90% of AMT income in any given year may be
offset by AMT NOLs.
Our ability to utilize NOL carryforwards to reduce our future federal
taxable income and federal income tax is subject to various limitations under
the Internal Revenue Code of 1986, as amended, or the Code. The utilization of
such carryforwards may be limited upon the occurrence of certain ownership
changes, including the issuance or exercise of rights to acquire stock, the
purchase or sale of stock by 5% stockholders, as defined in the Treasury
Regulations, and our offering of stock during any three-year period resulting
in an aggregate change of more than 50%, which we will refer to as an
ownership change, in our beneficial ownership.
In the event of an ownership change, Section 382 of the Code imposes an
annual limitation on the amount of a corporation's taxable income that can be
offset by these carryforwards. The limitation is generally equal to the
product of (1) the fair market value of our equity multiplied by (2) a
percentage approximately equivalent to the yield on long-term tax-exempt bonds
during the month in which an ownership change occurs. In addition, the
limitation is increased if there are recognized built-in gains during any
post-change year, but only to the extent of any net unrealized built-in gains
(as defined in the Code) inherent in the assets sold. Although no assurances
can be made, we do not believe that an ownership change has occurred as of
December 31, 2001. Equity transactions after the date hereof
21
by us or by 5% stockholders (including relatively small transactions and
transactions beyond our control) could cause an Ownership Change and therefore
a limitation on the annual utilization of NOLs.
In the event of an ownership change, the amount of our NOLs available for
use each year will depend upon future events that cannot currently be
predicted and upon interpretation of complex rules under Treasury Regulations.
If less than the full amount of the annual limitation is utilized in any given
year, the unused portion may be carried forward and may be used in addition to
successive years' annual limitation.
As a result of PAA's operations in Canada, beginning in 2001 we became
subject to Canadian federal and provincial income taxes. Our currently payable
Canadian income taxes for 2001 totaled $2.1 million.
Employees
As of February 1, 2002, we had 314 full-time employees, none of whom is
represented by any labor union. Of such full-time employees, 187 are field
personnel involved in oil and gas producing activities.
Item 3. LEGAL PROCEEDINGS
Texas Securities Litigation. In November and December of 1999, class action
lawsuits were filed in the United States District Court for the Southern
District of Texas alleging that PAA and certain of the general partner's
officers and directors violated federal securities laws, primarily in
connection with unauthorized trading by a former employee. The consolidated
class action filed by purchasers of our common stock and options is captioned
Koplovitz v. Plains Resources Inc., et al. The consolidated action filed by
purchasers of PAA's common units is captioned Di Giacomo v. Plains All
American Pipeline, L.P., et al.
We and PAA reached an agreement with representatives for the plaintiffs for
the settlement of all of the class actions, and in January 2001, PAA deposited
approximately $30.0 million under the terms of the settlement agreement. The
total cost of the settlement to us and PAA, including interest and expenses
and after insurance reimbursements, was $14.9 million. Of that amount, $1.0
million was allocated to us by agreement between special independent
committees of our board of directors and the board of directors of Plains
Holdings Inc. (fka Plains All American Inc.), the then general partner of PAA.
The settlement has received final approval by the court. The settlement
agreement does not affect the Texas Derivative Litigation and Delaware
Derivative Litigation described below.
Delaware Derivative Litigation. Beginning December 3, 1999 derivative
lawsuits were filed in the Delaware Chancery Court, New Castle County naming
Plains Holdings Inc., the then general partner of PAA, its directors and
certain of its officers as defendants alleging that the defendants breached
the fiduciary duties that they owed to PAA and its unitholders by failing to
monitor properly the activities of its employees. The court has consolidated
all of the cases under the caption In Re Plains All American Inc. Shareholders
Litigation. A motion to dismiss was filed on behalf of the defendants on
August 11, 2000.
An agreement has been reached with the plaintiffs to settle the Delaware
litigation by PAA making an aggregate payment of approximately $1.1 million.
On March 6, 2002, the Delaware court approved this settlement.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Fernandez v. Plains All American Inc., et al., naming Plains Holdings
Inc., the then general partner of PAA, its directors and certain of its
officers as
22
defendants. This lawsuit contains the same claims and seeks the same relief as
the Delaware derivative litigation described above. A motion to dismiss was
filed on behalf of the defendants on August 14, 2000. PAA has reached an
agreement in principle to settle the Texas derivative litigation. The
settlement, which is subject to court approval, contemplates a payment of
$112,500 by PAA and does not contemplate any payment by us.
We, in the ordinary course of business, are a claimant and/or defendant in
various other legal proceedings. Our 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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders, through
solicitation of proxies or otherwise, during the fourth quarter of the fiscal
year covered by this report.
Directors and Executive Officers of Plains Resources
Listed below are our directors and executive officers and their business
experience for the last five years.
Directors
James C. Flores, age 42, Chairman of the Board and Chief Executive Officer
and Director since May 2001. Mr. Flores served as Chairman of the Board of
Ocean Energy, Inc. from March 1999 until January 2000, and as Vice Chairman
from January 2000 until January 2001. Before its merger into Seagull Energy
Corporation he was President and Chief Executive Officer of Ocean Energy, Inc.
from July 1995 until March 1999 and a director from 1992 until March 1999.
Jerry L. Dees, age 62, Director since 1997. Mr. Dees 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
Tom H. Delimitros, age 61, Director since 1988. Mr. Delimitros has been
General Partner of AMT Venture Funds, a venture capital firm, since 1989.
William M. Hitchcock, age 62, Director since 1977. Mr. Hitchcock is a
partner and has been President, since December 1996, of Pembroke Capital LLC,
an investment firm. In addition, he is Chief Executive Officer of Camelot Oil
& Gas, an oil and gas company.
John H. Lollar, age 63, Director since 1995. Mr. Lollar has been the
Managing Partner of Newgulf Exploration L.P. since December 1996.
D. Martin Phillips, age 48, Director since June 2001. Mr. Phillips has been
a Managing Director and principal of EnCap Investments L.L.C., a funds
management and investment banking firm that focuses exclusively on the oil and
gas industry, since November 1989.
Robert V. Sinnott, age 52, Director since 1994. Mr. Sinnott has been Senior
Vice President of Kayne Anderson Investment Management, Inc., an investment
management firm, since 1992.
J. Taft Symonds, age 62, Director since 1987. Mr. Symonds has been Chairman
of the Board of Symonds Trust Co. Ltd., an investment firm, and Chairman of
the Board of Maurice Pincoffs Company, Inc., an international marketing firm,
since 1978.
23
Executive Officers
Franklin R. Bay, age 44, Senior Vice President of Corporate Development,
since January 2002. Prior to joining Plains, Mr. Bay served in various
capacities with Enron Corp. for approximately five years, including Vice
President of Commercial Affairs for Northern Natural Gas Pipeline Company,
General Counsel of the Gas Pipeline Group and Head of Broadband Services
Emerging Business Group.
Cynthia A. Feeback, age 44, Senior Vice President--Accounting and Treasurer
since July 2001. She was our Vice President--Accounting and Assistant
Treasurer from May 1999 to July 2001, and our Controller and Assistant
Treasurer from May 1998 to May 1999. Previously, Ms. Feeback served as our
Controller from 1993 to 1998.
Thomas M. Gladney, age 50, 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 January 1992 to December 1998, he was
Offshore Operations Manager for Oryx Energy Company.
Jere C. Overdyke, Jr., age 50, Executive Vice President and Chief Financial
Officer, since May 2001. From 1991 to March 2001, he served in various
capacities with Enron Corp., including Managing Director of Enron Global
Markets, Enron North America, Enron International and Enron Capital and Trade
Resources.
John T. Raymond, age 31, President and Chief Operating Officer since
November 2001. He was our Executive Vice President and Chief Operating Officer
from May 2001 to November 2001. 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. from 1992 to April 1998.
Timothy T. Stephens, age 50, 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. He
served as Chairman, President and Chief Executive Officer of Abacan Resources
Corporation from February 1998 until March 2000. 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.
24
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Price Range of Common Stock
Our common stock is listed and traded on the New York Stock Exchange under
the symbol "PLX". Prior to December 21, 2001 our common stock was traded on
the American Stock Exchange. The number of stockholders of record of our
common stock as of February 28, 2002 was 1,077.
The following table sets forth the range of high and low closing sales
prices for our common stock as reported on the applicable Stock Exchange
Composite Tapes for the periods indicated below.
High Low
------ ------
2001:
1st Quarter.................................................. $23.65 $19.44
2nd Quarter.................................................. 26.80 19.89
3rd Quarter.................................................. 29.50 22.76
4th Quarter.................................................. 27.70 22.20
2000:
1st Quarter.................................................. $14.75 $10.50
2nd Quarter.................................................. 17.00 11.00
3rd Quarter.................................................. 20.13 13.81
4th Quarter.................................................. 21.75 16.88
Dividend Policy
We have not paid cash dividends on shares of our common stock since our
inception and do not anticipate paying any cash dividends on our common stock
in the foreseeable future. In addition, the amount of dividends we can pay is
restricted by provisions of the indentures governing the issue of $275.0
million of 10.25% Senior Subordinated Notes Due 2006, or 10.25% notes, and the
agreement with respect to our $225.0 million revolving credit facility.
Recent Sales of Unregistered Securities
On June 8, 2001, the holders of the remaining 26,892 shares of our series F
preferred stock outstanding converted their shares of our series F preferred
stock into 2,236,639 shares of our common stock plus a cash payment equal to,
with respect to each share of our series F preferred stock converted, the
accrued dividends on each share from June 8, 2001 until the first date on
which we could cause conversion of the shares, plus a 20% premium on the
amount of the accrued dividends. This conversion was exempt from registration
pursuant to Section 3(a)(9) of the Securities Act of 1933, as amended.
In the second quarter of 2001, certain holders of our series H preferred
stock converted an aggregate of 132,022 shares into 4,439,788 shares of our
common stock. This conversion was exempt from registration pursuant to Section
3(a)(9) of the Securities Act of 1933, as amended.
In the third quarter of 2001, pursuant to the terms of our series H
preferred stock, the remaining shares of our series H preferred stock
outstanding were converted into 1,212,600 shares of our common stock. This
conversion was exempt from registration pursuant to Section 3(a)(9) of the
Securities Act of 1933, as amended.
25
Item 6. SELECTED FINANCIAL DATA
The following selected financial information was derived from, and is
qualified by reference to, our consolidated financial statements, including
the notes thereto, appearing elsewhere in this report. The selected financial
data should be read in conjunction with the consolidated financial statements,
including the notes thereto, and "Item 7.--Management's Discussion and
Analysis of Financial Condition and Results of Operations" (in thousands,
except per share information).
Year Ended December 31,
---------------------------------------------------------
2001(1) 2000 1999 1998 1997
-------- ---------- ----------- ---------- ----------
Statement of Operations
Data:
Revenues:
Oil and natural gas
sales................. $215,247 $ 149,342 $ 116,223 $ 102,754 $ 109,403
Other operating
revenues.............. 473 -- -- -- --
Marketing,
transportation,
storage and
terminalling
revenues.............. -- 6,425,644 10,796,998 3,454,635 2,732,043
Gain on sale of
assets(2)............. -- 48,188 16,457 -- --
-------- ---------- ----------- ---------- ----------
215,720 6,623,174 10,929,678 3,557,389 2,841,446
-------- ---------- ----------- ---------- ----------
Expenses:
Production expenses.... 71,192 62,140 55,645 50,827 45,486
Marketing,
transportation,
storage and
terminalling
expenses.............. -- 6,292,615 10,689,308 3,416,274 2,719,563
Unauthorized trading
losses and related
expenses(3)........... -- 7,963 166,440 7,100 --
General and
administrative(4)..... 21,293 50,776 31,402 10,778 8,340
Depreciation, depletion
and amortization...... 28,921 47,221 36,998 31,020 23,778
Reduction of carrying
cost of oil and
natural gas
properties(5)......... -- -- -- 173,874 --
-------- ---------- ----------- ---------- ----------
121,406 6,460,715 10,979,793 3,689,873 2,797,167
-------- ---------- ----------- ---------- ----------
Income from Operations.. 94,314 162,459 (50,115) (132,484) 44,279
Equity in earnings of
PAA(1)................ 18,540 -- -- -- --
Gain on PAA unit
offerings(6).......... 170,157 -- 9,787 60,815 --
Interest expense....... (26,385) (55,828) (46,378) (35,730) (22,012)
Interest and other
income(7)............. 151 7,411 1,237 834 319
-------- ---------- ----------- ---------- ----------
Income (loss) before
income taxes,
minorityinterest,
extraordinary item and
cumulative effect of
accounting change...... 256,777 114,042 (85,469) (106,565) 22,586
Minority interest....... -- (42,535) 40,203 (786) --
Income tax (expense)
benefit................
Current................ (9,947) (1,020) 7 (862) (352)
Deferred............... (91,513) (24,563) 20,472 45,867 (7,975)
-------- ---------- ----------- ---------- ----------
Income (loss) before
extraordinary item and
cumulative effect of
accounting change...... 155,317 45,924 (24,787) (62,346) 14,259
Extraordinary item, net
of tax benefit and
minority interest(8)... -- (4,988) (544) -- --
Cumulative effect of
accounting change, net
of tax benefit(9)...... (1,986) (121) -- -- --
-------- ---------- ----------- ---------- ----------
Net income (loss)....... 153,331 40,815 (25,331) (62,346) 14,259
Less: cumulative
preferred stock
dividends(10).......... (27,245) (14,725) (10,026) (4,762) (163)
-------- ---------- ----------- ---------- ----------
Net income (loss)
applicable to common
shareholders........... $126,086 $ 26,090 $ (35,357) $ (67,108) $ 14,096
======== ========== =========== ========== ==========
Income (loss) per common
share--basic:
Before extraordinary
item.................. $ 6.07 $ 1.75 $ (2.02) $ (3.99) $ 0.85
Extraordinary item..... -- (0.28) (0.03) -- --
Cumulative effect of
accounting change..... (0.09) (0.01) -- -- --
-------- ---------- ----------- ---------- ----------
$ 5.98 $ 1.46 $ (2.05) $ (3.99) $ 0.85
======== ========== =========== ========== ==========
Income (loss) per common
share--diluted:
Before extraordinary
item.................. $ 4.82 $ 1.56 $ (2.02) $ (3.99) $ 0.77
Extraordinary item..... -- (0.17) (0.03) -- --
Cumulative effect of
accounting change..... (0.07) -- -- -- --
-------- ---------- ----------- ---------- ----------
$ 4.75 $ 1.39 $ (2.05) $ (3.99) $ 0.77
======== ========== =========== ========== ==========
Table and footnotes continued on following page
26
Year Ended December 31,
--------------------------------------------------
2001 2000 1999 1998 1997
-------- --------- --------- -------- --------
Cash Flow Data:
Net cash provided by
(used in) operating
activities.............. $120,128 $ 35,860 $ (75,964) $ 37,630 $ 30,307
Net cash provided by
(used in) investing
activities.............. (29,383) 130,183 (266,396) (483,422) (107,634)
Net cash provided by
(used in) financing
activities.............. (91,221) (229,191) 404,044 448,622 78,524
EBITDA (11):
Upstream EBITDA.......... 123,235 74,594 51,172 46,446 59,106
Adjusted Upstream
EBITDA.................. 136,769 75,564 51,172 46,446 59,106
PAA Distributions........ 31,553 30,134 29,472 -- --
Combined EBITDA.......... 168,322 105,698 80,644 46,446 59,106
As of December 31,
--------------------------------------------------
2001 2000 1999 1998 1997
-------- ---------- ---------- -------- --------
Balance Sheet Data:
Cash and cash
equivalents.............. $ 1,179 $ 5,080 $ 68,228 $ 6,544 $ 3,714
Working capital
(deficit)(12)............ (9,969) 20,289 115,867 (21,041) (6,011)
Property and equipment,
net...................... 507,425 844,274 787,653 661,726 413,308
Total assets.............. 648,788 1,394,329 1,689,560 972,838 556,819
Long-term debt............ 282,061 626,376 676,703 431,983 285,728
Other long-term
liabilities and deferred
income taxes............. 49,183 3,422 21,107 10,253 5,107
Redeemable preferred
stock.................... -- 50,000 138,813 88,487 --
Non-redeemable preferred
stock, common stock and
other stockholders'
equity................... 254,852 137,140 40,619 69,170 133,193
- --------
(1) As a result of the reduction in our ownership interest in PAA, our
investment in PAA is accounted for using the equity method of accounting
effective January 1, 2001. In prior periods, PAA is included on a
consolidated basis. See Item 7.--"Management's Discussion and Analysis
of Financial Condition and Results of Operations--General".
(2) Relates to the sale of assets by PAA.
(3) Relates to losses resulting from unauthorized trading activity by a
former employee of PAA. See Items 1 and 2--"Business and Properties--
Unauthorized Trading Losses".
(4) Expense for 2001 included $8.7 million in costs related to our strategic
restructuring and expense for 2000 includes a $5.0 million charge to
reserve for potentially uncollectible accounts receivable of PAA.
(5) Represents a noncash charge related to a writedown of the capitalized
costs of our proved crude oil and natural gas properties due to low
crude oil prices at December 31, 1998.
(6) Gains in 2001 relate to the Transactions and PAA's public offerings of
common units. Gains in 1999 relate to PAA's public offering of common
units and the gain in 1998 relates to the formation of PAA.
(7) Amount for 2000 includes $4.4 million of previously deferred net gains
from terminated interest rate swaps recognized as a result of debt
extinguishment.
(8) Relates to the early redemption and refinancing of PAA debt.
(9) The amount for 2001 is the cumulative effect of adopting Statement of
Financial Accounting Standards No. 133--"Accounting for Derivative
Instruments and Hedging Activities". The amount for 2000 is the
cumulative effect adjustment as a result of the adoption of SEC Staff
Accounting Bulletin 101--"Revenue Recognition in Financial Statements".
(10) Amount for 2001 includes a $21.4 million deemed dividend and a $2.5
million cash payment related to the redemption and conversion of series
F preferred stock in connection with our strategic restructuring. See
Items 1 and 2--"Business and Properties--Our June 2001 Strategic
Restructuring".
(11) EBITDA means earnings before interest, income taxes, depletion,
depreciation and amortization. Upstream EBITDA excludes the results of
operations of PAA. Adjusted upstream EBITDA also excludes noncash
compensation, interest and other income, general and administrative
costs related to the June 2001 strategic restructuring and amortization
of option premiums. PAA distributions reflects amounts we received from
PAA subsequent to its initial public offering in 1998. Combined EBITDA
reflects adjusted upstream EBITDA plus distributions received from PAA.
EBITDA is not a measurement presented in accordance with generally
accepted accounting principles, or GAAP, and is not intended to be used
in lieu of GAAP representations of results of operations and cash
provided by operating activities. EBITDA is commonly used by debt
holders and financial statement users as a measurement to determine the
ability of an entity to meet its interest obligations.
(12) At December 31, 1999, working capital includes $37.9 million and $103.6
million related to pipeline linefill and a segment of the All American
Pipeline, respectively, both of which were sold in the first quarter of
2000.
27
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
General
Before the second quarter of 2001 we were engaged in two related lines of
business within the energy industry. The first line of business, referred to
as "upstream", acquires, exploits, develops, explores and produces crude oil
and natural gas. The second line of business, referred to as "midstream",
engaged in the marketing, transportation and terminalling of crude oil. Our
midstream business was conducted through our majority ownership in PAA. For
financial statement purposes, for the years prior to 2001, the assets,
liabilities and earnings of PAA were included in our consolidated financial
statements, with the public unitholders' interest reflected as a minority
interest.
June 2001 Strategic Restructuring
On June 8, 2001, we sold a portion of our interests in PAA to a group of
investors and management of PAA for approximately $155.2 million. The assets
we sold in this restructuring included 52%, or approximately 5.2 million, of
the subordinated units of PAA, at $22 per unit, and an aggregate 54% ownership
interest in the general partner of PAA. We received approximately $110 million
in cash and 23,108 shares of our series F preferred stock valued at $45.2
million as consideration for the sale. We recognized a pre-tax gain of $128.3
million in connection with this sale. In connection with our strategic
restructuring, the holders of the remaining shares of our series F preferred
stock converted their shares into 2.2 million shares of our common stock and
received from us a cash payment of approximately $2.5 million, equal to, with
respect to each share of our series F preferred stock converted, the accrued
dividends on each share from June 8, 2001 until the first date on which we
could cause conversion of the shares, plus a 20% premium on the amount of the
accrued dividends. Also, in connection with our strategic restructuring,
holders of our series H preferred stock converted an aggregate of 132,022
shares into approximately 4.4 million shares of our common stock. We also
granted management of PAA an option to acquire an additional 2% ownership
interest in the general partner of PAA, which PAA management exercised in
September 2001 by paying us $1.5 million in cash and notes. As a result of
this exercise we recognized a gain of $1.1 million.
As a result of our strategic restructuring, all of our series F preferred
stock and all but approximately 36,000 shares of our series H preferred stock
were retired or converted. The remaining outstanding shares of our series H
preferred stock were converted into 1.2 million shares of our common stock
during the third quarter of 2001.
The excess of the fair value of our Series F preferred stock redeemed as
consideration over the carrying value of such series F preferred stock ($21.4
million) is deemed to be a dividend to our preferred stockholders. As a
result, for purposes of determining our basic and diluted earnings per share,
we deducted this amount in determining our income available to our common
stockholders.
In exchange for the significant value we received for the subordinated
units (which are subordinated in right to distributions from PAA and are not
publicly traded) relative to the then current market price of the publicly
traded common units, we entered into a value assurance agreement with each of
the purchasers of the subordinated units. The value assurance agreements
require us to pay to the holders an amount per fiscal year, payable on a
quarterly basis, equal to the difference between $1.85 per unit and the actual
amount distributed during that period. The value assurance agreements will
expire upon the earlier of the conversion of the subordinated units to common
units, or June 8, 2006.
Also in connection with our strategic restructuring:
. we appointed James C. Flores as our Chairman of the Board and Chief
Executive Officer and we appointed a new Chief Operating Officer, Chief
Financial Officer, and General Counsel and Secretary;
28
. certain of our employees received transaction-related bonuses and other
payments and vested in benefits in accordance with the terms of our
employee benefit plans;
. we entered into a separation agreement with PAA whereby, among other
things, (1) we agreed to indemnify PAA, its general partner, and its
subsidiaries against (a) any claims related to the upstream business,
whenever arising, and (b) any claims related to federal or state
securities laws or the regulations of any self-regulatory authority, or
other similar claims, resulting from alleged acts or omissions by us,
our subsidiaries, PAA, or PAA's subsidiaries occurring on or before June
8, 2001, and (2) PAA agreed to indemnify us and our subsidiaries against
any claims related to the midstream business, whenever arising;
. we entered into a pension and employee benefits assumption and
transition agreement pursuant to which we and the general partner of PAA
agreed to the transition of certain employees to the general partner,
our provision of certain benefits with respect to the transfer, and our
provision of transition-related services;
. with respect to certain of our employees who transferred to the general
partner of PAA and who held in-the-money but unvested stock options to
acquire our common stock, which were subject to forfeiture due to the
transfer of employment, we agreed to substitute for the unvested options
a total contingent grant of 51,000 subordinated units with a value equal
to the discounted present value of the spread on the unvested options,
to vest on the same vesting schedule as the options, as a result of
which we recognized $0.5 million in noncash compensation expense; and
. we agreed to contribute 287,500 subordinated units to the general
partner of PAA to be used for performance option grants to officers and
key employees of the general partner.
As a result of our reduced ownership of PAA and our inability to control
PAA's operations, our minority interest in PAA is accounted for using the
equity method of accounting effective January 1, 2001. Under this method, we
no longer consolidate the assets, liabilities and operating activities of PAA.
Rather, we record our proportionate share of PAA's net assets and results of
operations.
As of December 31, 2001, our aggregate ownership interest in PAA was
approximately 29%, which was comprised of (1) a 44% interest in the general
partner of PAA, (2) 45%, or approximately 4.5 million, of the subordinated
units and (3) 24%, or approximately 7.9 million, of the common units,
including approximately 1.3 million class B common units.
Based on PAA's current annual distribution rate of $2.05 per unit, we would
receive an annual distribution from PAA of approximately $27.6 million,
including $1.0 million for our 44% of the general partner incentive
distribution. The general partner of PAA is entitled to receive incentive
distributions if the amount PAA distributes with respect to any quarter
exceeds levels specified in PAA's partnership agreement. Under the quarterly
incentive distribution provisions, generally the general partner is entitled
to 15% of distributions in excess of $0.45 per unit, 25% of distributions in
excess or $0.495 per unit and 50% of distributions in excess of $0.675 per
unit. Based on the current $2.05 annual distribution level ($0.5125 quarterly)
and the current units outstanding, the general partner's incentive
distribution is forecast to be approximately $2.2 million, of which we would
receive 44%.
29
Results of Operations
As a result of the change to the equity method of accounting for our
investment in PAA, our income statement presentation for 2001 is not comparable
to our income statement presentations for 2000 and 1999. The following table
reflects our 2001 income statement compared to proforma income statements for
2000 and 1999 adjusted to reflect PAA on the equity method of accounting. Our
discussion of the results of operations will be based on the income statement
presentation reflected herein.
Year Ended December 31
----------------------------
2001 2000 1999
-------- -------- --------
ProForma ProForma
(in thousands)
Revenues
Oil............................................ $186,476 $131,672 $109,643
Gas............................................ 28,771 16,017 5,094
Other operating revenues....................... 473 -- --
-------- -------- --------
215,720 147,689 114,737
-------- -------- --------
Costs and Expenses
Production costs............................... 71,192 62,140 55,646
General and administrative..................... 21,293 10,955 7,919
Depletion, depreciation and amortization....... 28,921 22,699 19,652
-------- -------- --------
121,406 95,794 83,217
-------- -------- --------
Income from Operations........................... 94,314 51,895 31,520
Other Income (Expense)
Equity in earnings of PAA...................... 18,540 50,115 (60,905)
Gain on PAA Unit transactions.................. 170,157 -- --
Interest expense............................... (26,385) (30,408) (25,844)
Interest and other income and expense.......... 151 (95) 10,671
-------- -------- --------
Income (Loss) Before Income Taxes, Extraordinary
Items and Cumulative Effect of Accounting
Change.......................................... 256,777 71,507 (44,558)
Income tax (expense) benefit
Current expense.............................. (9,947) (1,020) 7
Deferred expense............................. (91,513) (24,563) 20,765
-------- -------- --------
Income (Loss) Before Extraordinary Items and
Cumulative Effect of Accounting Change.......... 155,317 45,924 (23,786)
Extraordinary item............................. -- (4,988) (1,545)
Cumulative effect of accounting change......... (1,986) (121) --
-------- -------- --------
Net Income (Loss)................................ 153,331 40,815 (25,331)
Preferred dividend requirement................. (27,245) (14,725) (10,026)
-------- -------- --------
Income (Loss) Attributable to Common Shares...... $126,086 $ 26,090 $(35,357)
======== ======== ========
30
The following table reflects the components of our oil and gas revenues and
sets forth our revenues and costs and expenses on a BOE basis:
Year Ended December 31
-------------------------
2001 2000 1999
------ -------- --------
ProForma ProForma
Daily Average Sales Volumes
Total
Oil and liquids (Bbls)............................ 25,422 22,828 21,962
Natural Gas (Mcf)................................. 9,192 8,312 8,665
BOE............................................... 26,954 24,213 23,406
Oil and Liquids (Bbls)
Onshore California................................ 15,858 13,990 14,150
Offshore California............................... 3,920 4,122 2,223
Illinois.......................................... 2,739 2,799 3,029
Florida........................................... 2,905 1,917 2,560
------ ------ ------
25,422 22,828 21,962
====== ====== ======
Natural Gas (Mcf)
Onshore California................................ 9,192 8,312 8,665
====== ====== ======
Unit Economics (in dollars)
Average Liquids Sales Price ($/Bbl)
Average NYMEX..................................... $26.01 $30.25 $19.25
Hedging gain (loss)............................... (0.10) (9.50) (1.39)
Differential...................................... (5.81) (4.99) (4.18)
------ ------ ------
Net realized(1)................................... $20.10 $15.76 $13.68
====== ====== ======
Average Gas Sales Price ($/Mcf)..................... $ 8.58 $ 5.26 $ 1.61
Average Sales Price per BOE......................... $21.88 $16.67 $13.43
Average Production Costs per BOE.................... (7.24) (7.01) (6.51)
------ ------ ------
Gross Margin per BOE................................ 14.64 9.66 6.92
G&A per BOE(2)...................................... (2.16) (1.22) (0.92)
------ ------ ------
Gross Profit per BOE................................ $12.48 $ 8.44 $ 6.00
====== ====== ======
DD&A per BOE (oil and gas properties)............... $ 2.75 $ 2.25 $ 2.13
- --------
(1) Prices in 2000 and 1999 are proforma to include the $0.20/Bbl marketing
fee paid to PAA that was eliminated in consolidation.
(2) Excludes costs associated with our strategic restructuring and noncash
compensation expense.
Comparison of Year Ended December 31, 2001 to Year Ended December 31, 2000
We reported net income of $153.3 million for the year ended December 31,
2001, compared to net income of $40.8 million for the same period in 2000. Our
adjusted EBITDA increased 59% in 2001, to $168.3 million from the $105.7
million reported in 2000.
Excluding certain unusual items, net income for 2001 was $59.9 million
compared to $40.8 million in 2000. The unusual items in 2001 include: (i)
$170.2 million of gains including (a) $129.4 million in gains related to the
sale of a portion of our investment in PAA in connection with our June 2001
strategic restructuring, (2) $38.8 million of gains related to PAA's 2001
equity offerings, and (3) a $2.0 million gain related to the vesting of
certain unit grants; (ii) $8.7 million of general and administrative expenses
related to our June 2001 strategic restructuring, of which $4.3 million is
noncash
31
compensation cost associated with the vesting of performance-based stock
options; (iii) a $1.9 million charge (net to our interest) included in equity
in earnings of PAA related to our June 2001 strategic restructuring; (iv) a
$0.9 million charge related to the termination of an interest rate swap, and
(v) a $0.9 million noncash charge representing unamortized premiums for crude
oil put options with a subsidiary of Enron Corp.
During the year ended December 31, 2001, our operating revenues from oil,
natural gas and electricity sales increased by $68.0 million, from $147.7
million in 2000 to $215.7 million in 2001. The increase primarily reflects
more favorable results of our hedging program and higher gas prices. Increased
prices contributed $51.4 million in additional revenue, and increased sales
volumes contributed $16.6 million.
Our oil sales volumes increased 11%, from 22.8 MBbls per day in 2000 to
25.4 MBbls per day in 2001. On an "as produced" basis, our oil volumes
increased 8% from 23.2 MBbls per day in 2000 to 25.1 MBbls per day in 2001.
Our gas sales volumes increased 11%, from 8.3 MMcf per day in 2000 to 9.2 MMcf
per day in 2001. Production increases were primarily attributable to the
continuing development of our onshore California properties.
The average realized price for crude oil and liquids increased 28%, from
$15.76 per barrel in 2000 to $20.10 per barrel in 2001. Hedges that we put
into place in the latter part of 1999, when crude oil prices were considerably
lower, significantly impacted the 2000 realized price. The average realized
price for natural gas increased 63%, from $5.26 per Mcf in 2000 to $8.58 per
Mcf in 2001. This increase is reflective of the well-publicized high natural
gas prices in California during the first half of 2001.
Our production costs increased by $9.1 million, from $62.1 million for the
year ended December 31, 2000 to $71.2 million for the same period in 2001. The
2001 increase was primarily attributable to increased volumes, which accounted
for $6.8 million of the increase. On a barrel equivalent basis, production
costs increased 3%, from $7.01 per BOE in 2000 to $7.24 per BOE in 2001,
primarily reflecting higher electricity costs in California during the year.
Our general and administrative, or G&A, expense increased $10.3 million,
from $11.0 million for the year ended December 31, 2000 to $21.3 million for
the same period in 2001. Included in 2001 G&A is approximately $8.7 million of
nonrecurring costs associated with our June 2001 strategic restructuring, of
which $4.3 million was noncash compensation cost primarily associated with the
vesting of performance-based stock options in connection with our
restructuring.
Our depreciation, depletion and amortization, or DD&A, expense increased
$6.2 million, from $22.7 million for the year ended December 31, 2000 to $28.9
million for the same period in 2001. Oil and gas DD&A expense increased $7.2
million reflecting higher sales volumes and an increase in the rate per BOE.
Our average oil and gas DD&A expense on a per barrel equivalent basis for 2000
was $2.25 per BOE as compared to $2.75 per BOE in 2001. Our oil and gas DD&A
rate for the fourth quarter of 2001 and the first nine months of 2002, based
on our year-end 2001 oil and gas reserves, is $3.10 per BOE.
Our equity in the earnings of PAA was $18.5 million for the year ended
December 31, 2001, as compared to $50.1 million for the same period in 2000.
The decrease was primarily attributable to decreases in our ownership interest
in 2001 as well as nonrecurring gains included in PAA's 2000 earnings. At
December 31, 2000 our ownership interest in PAA was approximately 54%.
Primarily as a result of PAA's two public unit offerings during 2001, and our
June 2001 strategic restructuring, our ownership interest was approximately
29% at December 31, 2001.
The gain on PAA units reflects: (i) $129.4 million in gains related to the
sale of a portion of our investment in PAA in connection with our June 2001
strategic restructuring; (ii) $38.8 million of gains
32
resulting from the increase in the book value of our equity in PAA to reflect
our proportionate share of the increase in the underlying net assets of PAA
resulting from PAA's 2001 public equity offerings, in which we did not
participate; and (iii) a $2.0 million gain related to the vesting of certain
unit grants. No similar transactions occurred in 2000.
Our interest expense decreased by $4.0 million, from $30.4 million to $26.4
million for the year ended December 31, 2001 compared to 2000, reflecting
lower bank debt and lower interest rates on borrowings under our revolving
credit facility.
Our income tax expense increased to $101.5 million for the year ended
December 31, 2001 as compared to $25.6 million for the same period in 2000.
The increase was primarily attributable to the gains on PAA units discussed
above and an increase in our effective tax rate from 35.8% in 2000 to 39.5% in
2001. In 2001 we recognized a deferred tax provision of $91.5 million and a
current tax provision of $10.0 million. The current tax provision is primarily
attributable to the gain on the sale of PAA units. For 2000 we recognized a
deferred tax provision of $24.6 million and a current tax provision of $1.0
million. At December 31, 2001 we have a net deferred tax liability of $44.3
million, primarily attributable to timing differences between the
deductibility of certain costs for book and tax purposes.
The cumulative effects of accounting change recognized for the year ended
December 31, 2001 is for the adoption of Statement of Financial Accounting
Standards No. 133 "Accounting for Derivative Instruments and Hedging
Activities", as amended. The amount in 2000 is for the adoption of SEC Staff
Accounting Bulletin 101 "Revenue Recognition in Financial Statements".
Comparison of Year Ended December 31, 2000 to Year Ended December 31, 1999
We reported net income of $40.8 million for the year ended December 31,
2000, compared to a net loss of $25.3 million for the same period in 1999.
Combined EBITDA increased 31% in 2000, to $105.7 million from the $80.6
million reported in 1999.
Our operating revenues from oil and natural gas sales were $147.7 million
in 2000, an increase of $33.0 million over 1999 due to higher commodity prices
and increased sales volumes, which contributed approximately $28.5 million and
$4.5 million to the increase, respectively.
Our oil sales volumes increased from 22.0 MBbls per day in 1999 to 22.8
MBbls per day in 2000. The volume increase is primarily attributable to a full
year of production from our offshore California property that was acquired in
mid-1999. Our gas sales volumes decreased from 8.7 MMcf per day in 1999 to 8.3
MMcf per day in 2000.
The average realized price for oil increased 15%, from $13.68 per barrel in
1999 to $15.76 per barrel in 2000. The average NYMEX oil price increased from
$19.25 per barrel in 1999 to $30.25 per barrel in 2000. 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 $9.50 per barrel. The average realized price for gas
increased 227%, from $1.61 per Mcf in 1999 to $5.26 per Mcf in 2000. This
increase is reflective of the well-publicized high gas prices in California
during the latter half of 2000.
Our production costs were $62.1 million in 2000, an increase of $6.5
million over 1999 due to higher production costs and increased sales volumes,
which contributed $4.4 million and $2.1 million to the increase, respectively.
On a barrel equivalent basis, production costs increased 8%, from $6.51 per
BOE in 1999 to $7.01 per BOE in 2000, primarily reflecting a full year of
production from our offshore California property, increased gas fuel costs and
upward pressure on costs throughout the service industry.
Our G&A expense increased $3.1 million, from $7.9 million for the year
ended December 31, 1999 to $11.0 million for the same period in 2000. The
increase primarily reflects higher personnel costs and
33
expenses related to our corporate reorganization and $1.0 million in expenses
related to PAA's unauthorized trading loss.
Our DD&A expense increased $3.0 million, from $19.7 million for the year
ended December 31, 1999 to $22.7 million for the same period in 2000. Oil and
gas DD&A expense increased $1.8 million, with $1.1 million of the increase
from higher sales volumes. Our oil and gas DD&A expense on a per barrel
equivalent basis for 1999 was $2.13 per BOE as compared to $2.25 per BOE in
2000.
Our equity in the earnings of PAA was $50.1 million for the year ended
December 31, 2000, as compared to a loss of $60.9 million for the same period
in 1999. The loss in 1999 was due to unauthorized trading losses of $166.4
million incurred by PAA in 1999.
Our interest expense increased by $4.6 million, from $25.8 million to $30.4
million for the year ended December 31, 2000 compared to 1999, reflecting
higher bank debt.
Our income tax expense increased to $25.6 million for the year ended
December 31, 2000 as compared to an income tax benefit of $20.8 million for
the same period in 1999.
The extraordinary items in 2000 and 1999 relate to the early redemption and
refinancing of PAA debt.
Liquidity and Capital Resources
General
Cash generated from our upstream operations, PAA distributions and our
revolving credit facility are our primary sources of liquidity. At December
31, 2001 we had availability on our revolving credit facility of $212.9
million. We believe that we have sufficient liquid assets, cash from
operations and, if necessary, borrowing capacity under our credit facility to
meet our short term normal recurring operating needs, debt service
obligations, contingencies and anticipated capital expenditures. We also
believe that we have sufficient liquid assets, cash from operations and
borrowing capacity under our credit facility to meet our long term normal
recurring operating needs, contingencies and anticipated capital expenditures.
In 2006, our approximately $267.5 million of 10.25% senior subordinated notes
will mature. We believe that we will refinance the 10.25% senior subordinated
notes before they mature, however, there can be no assurance that we will be
able to do so.
Cash Flows
Year Ended December
31,
------------------------
2001 2000 1999
------ ------- -------
(in millions)
Cash provided by (used in):
Operating activities............................. $120.1 $ 35.9 $ (76.0)
Investing activities............................. (29.4) 130.2 (266.4)
Financing activities............................. (91.2) (229.2) 404.0
Operating Activities. Net cash provided by operating activities in 2001
totaled $120.1 million compared to net cash provided by operating activities
of $35.9 million in 2000. The net increase is primarily attributable to higher
realized oil and gas prices and increased sales volumes. Net cash used in
operating activities in 1999 resulted from the unauthorized trading losses of
PAA.
Investing Activities. In 2001 net cash used in investing activities was
$29.4 million. Additions to oil and gas properties and equipment used $131.8
million in cash, and we made capital contributions to
34
PAA of $4.0 million to maintain our proportionate general partner share of
equity offerings by PAA. To maintain its 2% general partner interest, the
general partner of PAA is required to make a capital contribution each time
PAA has a new equity offering. These uses of cash were offset by $106.9
million in cash proceeds received as a result of our June 2001 strategic
restructuring. During 2000 investing activities provided cash of $130.2
million. Proceeds from PAA asset sales of $224.3 million were offset primarily
by expenditures of $12.2 million for crude oil pipeline, gathering and
terminal costs and $78.7 million for upstream acquisition, exploration and
development costs. Net cash used in investing activities for 1999 included
approximately $176.9 million for midstream acquisitions, primarily for the
Scurlock and West Texas gathering system acquisitions, approximately $12.5
million for midstream capital costs and $77.9 for upstream acquisition,
exploration, exploitation and development costs.
Financing Activities. Cash used in financing activities in 2001 included a
net reduction in long-term debt of $23.9 million, expenditures of $67.7
million for our repurchase of 2.8 million shares of our common stock stock,
$9.2 million in proceeds from new issuances of our common stock, and $8.7
million in preferred stock dividends. Cash used in financing activities in
2000 included a net reduction in long and short term debt of $158.0 million,
expenditures of $23.6 million for our repurchase of 1.3 million shares of our
common stock, $13.4 million in preferred stock dividends and $29.4 million in
distributions to PAA unitholders. Cash provided by financing activities in
1999 was generated primarily from net issuances of $50.0 million of our series
F preferred stock, $50.8 million in PAA common units and $325.2 million of
short-term and long-term debt. Financing activities for 1999 also included
dividend payments of approximately $4.2 million on our series E preferred
stock and distributions to PAA unitholders of $22.2 million.
Our Board of Directors has authorized the repurchase of up to eight million
shares of our common stock. During 2001 we repurchased 2.8 million shares for
$67.7 million and in 2000 we repurchased 1.3 million shares for $23.6 million.
Our average cost for the share purchases was $24.02 per share in 2001 and
$18.34 per share in 2000.
Capital Expenditures
We have made and will continue to make substantial capital expenditures for
the acquisition, exploitation, development, exploration and production of
crude oil and natural gas reserves. Historically, we have financed these
expenditures primarily with cash generated by operations, bank borrowings and
the issuance of our common stock and our preferred stock. We intend to make
aggregate capital expenditures, including capitalized G&A and interest, of
approximately $77 million in 2002 for exploitation of our existing properties.
In addition, we intend to continue to pursue the acquisition of underdeveloped
producing properties. We will also be required to make capital contributions
to the general partner of PAA for any PAA equity offerings. We believe that we
will have sufficient cash from operating activities and borrowings under the
revolving credit facility to fund our capital expenditures.
Commitments
At December 31, 2001, 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 1,949 6,261 4,313 267,450 --
Operating leases..................... 616 593 595 573 143 --
----- ----- ----- ----- ------- ----
1,127 2,542 6,856 4,886 267,593 --
===== ===== ===== ===== ======= ====
The long-term debt amounts consist principally of amounts due under our
revolving credit facility and 10.25% senior subordinated notes. Historically,
we have renewed and/or extended our revolving
35
credit facility prior to commencing scheduled payments. There can be no
assurance, however, that we will be able to do so in the future. We believe
that we will refinance the 10.25% senior subordinated notes before they
mature, however, there can be no assurance that we will be able to do so.
In connection with our June 2001 strategic restructuring, we entered into
value assurance agreements with the purchasers of the subordinated units,
under the terms of which we will pay the purchasers an amount per fiscal year,
payable on a quarterly basis, equal to $1.85 per unit less the actual amount
distributed during that year. The value assurance agreements will expire upon
the earlier of (a) the conversion of all of the subordinated units to common
units or (b) June 8, 2006. In the first quarter of 2002 PAA paid a quarterly
distribution of $0.5125 per unit ($2.05 annualized).
Revolving Credit Facility
Amounts borrowed under our credit facilities were as follows at the dates
indicated (in thousands):
December 31,
----------------
2001 2000
------- --------
Plains, excluding PAA
Revolving credit facility................................ $11,500 $ 27,300
------- --------
11,500 27,300
------- --------
PAA
Revolving credit facility................................ -- 320,000
Letter of credit and hedged inventory facility........... -- 1,300
------- --------
-- 321,300
------- --------
$11,500 $348,600
======= ========
We have a $225.0 million revolving credit facility with a group of banks.
Our revolving credit facility is guaranteed by all of our upstream
subsidiaries and is collateralized by our upstream oil and natural gas
properties and those of the guaranteeing subsidiaries and the stock of all the
upstream subsidiaries. The borrowing base under the revolving credit facility
at December 31, 2001 was $225.0 million and is subject to redetermination from
time to time by the lenders in good faith, in the exercise of the lenders'
sole discretion, and in accordance with customary practices and standards in
effect from time to time for crude oil and natural gas loans to borrowers
similar to us. Our borrowing base may be affected from time to time by the
performance of our oil and natural gas properties and changes in oil and
natural gas prices. We incur a commitment fee of 3/8% per annum on the unused
portion of the borrowing base. In addition, we pay a fee of 1 3/8% per annum
of the face amount of letters of credit that are issued under our revolving
credit facility. Our revolving credit facility terminates on July 1, 2003, at
which time the remaining outstanding balance converts to a term loan,
repayable in eight equal quarterly installments commencing October 1, 2003,
with a final maturity of July 1, 2005. Our revolving credit facility bears
interest, at our option, of either LIBOR plus 1 3/8% or the base rate (as
defined in our facility). At December 31, 2001, letters of credit of $0.6
million were outstanding under the revolving credit facility.
Our revolving credit facility contains covenants which, among other things,
limit the payment of cash dividends on our common stock, limit repurchases of
our common stock, limit the amount of our consolidated debt, limit our ability
to make certain loans and investments, and provide that we must maintain a
specified relationship between current assets and current liabilities.
In October 2001 we amended the terms of our revolving credit facility to
allow us to purchase any combination of our own common stock, our senior
subordinated notes and PAA common units and pay cash dividends on our common
stock (up to $30 million) up to a total of $150.0 million. At December 31,
2001 we had $117.5 million available under this provision of the credit
facility.
36
As of December 31, 2001, we were in compliance with the covenants contained
in our revolving credit facility and could have borrowed the full $225.0
million available under the facility.
10.25% Senior Subordinated Notes Due 2006
At December 31, 2001 we had $267.5 million principal amount of 10.25%
Senior Subordinated Notes Due 2006, or 10.25% notes, outstanding, bearing a
coupon rate of 10.25%. The 10.25% notes were issued in 1996 ($150.0 million),
1997 ($50.0 million) and 1999 ($75.0 million). In 2001 we repurchased $7.55
million of the 10.25% notes at 99.5% of par.
The 10.25% notes are redeemable, at our option, at 105.13% of the principal
amount through March 15, 2002, at 103.42% on or after March 15, 2002, at
101.71% on or after March 15, 2003 and at 100% on or after March 15, 2004
plus, in each case, accrued interest to the date of redemption.
The indentures governing our 10.25% notes contain covenants that: (1) limit
the incurrence of additional indebtedness; (2) limit certain investments; (3)
limit restricted payments; (4) limit the disposition of assets; (5) limit the
payment of dividends and other payment restrictions affecting subsidiaries;
(6) limit transactions with affiliates; (7) limit the creation of liens; and
(8) restrict mergers, consolidations and transfers of assets. In the event of
a change of control and a corresponding rating decline under the indentures,
we will be required to make an offer to repurchase the 10.25% notes at 101% of
the principal amount thereof, plus accrued and unpaid interest to the date of
the repurchase.
The 10.25% notes are unsecured general obligations and are subordinated in
right of payment to all our existing and future senior indebtedness and are
guaranteed by certain of our subsidiaries on a full, unconditional, joint and
several basis.
Contingencies
Following our announcement in November 1999 of PAA's losses resulting from
unauthorized trading by a former employee, numerous class action lawsuits were
filed against PAA, certain of its general partner's officers and directors and
in some of these cases, its general partner and us alleging violations of the
federal securities laws. In addition, derivative lawsuits were filed in the
Delaware Chancery Court against PAA's general partner, its directors and
certain of its officers alleging the defendants breached the fiduciary duties
owed to PAA and its unitholders by failing to monitor properly the activities
of its traders. These suits have been settled. See Item 3.--"Legal
Proceedings."
Recent Accounting Pronouncements
The following Statements of Financial Accounting Standards, or SFAS's, 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 will be allocated to expense using
37
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 position, results of operations or
cash flows.
In the fourth quarter of 2000, we adopted SEC Staff Accounting Bulletin
101, "Revenue Recognition in Financial Statements", or SAB 101. As a result,
we record revenue from crude oil production in the period it is sold as
opposed to when it is produced and carry any unsold production as inventory
valued at historical cost. The total effect of implementing SAB 101 was to
reduce reported sales volumes by 144,000 barrels for 2000 and net income for
the year by $175,000, including a $121,000 reduction for the cumulative effect
of prior years. The effect of this change in accounting for crude oil
inventories on prior periods was deminimus.
Critical Accounting Policies and Factors That May Affect Future Results
Based on the accounting policies we have in place, which are discussed in
Note 1 to the consolidated financial statements, certain factors may impact
our future financial results. The most significant of these factors and their
effect on certain of our accounting policies is 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 purchased puts and calls. While the use of
these types of hedging instruments limits our downside risk to adverse price
movements, they 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 Item 7A--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 present value of estimated future net cash flows from
proved oil and gas reserves (including the effect of any related hedging
activities), discounted at 10 percent, plus the lower of cost or fair value of
unproved properties included in the costs being amortized (net of related tax
effects). 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 reasonably possible that our estimate
of discounted future net cash flows from proved oil and gas reserves could
change in the near term. If oil and gas prices decline significantly in the
future, even if only for a short period of time, it is possible that write-
downs of our oil and gas properties could occur. Write-downs required by these
rules do not impact cash flows from our operating activities.
38
Oil and Gas Reserves
The process of estimating quantities of proved reserves is inherently
uncertain, and the reserve data included in this annual report are only
estimates. Reserve engineering is a subjective process of estimating
underground accumulations of natural gas and crude oil that cannot be measured
in an exact manner. The process relies on interpretations of available
geologic, geophysical, engineering and production data. The extent, quality
and reliability of this technical data can vary. The process also requires
certain economic assumptions, some of which are mandated by the SEC, such as
oil and gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. The accuracy of a reserve estimate is a
function of the quality and quantity of available data, the interpretation of
that data, the accuracy of various mandated economic assumptions and the
judgment of the persons preparing the estimate.
The proved reserve information included in this annual report is based on
estimates prepared by outside engineering firms. Estimates prepared by others
may be higher or lower than these estimates. Because these estimates depend on
many assumptions, all of which may substantially differ from actual results,
reserve estimates may be different from the quantities of natural gas and
crude oil that are ultimately recovered. In addition, results of drilling,
testing and production after the date of an estimate may justify material
revisions to the estimate.
You should not assume that the present value of future net cash flows is
the current market value of our estimated proved natural gas and oil reserves.
In accordance with SEC requirements, we base the estimated discounted future
net cash flows 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.
Our rate of recording DD&A is dependent upon our estimate of proved
reserves. If the estimates of proved reserves declines, the rate at which we
record DD&A expense increases, reducing net income. Such a decline may result
from lower market prices, which may make it non-economic to drill for and
produce higher cost fields. In addition, the decline in proved reserve
estimates may impact the outcome of the "ceiling" test discussed above.
Operating Risks and Insurance Coverage
Our operations are subject to all of the risks normally incident to the
exploration for and the production of crude oil and natural gas, including
blowouts, cratering, oil spills and fires, each of which could result in
damage to or destruction of crude oil and natural gas wells, production
facilities or other property, or injury to persons. Our operations in
California, including transportation of crude oil by pipelines within the city
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 the area. Although we
maintain insurance coverage considered to be customary in the industry, we are
not fully insured against some risks, including earthquake risk in California,
either because insurance is not available or because of high premium costs.
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
39
environment. These laws and regulations may, among other things, impose
liabilities on the lessee under an oil and gas lease for the cost of pollution
clean-up resulting from operations, subject the lessee 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,
the Sunniland Trend and Illinois Basin, 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 approximately 90 years, and current or
future federal, state and local environmental laws and regulations may require
substantial expenditures to comply with such rules and regulations. While we
do not believe that 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 such laws or regulations will not
have such an impact.
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 cost to perform these tasks is
approximately $17.0 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 each include $0.5 million of
expense associated with these estimated future costs.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in crude oil
commodity prices and interest rates. 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.
On January 1, 2001, we adopted 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 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.
40
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 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 of 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, or 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 G20 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 the year ended December 31, 2001 include a $3.4 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. We
also utilize interest rate swaps and collars to manage the interest rate
exposure on our long-term debt. In October 2001 we entered into a three-year
interest rate swap agreement, fixing at 5.29% the interest rate on $7.5
million of borrowing under our revolving credit facility.
On January 1, 2001, in accordance with the transition provisions of SFAS
133, we recorded a gain of $4.5 million in OCI representing the cumulative
effect of an accounting change to recognize at fair value all cash flow
derivatives, including our equity in the cash flow derivatives of PAA. We
recorded cash flow hedge derivative assets and liabilities of $20.6 million
and $18.1 million, respectively, and a net-of-tax non-cash charge of $2.0
million was recorded in earnings as a cumulative effect adjustment.
For the year ended December 31, 2001 net unrealized gains of $9.8 million
were added to OCI and the fair value of open positions increased $16.2
million. At December 31, 2000, we had an interest rate swap arrangement to
protect interest rate fluctuations on a portion of our outstanding debt. The
position was terminated prior to maturity and as a result $0.6 million related
to such position was relieved from OCI.
At December 31, 2001, net unrealized gains on our option and swap contracts
included in OCI was $16.7 million. The related assets and liabilities were
included in other current assets ($21.8 million), other assets ($5.7 million),
and deferred income taxes ($10.8 million). Additionally, OCI includes our $2.3
million (net of tax) equity in the unrealized OCI losses of PAA. As of
December 31, 2001, $13.2 million of deferred net gains on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
the next twelve-month period.
41
Commodity Price Risk. At March 13, 2002, we had the following open crude
oil hedge positions:
Barrels Per
Day
-------------
2002 2003
------ ------
Puts
Average price $20.00/bbl..................................... 2,000 --
Calls
Average price $35.17/bbl..................................... 9,000 --
Swaps
Average price $24.00/bbl..................................... 17,000 --
Average price $23.12/bbl..................................... -- 12,500
These positions provide for us to receive for the year ended December 31,
2002 an average minimum NYMEX price of approximately $23.58 per barrel on
19,000 barrels per day with full upside participation above $20.00 per barrel
on 11% of those hedged barrels, and upside participation above $35.17 per
barrel on 47% of those hedged barrels. For example, if the NYMEX index
averages $20.00 during 2002, we will receive $23.58 per barrel; if the NYMEX
index averages $25.00 per barrel, we will receive $24.11 per barrel; if the
NYMEX index averages $30.00 per barrel, we will receive $24.63 per barrel; and
if the NYMEX index average were to fall to $15.00 per barrel we would receive
$23.58 per barrel, all on the hedged barrels. For 2003, we have entered into
various arrangements that provide for us to receive an average fixed NYMEX
price of $23.12 per barrel on 12,500 barrels per day regardless of the NYMEX
index average. 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.
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
crude oil and natural gas sales revenues. Such contracts resulted in a
reduction of revenues of $0.9 million, $79.4 million and $11.1 million for the
years ended December 31, 2001, 2000 and 1999, respectively. At December 31,
2001, we had an unrealized gain of $16.6 million (net of tax) with respect to
such contracts. The estimated fair value of the hedges is included in our
balance sheet at December 31, 2001.
The fair value of outstanding derivative commodity instruments and the
change in fair value that would be expected from a 10 percent price decrease
are shown in the table below (in millions):
December 31,
------------------------------
2001 2000
-------------- ---------------
Effect Effect
of 10% of 10%
Fair Price Fair Price
Value Decrease Value Decrease
----- -------- ----- --------
Swaps and options contracts................... $28.8 $18.5 $17.3 $(13.0)
Futures contracts............................. $ -- $ -- $(9.4) $ 6.0
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 year 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
42
across-the-board 10 percent 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 percent change in
prompt month crude 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.
In the fourth quarter of 2001 we terminated our open crude oil put options
with Enron Risk Management Corp. and charged earnings for $0.9 million,
representing unamortized premiums for such options. The contract
counterparties for our current 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 our revolving credit
facility, with one such counterparty holding contracts that represent
approximately 37% of the fair value of all open positions at December 31,
2001.
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 crude oil prices decline below
the prices at which these hedges are set, but ceiling prices in our hedges may
cause us to receive less revenue on the hedged volumes than we would receive
in the absence of hedges.
Interest Rate Risk. Our debt instruments are sensitive to market
fluctuations in interest rates. The table below presents principal payments
and the related weighted average interest rates by expected maturity dates and
the estimated fair value for debt outstanding at December 31, 2001. Our
variable rate debt bears interest at LIBOR or prime plus the applicable
margin. The average interest rates presented below are based upon rates in
effect at December 31, 2001. The carrying value of variable rate bank debt
approximates fair value because interest rates are variable, based on
prevailing market rates. The fair value of fixed rate debt was based on quoted
market prices based on trades of subordinated debt.
Expected Year of Maturity
------------------------------------------------- Fair
2002 2003 2004 2005 2006 Thereafter Total Value
---- ----- ----- ----- ---- ---------- ------ ------
(dollars in millions)
Long-term debt--
variable rate......... $ -- $ 1.4 $ 5.8 $ 4.3 $-- $ -- $ 11.5 $ 11.5
Average interest
rate................ -- 5.10% 5.10% 5.10% -- -- 5.10%
Long-term debt--fixed
rate.................. $0.5 $ 0.5 $ 0.5 $ -- $-- $267.5 $269.0 $272.1
Average interest
rate................ 8.00% 8.00% 8.00% -- -- 10.25% 10.24%
Interest rate swaps are used 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. At December 31, 2001, we had an
interest rate swap for an aggregate notional principal amount of $7.5 million,
for which we would receive approximately $0.03 million if such arrangement
were terminated as of such date. The swap is based on LIBOR margins and
provides for a fixed rate of 3.914% with an expiration date of October 2004.
The adjustment to interest expense resulting from interest rate swaps for the
years ended December 31, 2001 and 2000 was a $0.03 million loss and a $0.3
million gain, respectively.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in this report as set forth in
the "Index to Financial Statements" on page F-1.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
43
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding our directors and executive officers will be included
in the proxy statement for the 2002 annual meeting of stockholders to be filed
within 120 days after December 31, 2001, and is incorporated by reference to
this report.
We have provided summary information with respect to our directors and
executive officers following Item 4 in Part I of this report.
Item 11. EXECUTIVE COMPENSATION
Information regarding executive compensation will be included in the proxy
statement and is incorporated by reference to this report.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding beneficial ownership will be included in the proxy
statement and is incorporated by reference to this report.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions will
be included in the proxy statement and is incorporated by reference to this
report.
44
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Consolidated Financial Statements" set forth on Page F-1.
(a) (3) Exhibits
2.1 Stock Purchase Agreement dated as of March 15, 1998, among Plains
Resources Inc., Plains All American Inc. and Wingfoot Ventures Seven Inc.
(incorporated by reference to Exhibit 2(b) to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997).
2.2 Unit Transfer and Contribution Agreement, dated as of May 8, 2001, among
Sable Investments, L.P., Sable Holdings, L.P., James C. Flores, Plains
Resources Inc., Plains Holdings Inc. (formerly known as Plains All
American Inc.) and Plains Holdings LLC (formerly known as PAAI LLC)
(incorporated by reference to Exhibit 99.3 to the Company's Current
Report on Form 8-K filed on May 10, 2001).
2.3 Unit Transfer and Contribution Agreement, dated as of May 8, 2001, among
KAFU Holdings, LLC, Plains Resources Inc., Plains Holdings Inc. (formerly
known as Plains All American Inc.), and Plains Holdings LLC (formerly
known as PAAI LLC) (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K filed on May 10, 2001).
2.4 First Amendment, dated as of June 8, 2001, to Unit Transfer and
Contribution Agreement, dated as of May 8, 2001, among KAFU Holdings,
LLC, Plains Resources Inc., Plains Holdings Inc. (formerly known as
Plains All American Inc.), and Plains Holdings LLC (formerly known as
PAAI LLC) (incorporated by reference to Exhibit 99.9 to the Company's
Current Report on Form 8-K filed on June 13, 2001).
2.5 Unit Transfer and Contribution Agreement, dated as of May 8, 2001, among
E-Holdings III, L.P., Plains Resources Inc., Plains Holdings Inc.
(formerly known as Plains All American Inc). and Plains Holdings LLC
(formerly known as PAAI LLC) (incorporated by reference to Exhibit 99.4
to the Company's Current Report on Form 8-K filed on May 10, 2001).
2.6 First Amendment, dated as of June 8, 2001, to Unit Transfer and
Contribution Agreement, dated as of May 8, 2001, among E-Holdings III,
L.P., Plains Resources Inc., Plains Holdings Inc. (formerly known as
Plains All American Inc.) and Plains Holdings LLC (formerly known as PAAI
LLC) (incorporated by reference to Exhibit 99.10 to the Company's Current
Report on Form 8-K filed on June 13, 2001).
2.7 Unit Transfer and Contribution Agreement, dated as of June 8, 2001, among
Strome Hedgecap Fund, L.P., Plains Resources Inc., Plains Holdings Inc.
(formerly known as Plains All American Inc.) and Plains Holdings LLC
(formerly known as PAAI LLC) (incorporated by reference to Exhibit 99.5
to the Company's Current Report on Form 8-K filed on June 13, 2001).
2.8 Unit Transfer and Contribution Agreement, dated as of June 8, 2001, among
Mark E. Strome, Plains Resources Inc., Plains Holdings Inc. (formerly
known as Plains All American Inc.), and Plains Holdings LLC (formerly
known as PAAI LLC) (incorporated by reference to Exhibit 99.6 to the
Company's Current Report on Form 8-K filed on June 13, 2001).
2.9 Unit Transfer and Contribution Agreement, dated as of June 8, 2001, among
John T. Raymond, Plains Resources Inc., Plains Holdings Inc. (formerly
known as Plains All American Inc.) and Plains Holdings LLC (formerly
known as PAAI LLC) (incorporated by reference to Exhibit 99.7 to the
Company's Current Report on Form 8-K filed on June 13, 2001).
45
2.10 Contribution Agreement, dated as of June 8, 2001, among PAA Management,
L.P., Plains Resources Inc., Plains Holdings Inc. (formerly known as
Plains All American Inc.), and Plains Holdings LLC (formerly known as
PAAI LLC) (incorporated by reference to Exhibit 99.8 to the Company's
Current Report on Form 8-K filed on June 13, 2001).
3.1 Second Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3(a) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1995).
*3.2 Bylaws of the Company
3.3 Certificate of Designation, Preference and Rights of Series D Cumulative
Convertible Preferred Stock (incorporated by reference to Exhibit 3(c)
to the Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1997).
3.4 First Amendment to the Plains Resources Inc. Bylaws. (incorporated by
reference to Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q
for the three months ended June 30, 2001).
4.1 Indenture dated as of March 15, 1996, among the Company, the Subsidiary
Guarantors named therein and Texas Commerce Bank National Association,
as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006,
Series A and Series B (incorporated by reference to Exhibit 4(b) to the
Company's Form S-3 (Registration No. 333-1851)).
4.2 Indenture dated as of July 21, 1997, among the Company, the Subsidiary
Guarantors named therein and Texas Commerce Bank National Association,
as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006,
Series C and Series D (incorporated by reference to Exhibit 4 to the
Company's Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 1997).
4.3 Specimen Common Stock Certificate (incorporated by reference to Exhibit
4 to the Company's Form S-1 Registration Statement (Reg. No. 33-33986)).
4.4 Warrant dated November 12, 1997, to Shell Land & Energy Company for the
purchase of 150,000 shares of Common Stock (incorporated by reference to
Exhibit 4(d) to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1997).
4.5 Indenture dated as of September 15, 1999, among Plains Resources Inc.,
the Subsidiary Guarantors named therein and Chase Bank of Texas,
National Association, as Trustee (incorporated by reference to Exhibit
4(a) to the Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
4.6 Registration Rights Agreement dated as of September 22, 1999, among
Plains Resources Inc., the Subsidiary Guarantors named therein, J.P.
Morgan Securities Inc. and First Union Capital Markets Corp.
(incorporated by reference to Exhibit 4(b) to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended September 30, 1999).
4.7 Stock Purchase Agreement dated as of December 15, 1999, among Plains
Resources Inc. and the purchasers named therein (incorporated by
reference to Exhibit 4(g) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1999).
4.8 Amendment to Stock Purchase Agreement dated as of December 17, 1999,
among Plains Resources Inc. and the purchasers named therein
(incorporated by reference to Exhibit 4(h) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1999).
10.1 The Company's 1991 Management Options (incorporated by reference to
Exhibit 4.1 to the Company's Form S-8 Registration Statement (Reg. No.
33-43788)).
10.2 The Company's 1992 Stock Incentive Plan (incorporated by reference to
Exhibit 4.3 to the Company's Form S-8 Registration Statement (Reg. No.
33-48610)).
10.3 The Company's Amended and Restated 401(k) Plan (incorporated by
reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1996).
46
10.4 The Company's 1996 Stock Incentive Plan (incorporated by reference to
Exhibit 4 to the Company's Form S-8 Registration Statement (Reg. No.
333-06191)).
10.5 First Amendment to the Company's 1992 Stock Incentive Plan (incorporated
by reference to Exhibit 10(n) to the Company's Annual Report on Form 10-
K for the year ended December 31, 1996).
10.6 Second Amendment to the Company's 1992 Stock Incentive Plan
(incorporated by reference to Exhibit 10(b) to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 1997).
10.7 First Amendment to Plains Resources Inc. 1996 Stock Incentive Plan dated
May 21, 1998 (incorporated by reference to Exhibit 10(z) to the
Company's Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1998)
10.8 Third Amendment to Plains Resources Inc. 1992 Stock Incentive Plan dated
May 21, 1998 (incorporated by reference to Exhibit 10(aa) to the
Company's Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1998).
10.9 Purchase and Sale Agreement dated June 4, 1999, by and among the
Company, Chevron U.S.A., Inc., and Chevron Pipe Line Company
(incorporated by reference to Exhibit 10(h) to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended June 30, 1999).
10.10 Second Amendment to Plains Resources 1996 Stock Incentive Plan dated May
20, 1999 (incorporated by reference to Exhibit 10(q) to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended June 30,
1999).
10.11 Third Amendment to Plains Resources 1996 Stock Incentive Plan dated June
7, 2000 (incorporated by reference to Exhibit 10.23 to the Company's
Annual Report on Form 10-K for the Year Ended December 31, 2000).
10.12 Forms of Officer Stock Option Agreement (incorporated by reference to
Exhibits 4.1 and 4.2 to the Company's Form S-8 Registration Statement
(Registration No. 333-45562).
10.13 Contribution, Conveyance and Assumption Agreement among Plains All
American Pipeline, L.P. and certain other parties dated as of November
23, 1998 (incorporated by reference to Exhibit 10.03 to Annual Report on
Form 10-K for the Year Ended December 31, 1998 for Plains All American
Pipeline, L.P.).
10.14 Crude Oil Marketing Agreement among Plains Resources Inc., Plains
Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains
Marketing, L.P. dated as of November 23, 1998 (incorporated by reference
to Exhibit 10.07 to Annual Report on Form 10-K for the Year Ended
December 31, 1998 for Plains All American Pipeline, L.P.).
10.15 Omnibus Agreement among Plains Resources Inc., Plains All American
Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., and
Plains Holdings Inc. (formerly known as Plains All American Inc.) dated
as of November 23, 1998 (incorporated by reference to Exhibit 10.08 to
Annual Report on Form 10-K for the Year Ended December 31, 1998 for
Plains All American Pipeline, L.P.).
10.16 First Amendment to Contribution, Conveyance and Assumption Agreement
dated as of December 15, 1998 (incorporated by reference to Exhibit
10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998
for Plains All American Pipeline, L.P.).
10.17 Employment Agreement dated as of May 8, 2001 between Plains Resources
Inc. and James C. Flores (incorporated by reference to Exhibit 10.1 to
the Company's Quarterly Report on Form 10-Q for the three months ended
March 31, 2001).
10.18 Performance Stock Option Agreement dated as of May 8, 2001 between
Plains Resources Inc. and James C. Flores (incorporated by reference to
Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the
three months ended June 30, 2001).
47
10.19 Separation Agreement dated as of June 8, 2001 by and among Plains
Resources Inc., Plains Holdings Inc. (formerly known as Plains All
American Inc.), Plains All American GP LLC, Plains AAP, LP and Plains
All American Pipeline, L.P. (incorporated by reference to Exhibit 10.3
to the Company's Quarterly Report on Form 10-Q for the three months
ended June 30, 2001).
10.20 Pension and Employee Benefits Assumption and Transition Agreement, dated
as of June 8, 2001, by and between Plains Resources Inc., Plains
Holdings Inc. (formerly known as Plains All American Inc.) and Plains
All American GP LLC (incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the three months ended June
30, 2001).
10.21 Value Assurance Agreement dated as of June 8, 2001 by and among Plains
Resources Inc. and Sable Holdings L.P. and schedule of other Value
Assurance Agreements substantially identical thereto (incorporated by
reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q
for the three months ended June 30, 2001).
10.22 Contribution, Assignment and Amendment Agreement dated as of June 8,
2001, between Plains Holdings Inc. (formerly known as Plains All
American Inc.), Plains AAP, LP and Plains All American GP LLC.
(incorporated by reference to Exhibit 10.6 to the Company's Quarterly
Report on Form 10-Q for the three months ended June 30, 2001).
10.23 Registration Rights Agreement dated as of May 8, 2001, among Plains
Resources Inc. and James C. Flores. (incorporated by reference to
Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the
three months ended June 30, 2001).
10.24 Registration Rights Agreement dated as of June 8, 2001, among Plains
Resources Inc., Strome Hedgecap Fund L.P., Strome Series Fund 1, Strome
Series Fund 2 and Mark E. Strome. (incorporated by reference to Exhibit
10.8 to the Company's Quarterly Report on Form 10-Q for the three months
ended June 30, 2001).
10.25 Registration Rights Agreement dated as of June 8, 2001, among Plains All
American Pipeline, L.P., Sable Holdings, L.P., E-Holdings III, L.P.,
KAFU Holdings, LP, PAA Management, L.P., Mark E. Strome, Strome Hedgecap
Fund, L.P., John T. Raymond, and Plains Holdings Inc. (formerly known as
Plains All American Inc.) (incorporated by reference to Exhibit 10.9 to
the Company's Quarterly Report on Form 10-Q for the three months ended
June 30, 2001).
10.26 Registration Rights Agreement dated as of June 8, 2001, among Plains
Resources Inc. and EnCap Energy Capital Fund III, L.P., EnCap Energy
Capital Fund III-B, L.P., BOCP Energy Partners, L.P. and Energy Capital
Investment Company PLC. (incorporated by reference to Exhibit 10.10 to
the Company's Quarterly Report on Form 10-Q for the three months ended
June 30, 2001).
10.27 Registration Rights Agreement dated as of June 8, 2001, among Plains
Resources Inc. and Kayne Anderson Capital Advisors, L.P. (incorporated
by reference to Exhibit 10.11 to the Company's Quarterly Report on Form
10-Q for the three months ended June 30, 2001).
10.28 Amended and Restated Limited Liability Company Agreement of Plains All
American GP LLC, dated as of June 8, 2001. (incorporated by reference to
Exhibit 10.12 to the Company's Quarterly Report on Form 10-Q for the
three months ended June 30, 2001).
10.29 Amended and Restated Limited Partnership Agreement of Plains AAP, L.P,
dated June 8, 2001. (incorporated by reference to Exhibit 10.13 to the
Company's Quarterly Report on Form 10-Q for the three months ended June
30, 2001).
10.30 Plains Resources Inc. 2001 Stock Incentive Plan. (incorporated by
reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-
Q for the three months ended June 30, 2001).
10.31 Amendment and Transfer Agreement--Plains Resources Inc. 401(k) Plan and
Trust and the Plains All American 401(k) Plan and Trust (incorporated by
reference to Exhibit 10.16 to the Company's Quarterly Report on Form 10-
Q for the three months ended June 30, 2001).
48
10.32 Fifth Amended and Restated Credit Agreement dated as of October 5,
2001, by and among Plains Resources Inc., The Chase Manhattan Bank, as
Co-Agent for the Lenders, First Union National Bank, as agent for the
Lenders, and the Lenders named within, amending and restating the
Original Agreement (incorporated by reference to Exhibit 2.1 to the
Company's Quarterly Report on Form 10-Q for the three months ended
September 30, 2001).
10.33 Letter Agreement dated as of October 23, 2001 by and between Plains
Marketing, L.P. ("Plains Marketing") and Stocker Resources, L.P.
("Stocker"), regarding the Crude Oil Sales Agreement dated April 1,
2001 between Tosco Refining Co. and Plains Marketing for Stocker's
Arroyo Grande Crude Oil (incorporated by reference to Exhibit 2.2 to
the Company's Quarterly Report on Form 10-Q for the three months ended
September 30, 2001).
*10.34 Value Assurance Agreement, dated as of August 17, 2001, by and among
Plains Resources Inc. and First Union Investors, Inc.
*10.35 Employment Agreement dated June 7, 2001, between John T. Raymond and
Plains Resources Inc.
*10.36 Combination Incentive Stock Option and Nonqualified Stock Option
Agreement, dated as of June 7, 2001, between John T. Raymond and Plains
Resources Inc.
*10.37 Performance Stock Option Agreement, dated as of June 7, 2001, between
John T. Raymond and Plains Resources Inc.
*10.38 Employment Agreement dated June 7, 2001, between Jere C. Overdyke and
Plains Resources Inc.
*10.39 Combination Incentive Stock Option and Nonqualified Stock Option
Agreement, dated as of June 7, 2001, between Jere C. Overdyke and
Plains Resources Inc.
*10.40 Performance Stock Option Agreement, dated as of June 7, 2001, between
Jere C. Overdyke and Plains Resources Inc.
*10.41 Employment Agreement dated June 7, 2001, between Timothy T. Stephens
and Plains Resources Inc.
*10.42 Combination Incentive Stock Option and Nonqualified Stock Option
Agreement, dated as of June 7, 2001, between Timothy T. Stephens and
Plains Resources Inc.
*10.43 Performance Stock Option Agreement, dated as of June 7, 2001, between
Timothy T. Stephens and Plains Resources Inc.
*21.1 Subsidiaries of the Company
*23.1 Consent of PricewaterhouseCoopers LLP.
*23.2 Consent of H.J. Gruy and Associates, Inc.
*23.3 Consent of Netherland, Sewell and Associates, Inc.
*23.4 Consent of Ryder Scott Company.
- --------
* Filed herewith
Reports on Form 8-K
On November 8, 2001 we filed a Form 8-K with respect to Item 9, Regulation
FD Disclosures. The report discussed our fourth quarter 2001 estimates.
On December 19, 2001 we filed a Form 8-K with respect to Item 9, Regulation
FD Disclosures. The report discussed our year 2002 estimates.
49
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
PLAINS RESOURCES INC.
Date: March 21, 2002 /s/ Jere C. Overdyke, Jr.
By: _________________________________
Jere C. Overdyke, Jr.
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ James C. Flores Chairman of the Board and March 21, 2002
______________________________________ Chief Executive Officer
James C. Flores (Principal Executive
Officer)
/s/ Jerry L. Dees Director March 21, 2002
______________________________________
Jerry L. Dees
/s/ Tom H. Delimitros Director March 21, 2002
______________________________________
Tom H. Delimitros
/s/ William M. Hitchcock Director March 21, 2002
______________________________________
William M. Hitchcock
/s/ John H. Lollar Director March 21, 2002
______________________________________
John H. Lollar
/s/ D. Martin Phillips Director March 21, 2002
______________________________________
D. Martin Phillips
/s/ Robert V. Sinnott Director March 21, 2002
______________________________________
Robert V. Sinnott
/s/ J. Taft Symonds Director March 21, 2002
______________________________________
J. Taft Symonds
/s/ Jere C. Overdyke, Jr. Executive Vice President and March 21, 2002
______________________________________ Chief Financial Officer
Jere C. Overdyke, Jr. (Principal Financial
Officer)
/s/ Cynthia A. Feeback Senior Vice President-- March 21, 2002
______________________________________ Accounting and Treasurer
Cynthia A. Feeback (Principal Accounting
Officer)
50
PLAINS RESOURCES INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Financial Statements
Report of Independent Accountants....................................... F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000............ F-3
Consolidated Statements of Operations for the years ended December 31,
2001, 2000 and 1999.................................................... F-4
Consolidated Statements of Cash Flows for the years ended December 31,
2001, 2000 and 1999.................................................... F-5
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2001, 2000, and 1999...................................... F-6
Consolidated Statements of Changes in Non-redeemable Preferred Stock,
Common Stock and Other Stockholders' Equity for the years ended
December 31, 2001, 2000 and 1999....................................... F-7
Notes to Consolidated Financial Statements.............................. F-8
All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
F-1
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Stockholders of Plains Resources Inc.
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Plains Resources Inc. and its subsidiaries 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 1 to the consolidated financial statements, the
Company changed its method of accounting for its crude oil inventories in
connection with its adoption of Staff Accounting Bulletin No. 101, "Revenue
Recognition in Financial Statements", effective January 1, 2000.
As discussed in Note 3 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and
hedging activities in connection with its adoption of Statement of Financial
Accounting Standards No. 133 "Accounting for Derivative Instruments and
Hedging Activities", as amended effective January 1, 2001.
PricewaterhouseCoopers LLP
Houston, Texas
March 13, 2002
F-2
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
December 31,
---------------------
2001 2000
--------- ----------
ASSETS
Current Assets
Cash and cash equivalents............................. $ 1,179 $ 5,080
Accounts receivable................................... 20,039 357,790
Commodity hedging contracts and other derivatives..... 23,257 6,033
Inventory............................................. 6,721 54,844
Other current assets.................................. 1,527 11,662
--------- ----------
52,723 435,409
--------- ----------
Property and Equipment, at cost
Oil and natural gas properties--full cost method
Subject to amortization.............................. 900,898 762,245
Not subject to amortization.......................... 40,506 42,581
Crude oil pipeline, gathering and terminal assets..... -- 470,460
Other property and equipment.......................... 4,003 6,453
--------- ----------
945,407 1,281,739
Less allowance for depreciation, depletion and
amortization......................................... (437,982) (437,465)
--------- ----------
507,425 844,274
--------- ----------
Investment in Plains All-American Pipeline, L.P......... 64,626 --
--------- ----------
Other Assets............................................ 24,014 114,646
--------- ----------
$ 648,788 $1,394,329
========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable and other current liabilities........ $ 53,895 $ 399,773
Interest payable...................................... 8,286 13,536
Notes payable......................................... 511 1,811
--------- ----------
62,692 415,120
--------- ----------
Long-Term Debt
Bank debt............................................. 11,500 27,300
Bank debt of subsidiary............................... -- 320,000
Subordinated debt..................................... 269,539 277,543
Other................................................. 1,022 1,533
--------- ----------
282,061 626,376
--------- ----------
Other Long-Term Liabilities............................. 4,889 3,422
--------- ----------
Deferred Income Taxes................................... 44,294 --
--------- ----------
Commitments and Contingencies (Note 15)
Minority Interest in Plains All American Pipeline,
L.P.................................................... -- 162,271
--------- ----------
Cumulative Convertible Preferred Stock, stated at
liquidation preference................................. -- 50,000
--------- ----------
Non-redeemable Preferred Stock, Common Stock and Other
Stockholders' Equity
Series D Cumulative Convertible Preferred Stock, $1.00
par value, 46,600 shares authorized, issued and
outstanding, at stated value......................... 23,300 23,300
Series H Cumulative Convertible Preferred Stock, $1.00
par value, 175,000 shares authorized; nil and 169,571
shares issued and outstanding, at stated value....... -- 84,785
Common Stock, $0.10 par value, 50,000,000 shares
authorized; 27,677,411 and 18,746,612 shares issued
for 2001 and 2000.................................... 2,768 1,875
Additional paid-in capital............................ 268,520 139,203
Retained earnings (deficit)........................... 37,676 (88,410)
Accumulated other comprehensive income................ 13,930 --
Treasury stock, at cost............................... (91,342) (23,613)
--------- ----------
254,852 137,140
--------- ----------
$ 648,788 $1,394,329
========= ==========
See notes to consolidated financial statements.
F-3
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31,
-------------------------------
2001 2000 1999
-------- --------- ----------
Revenues
Crude oil and liquids....................... $186,476 $ 133,325 $ 111,128
Natural gas................................. 28,771 16,017 5,095
Marketing, transportation, storage and
terminalling............................... -- 6,425,644 10,796,998
Gain on sale of assets...................... -- 48,188 16,457
Other operating revenues.................... 473
-------- --------- ----------
215,720 6,623,174 10,929,678
-------- --------- ----------
Costs and Expenses
Production expenses......................... 71,192 62,140 55,645
General and administrative.................. 21,293 50,776 31,402
Marketing, transportation, storage and
terminalling............................... -- 6,292,615 10,689,308
Unauthorized trading losses and related
expenses................................... -- 7,963 166,440
Depreciation, depletion and amortization.... 28,921 47,221 36,998
-------- --------- ----------
121,406 6,460,715 10,979,793
-------- --------- ----------
Income (Loss) from Operations................. 94,314 162,459 (50,115)
Other Income (Expense)
Equity in earnings of Plains All American
Pipeline, L.P.............................. 18,540 -- --
Gains on Plains All American Pipeline, L.P.
unit transactions and public offerings..... 170,157 -- 9,787
Interest expense............................ (26,385) (55,828) (46,378)
Interest and other income................... 151 7,411 1,237
-------- --------- ----------
Income (Loss) Before Income Taxes, Minority
Interest, Extraordinary Items and Cumulative
Effect of Accounting Changes................. 256,777 114,042 (85,469)
Minority interest in Plains All American
Pipeline, L.P.............................. -- (42,535) 40,203
Income tax (expense) benefit:
Current.................................... (9,947) (1,020) 7
Deferred................................... (91,513) (24,563) 20,472
-------- --------- ----------
Income (Loss) Before Extraordinary Items and
Cumulative Effect of Accounting Changes...... 155,317 45,924 (24,787)
Extraordinary items, net of tax benefit and
minority interest.......................... -- (4,988) (544)
Cumulative effect of accounting changes, net
of tax benefit............................. (1,986) (121) --
-------- --------- ----------
Net Income (Loss)............................. 153,331 40,815 (25,331)
Cumulative preferred dividends.............. (27,245) (14,725) (10,026)
-------- --------- ----------
Income (Loss) Available to Common
Stockholders................................. $126,086 $ 26,090 $ (35,357)
======== ========= ==========
Basic Earnings Per Share
Income (loss) before extraordinary items and
cumulative effect of accounting changes.... $ 6.07 $ 1.75 $ (2.02)
Extraordinary items......................... -- (0.28) (0.03)
Cumulative effect of accounting changes..... (0.09) (0.01) --
-------- --------- ----------
Net income (loss)........................... $ 5.98 $ 1.46 $ (2.05)
======== ========= ==========
Diluted Earnings Per Share
Income (loss) before extraordinary items and
cumulative effect of accounting changes.... $ 4.82 $ 1.56 $ (2.02)
Extraordinary items......................... -- (0.17) (0.03)
Cumulative effect of accounting changes..... (0.07) -- --
-------- --------- ----------
Net income (loss)........................... $ 4.75 $ 1.39 $ (2.05)
======== ========= ==========
See notes to consolidated financial statements.
F-4
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
------------------------------
2001 2000 1999
-------- ---------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)............................. $153,331 $ 40,815 $(25,331)
Items not affecting cash flows from operating
activities:
Depreciation, depletion and amortization.... 28,921 47,221 36,998
Equity in earnings of Plains All American
Pipeline, L.P.............................. (18,540) -- --
Distributions received from Plains All
American Pipeline, L.P..................... 31,553 -- --
Noncash gains............................... (170,157) (48,188) (26,244)
Minority interest in income of a
subsidiary................................. -- 35,566 (40,203)
Loss on early extinguishment of debt, net of
tax........................................ --
Deferred income taxes....................... 91,513 21,297 (20,472)
Cumulative effect of adoption of SFAS 133... 1,986 -- --
Change in derivative fair value............. 1,227 -- --
Noncash compensation expense................ 4,514 2,682 1,013
Allowance for doubtful accounts............. -- 5,000 --
Other noncash items......................... 1,626 10,925 (61)
Change in assets and liabilities from
operating activities:
Accounts receivable and other............... 21,023 102,651 (226,438)
Inventory................................... 1,133 (13,977) 33,930
Accounts payable and other current
liabilities................................ (29,636) (143,453) 171,974
Pipeline linefill........................... -- (16,679) (3)
Other long-term liabilities................. 1,634 (8,000) 18,873
-------- ---------- --------
Net cash provided by (used in) operating
activities................................... 120,128 35,860 (75,964)
-------- ---------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration and developments
costs........................................ (131,785) (78,726) (77,899)
Additions to other property and assets........ (561) (3,133) (2,472)
Plains All American Pipeline, L.P.
acquisitions and assets...................... -- (12,219) (189,425)
Proceeds from the sale of Plains All American
Pipeline, L.P. units......................... 106,941 -- --
Investment in Plains All American Pipeline,
L.P.......................................... (3,978) -- --
Proceeds from asset sales..................... -- 224,261 3,400
-------- ---------- --------
Net cash provided by (used in) investing
activities................................... (29,383) 130,183 (266,396)
-------- ---------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt.................. 204,900 1,698,575 744,971
Proceeds from short-term debt................. -- 51,300 131,119
Proceeds from sale of common stock............ 9,169 2,301 5,542
Proceeds from issuance of preferred stock..... -- -- 50,000
Proceeds from issuance of common units, net... -- -- 50,759
Purchase of senior subordinated notes......... (7,550) -- --
Principal payments of long-term debt.......... (221,211) (1,799,186) (449,332)
Principal payments of short-term debt......... -- (108,719) (82,150)
Purchase of common stock...................... (67,729) (23,613) --
Costs incurred in connection with financing
arrangements................................. -- (6,748) (19,448)
Preferred stock dividends..................... (8,698) (13,409) (4,245)
Distributions to Plains All American Pipeline,
L.P. unitholders............................. -- (29,432) (22,201)
Other......................................... (102) (260) (971)
-------- ---------- --------
Net cash provided by (used in) financing
activities................................... (91,221) (229,191) 404,044
-------- ---------- --------
Net increase (decrease) in cash and cash
equivalents.................................. (476) (63,148) 61,684
Decrease in cash due to deconsolidation of
Plains All American Pipeline, L.P............ (3,425) -- --
Cash and cash equivalents, beginning of year.. 5,080 68,228 6,544
-------- ---------- --------
Cash and cash equivalents, end of year........ $ 1,179 $ 5,080 $ 68,228
======== ========== ========
See notes to consolidated financial statements.
F-5
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)
Year Ended December 31,
--------------------------
2001 2000 1999
-------- ------- --------
Net Income (Loss).................................. $153,331 $40,815 $(25,331)
Other Comprehensive Income:
Unrealized gains on derivatives:
Cumulative effect of accounting change, net of
taxes of $4,383................................. 6,856 -- --
Unrealized gains arising during the year, net of
taxes of $8,329................................. 12,803 -- --
Reclassification adjustment for gains realized in
net income, net of tax benefit of $1,921........ (2,989) -- --
-------- ------- --------
16,670 -- --
Minimum pension liability adjustment, net of tax
benefit of $272.................................. (421) -- --
-------- ------- --------
16,249 -- --
-------- ------- --------
Equity in other comprehensive income changes of
Plains All American Pipeline, L.P.
Cumulative effect of accounting change, net of
tax benefit of $1,496.......................... (2,340) -- --
Change in fair value of open hedging positions,
net of taxes of $5............................. 21 -- --
-------- ------- --------
(2,319) -- --
-------- ------- --------
Other Comprehensive Income......................... 13,930 -- --
-------- ------- --------
Comprehensive Income (Loss)........................ $167,261 $40,815 $(25,331)
======== ======= ========
See notes to consolidated financial statements.
F-6
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN NON-REDEEMABLE PREFERRED STOCK, COMMON
STOCK AND OTHER STOCKHOLDERS' EQUITY
(in thousands)
2001 2000 1999
---------------- ---------------- ---------------
Shares Amount Shares Amount Shares Amount
------ -------- ------ -------- ------ --------
Series D Cumulative
Convertible Preferred
Stock
Balance, beginning of
year................... 47 $ 23,300 47 $ 23,300 47 $ 21,946
Preferred stock
dividends.............. -- -- -- -- -- 1,354
------ -------- ------ -------- ------ --------
Balance, end of year.... 47 23,300 47 23,300 47 23,300
====== -------- ====== -------- ====== --------
Series H Cumulative
Convertible Preferred
Stock
Balance, beginning of
year................... 170 84,785 -- -- -- --
Shares issued upon
conversion of
redeemable preferred
stock.................. -- -- 170 84,785 -- --
Conversion of preferred
stock into common...... (170) (84,785) -- -- -- --
------ -------- ------ -------- ------ --------
Balance, end of year.... -- -- 170 84,785 -- --
====== -------- ====== -------- ====== --------
Common Stock
Balance, beginning of
year................... 18,747 1,875 17,924 1,792 16,882 1,688
Common stock issued upon
exercise of options,
warrants and other..... 1,041 103 557 56 943 94
Conversion of preferred
stock into common...... 7,889 790 266 27 99 10
------ -------- ------ -------- ------ --------
Balance, end of year.... 27,677 2,768 18,747 1,875 17,924 1,792
====== -------- ====== -------- ====== --------
Additional Paid-in Capital
Balance, beginning of
year................... 139,203 130,027 124,679
Common stock issued upon
exercise of options,
warrants and other..... 18,429 5,223 3,583
Conversion of preferred
stock into common...... 110,888 3,958 1,765
Redemption of preferred
stock.................. -- (5) --
-------- -------- --------
Balance, end of year.... 268,520 139,203 130,027
-------- -------- --------
Retained Earnings
(Deficit)
Balance, beginning of
year................... (88,410) (114,500) (79,143)
Preferred stock
dividends.............. (27,245) (14,725) (10,026)
Net income (loss)....... 153,331 40,815 (25,331)
-------- -------- --------
Balance, end of year.... 37,676 (88,410) (114,500)
-------- -------- --------
Accumulated Other
Comprehensive Income
Balance, beginning of
year................... -- -- --
Other comprehensive
income................. 13,930 -- --
-------- -------- --------
Balance, end of year.... 13,930 -- --
-------- -------- --------
Treasury Stock
Balance, beginning of
year................... (1,291) (23,613) -- -- -- --
Purchase of common
stock.................. (2,830) (67,729) (1,291) (23,613) -- --
------ -------- ------ -------- ------ --------
Balance, end of year.... (4,121) (91,342) (1,291) (23,613) -- --
====== -------- ====== -------- ====== --------
Total..................... $254,852 $137,140 $ 40,619
======== ======== ========
See notes to consolidated financial statements.
F-7
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1--Organization and Significant Accounting Policies
Organization
The consolidated financial statements of Plains Resources Inc. ("Plains",
"our", or "we") include the accounts of all wholly owned subsidiaries and for
periods prior to January 1, 2001, Plains All American Pipeline, L.P. ("PAA").
As discussed in Note 2, in June 2001 we reduced our interest in PAA from 54%
to 33% and as a result we no longer have the ability to exercise control over
the operations of PAA. Accordingly, effective January 1, 2001, our minority
interest investment in PAA is accounted for using the equity method of
accounting. Under the equity method, we no longer consolidate the assets,
liabilities and operating activities of PAA, but instead record our
proportionate share of PAA's net assets and results of operations. For periods
prior to January 1, 2001 the assets, liabilities and results of operations of
PAA are consolidated in our financial statements.
All significant intercompany transactions have been eliminated. Certain
reclassifications have been made to the prior year statements to conform to
the current year presentation.
We are an independent energy company that is currently 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. Prior to the reduction in our
interest in PAA, we also participated directly in the "Midstream" oil and gas
business, which consists of the marketing, transportation and terminalling of
crude oil. We continue to participate indirectly in the Midstream oil and gas
business through our minority interest in PAA. All of PAA's Midstream
activities are conducted in the United States and Canada.
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 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.
F-8
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 related
valuation allowance, (4) allowance for doubtful accounts receivable and (5)
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 two institutions and
at times may exceed federally insured limits. We periodically assess the
financial condition of the institutions and believe that any possible credit
risk is minimal.
Accounts Receivable, Net. At December 31, 2000, PAA had an allowance for
doubtful accounts receivable of $5.0 million that is reflected in the
consolidated balance sheet as a reduction of certain accounts receivable which
are included in Other Assets. At December 31, 2001 the allowance is reflected
in our investment in PAA.
Inventory. Plains' crude oil inventories are carried at cost. Materials and
supplies inventory is stated at the lower of cost or market with cost
determined on an average cost method. PAA's crude oil inventories are carried
at the lower of cost, adjusted for deferred gains or losses, or market value
using an average cost method.
Inventory consists of the following (in thousands):
December 31,
---------------
2001 2000
------- -------
Plains, excluding PAA
Crude oil................................................. $ 1,467 $ 3,347
Materials and supplies.................................... 5,254 4,716
------- -------
6,721 8,063
------- -------
PAA
Crude oil................................................. -- 45,914
Materials and supplies.................................... -- 867
------- -------
-- 46,781
------- -------
$ 6,721 $54,844
======= =======
F-9
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Other Assets. Other assets consists of the following (in thousands):
December 31,
----------------
2001 2000
------- --------
Plains, excluding PAA
Deferred tax asset....................................... $ -- $ 47,974
Land..................................................... 8,853 8,853
Commodity hedging contracts and other derivatives........ 5,661 --
Debt issue costs, net.................................... 3,566 7,249
Other.................................................... 5,934 3,318
------- --------
24,014 67,394
------- --------
PAA
Pipeline linefill, at cost............................... -- 34,312
Debt issue costs, net.................................... -- 7,259
Long-term receivable, net................................ -- 5,000
Other.................................................... -- 681
------- --------
-- 47,252
------- --------
$24,014 $114,646
======= ========
Costs incurred in connection with the issuance of long-term debt are
capitalized and amortized using the straight-line method over the term of the
related debt. Use of the straight-line method does not differ materially from
the "effective interest" method of amortization.
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.
Revenue Recognition. Oil and gas revenue from our interests in producing
wells is recognized when the production is delivered and the title transfers.
Transportation costs incurred in connection with such operations, which are
immaterial, are reflected as a reduction of sales revenues.
PAA's gathering and marketing revenues are accrued at the time title to the
product sold transfers to the purchaser, which occurs upon receipt of the
product by the purchaser, and purchases are accrued at the time title to the
product purchased transfers to PAA, which occurs upon our receipt of the
product. PAA's terminalling and storage revenues are recognized at the time
service is performed and revenues for the transportation of crude oil are
recognized based upon regulated and non-regulated tariff rates and the related
transported volumes.
Derivative Financial Instruments (Hedging). We utilize various derivative
instruments to reduce our exposure to decreases in the market price of crude
oil. The derivative instruments consist primarily of crude oil swap and option
contracts entered into with financial institutions. We also utilize interest
rate swaps to manage the interest rate exposure on our long-term debt.
F-10
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Stock Options. We have elected to follow Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25") and
related interpretations in accounting for our employee stock options. Under
APB 25, no compensation expense is recognized when the number of options to be
issued is known and the exercise price of the options equals the fair value
(market price) of the underlying stock on the date of grant.
Sale of Units by PAA. When PAA sells additional units to a third party,
resulting in a change in our percentage ownership interest, we recognize a
gain or loss in our consolidated statement of operations if the selling price
per unit is more or less than our average carrying amount per unit.
Recent Accounting Pronouncements. The following Statements of Financial
Accounting Standards ("SFAS's") 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.
In the fourth quarter of 2000, we adopted Securities and Exchange
Commission ("SEC") Staff Accounting Bulletin 101, "Revenue Recognition in
Financial Statements" ("SAB 101"). As a result, we record revenue from crude
oil production in the period it is sold as opposed to when it is produced and
carry any unsold production as inventory valued at historical cost. The total
effect of implementing SAB 101 was to reduce reported sales volumes by 144,000
barrels for 2000 and net income for the year by $175,000, including a $121,000
reduction for the cumulative effect of prior years. The effect of this change
in accounting for crude oil inventories on prior periods was deminimus.
Note 2--Investment in Plains All American Pipeline, L.P.
In a series of transactions on June 8, 2001, we sold a portion of our
interest in PAA to a group of investors and certain members of PAA management
for aggregate consideration of approximately $155.2 million (consisting of
$110.0 million in cash and $45.2 million in Series F Cumulative Convertible
Preferred Stock [the "Series F Preferred Stock"]) and recognized a pre-tax
gain of $128.3 million in connection with this sale. In addition, certain
holders of the Series F Preferred Stock and
F-11
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Series H Convertible Preferred Stock (the "Series H Preferred Stock")
converted their shares into shares of our common stock. We sold (i) 5.2
million Subordinated Units of PAA (the "Subordinated Units") for $69.5 million
in cash and the redemption of 23,108 shares of Series F Preferred Stock,
valued at $45.2 million; and (ii) an aggregate 54% ownership interest in the
general partner of PAA for $40.5 million in cash. In addition, the investor
group and certain other stockholders converted 26,892 shares of Series F
Preferred Stock and 132,022 shares of Series H Preferred Stock into a total of
6.6 million shares of our common stock. On September 5, 2001, pursuant to an
option granted as part of the June 8, 2001 transactions, certain members of
the executive management of PAA acquired an aggregate additional 2% ownership
interest in the general partner of PAA for $1.5 million in cash and notes,
further reducing our ownership in the general partner of PAA to 44%. We
recognized a gain of $1.1 million as a result of this transaction. These
transactions in the aggregate are hereinafter referred to as "the
Transactions".
As a result of the Transactions, all of the Series F Preferred Stock and
all but approximately 36,000 shares of the Series H Preferred Stock were
retired or converted. The remaining outstanding shares of the Series H
Preferred Stock converted to 1.2 million shares of our common stock during the
third quarter. Also as a result of the Transactions, certain of our employees
received transaction-related bonuses and other payments and vested in benefits
in accordance with the terms of certain of our employee benefit plans.
The excess of the fair value of the Series F Preferred stock as
consideration for the PAA Units over the carrying value of the Series F
Preferred Stock ($21.4 million) is deemed to be a dividend to preferred
stockholders and is deducted in determining the income available to common
stockholders for the purpose of determining basic and fully diluted earnings
per share. In connection with the conversion of the Series F Preferred Stock
into common stock, we made a $2.5 million inducement payment representing a
20% premium to the amount of dividends that would accrue on the Series F
Preferred Stock between the closing of the Transactions and the first date we
could potentially cause such conversion. Such amounts are included in
preferred dividends.
The Subordinated Units are subordinated in right to distributions from PAA
and are not publicly traded. However, PAA's partnership agreement provides
that, if certain financial tests are met, the Subordinated Units (including
those retained by us) will convert into common units on a one-for-one basis
commencing in 2003. In connection with the Transactions, we entered into Value
Assurance Agreements with such purchasers of the Subordinated Units under the
terms of which we will pay the purchasers an amount per fiscal year, payable
on a quarterly basis, equal to $1.85 per unit less the actual amount
distributed during that year. The Value Assurance Agreements expire upon the
earlier of (a) the conversion of the Subordinated Units to common units or (b)
June 8, 2006. In the first quarter of 2002 PAA paid a distribution of $0.5125
per unit ($2.05 annualized).
Also in connection with the Transactions, we entered into a separation
agreement with PAA pursuant to which, among other things, (a) we agreed to
indemnify PAA, the general partner of PAA, and the subsidiaries of PAA against
any losses or liabilities resulting from (i) the operation of the upstream
business or (ii) federal or state securities laws, or the regulations of any
self-regulatory authority, or other similar claims resulting from acts or
omissions by us, our subsidiaries, PAA, or PAA's subsidiaries on or before the
closing of the Transactions; and (b) PAA agreed to indemnify us and our
subsidiaries against any losses or liabilities resulting from the operation of
the midstream business. We also entered into a pension and employee benefits
assumption and transition agreement pursuant to which the general partner of
PAA and us agreed to the transition of certain employees to such general
partner, the provision of certain benefits with respect to such transfer, and
the provision of other transition services by us.
F-12
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In addition, we agreed to contribute 287,500 of our Subordinated Units to
PAA's general partner to be used for option grants to officers and key
employees. These Subordinated Units are considered to be a contribution to the
general partner and we will receive no reimbursement for such units. Also, at
the time of the Transactions, certain of our employees, who are now employees
of PAA's general partner, held "in-the-money" but unvested Plains stock
options which were subject to forfeiture due to the transfer of employment. We
agreed to substitute, based on the present value of such options, a contingent
grant of 51,000 Subordinated Units that vest on the same schedule the stock
options were to vest. In connection with these substitute options, we
recognized $0.5 million in noncash compensation expense in 2001.
In May 2001, PAA issued 4.0 million common units in a public equity
offering. We recognized a gain of $19.6 million resulting from the increase in
the book value of our equity in PAA to reflect our proportionate share of the
increase in the underlying net assets of PAA due to the sale of the units. In
October 2001, PAA issued 4.5 million Common Units in a public offering. As a
result of the offering, we made a general partner capital contribution of
approximately $1.0 million, and our aggregate ownership interest in PAA was
reduced to approximately 29%. We recognized a gain of approximately $19.2
million resulting from the increase in book value of our equity in PAA to
reflect our proportionate share of the increase in the underlying net assets
of PAA resulting from this public offering.
At March 31, 2001, our aggregate ownership interest in PAA was
approximately 54%. Following the sale of common units by PAA in the
aforementioned public equity offerings and the Transactions, our aggregate
ownership interest in PAA was approximately 29%. At December 31, 2001, our
aggregate 29% ownership in PAA consisted of: (i) a 44% ownership interest in
the 2% general partner interest and incentive distribution rights, (ii) 45%,
or approximately 4.5 million, of the Subordinated Units and (iii) 24% or
approximately 7.9 million of the common units (including approximately 1.3
million Class B common units).
The following table presents summarized financial statement information of
PAA (in thousands of dollars):
Year Ended
December 31,
2001
------------
Revenues........................................................ $6,868,215
Cost of sales and operations.................................... 6,725,954
Gross margin.................................................... 142,261
Operating income................................................ 71,368
Income before cumulative effect of accounting change............ 43,671
Net income...................................................... 44,179
At
December 31,
2001
------------
Current assets.................................................. $ 558,082
Property and equipment, net..................................... 604,919
Other assets.................................................... 98,250
Total assets.................................................... 1,261,251
Current liabilities............................................. 505,160
Long-term debt.................................................. 351,677
Other long-term liabilities..................................... 1,617
Partners' capital............................................... 402,797
Total liabilities and partners' capital......................... 1,261,251
F-13
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 3--Derivative Instruments and Hedging Activities
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 accumulated
Other Comprehensive Income ("OCI"), a component of 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 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 the year ended December 31, 2001 include a $3.4 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. We
also utilize interest rate swaps and collars to manage the interest rate
exposure on our long-term debt. In October
F-14
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
2001 we entered into a three-year interest rate swap agreement, fixing at
5.29% the interest rate on $7.5 million of borrowing under our revolving
credit facility. At December 31, 2001, we had the following open crude oil
hedge positions:
Barrels Per
Day
------------
2002 2003
------ -----
Puts
Average price $20.00/bbl...................................... 2,000 --
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 $4.5 million in OCI, representing the cumulative
effect of an accounting change to recognize at fair value all cash flow
derivatives, including our equity in the cash flow derivatives of PAA. We
recorded cash flow hedge derivative assets and liabilities of $20.6 million
and $18.1 million, respectively, and a net-of-tax non-cash charge of $2.0
million was recorded in earnings as a cumulative effect adjustment.
For the year ended December 31, 2001, net unrealized gains of $9.8 million
were added to OCI and the fair value of open positions increased $16.2
million. At December 31, 2000, we had an interest rate swap arrangement to
protect interest rate fluctuations on a portion of our outstanding debt. The
position was terminated prior to maturity and as a result $0.6 million related
to such position was relieved from OCI when the debt was repaid in June 2001.
At December 31, 2001, net unrealized gains on our option and swap contracts
included in OCI was $16.7 million. The related assets and liabilities were
included in commodity hedging contracts and other derivatives ($21.8 million),
other assets ($5.7 million), and deferred income taxes ($10.8 million).
Additionally, OCI includes our $2.3 million net of tax equity in the
unrealized OCI losses of PAA. As of December 31, 2001, $13.2 million of
deferred net gains on derivative instruments recorded in OCI are expected to
be reclassified to earnings during the next twelve-month period.
F-15
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 4--Long-Term Debt and Credit Facilities
Short-term debt and long-term debt consists of the following at December
31, 2001 and 2000 (in thousands):
2001 2000
----------------- -----------------
Current Long-Term Current Long-Term
------- --------- ------- ---------
Plains
Revolving credit facility, bearing
interest at 4.2% and 8.4%, at December
31, 2001 and 2000, respectively......... $ -- $ 11,500 $ -- $ 27,300
10.25% Senior Subordinated Notes, due
2006, net of repurchased notes of $7.55
million and nil, and unamortized premium
of $2.1 million and $2.5 million at
December 31, 2001 and 2000,
respectively............................ -- 269,539 -- 277,543
Other long-term debt..................... 511 1,533 511 2,044
---- -------- ------ --------
511 282,572 511 306,887
PAA
Letter of credit facility and hedged
inventory facility, bearing interest at
a weighted average interest rate of
8.4%.................................... -- -- 1,300 --
Plains Marketing, L.P. revolving credit
facility, bearing interest at 9.2%, at
December 31, 2000....................... -- -- -- 320,000
---- -------- ------ --------
$511 $282,572 $1,811 $626,887
==== ======== ====== ========
Aggregate total maturities of long-term debt in the next five years are as
follows: 2002--$0.5 million; 2003--$1.9 million; 2004--$6.3 million; 2005--
$4.3 million; and 2006--$267.5 million.
Plains Long-Term Debt and Credit Facilities
Revolving Credit Facility
We have a $225.0 million revolving credit facility with a group of banks.
The revolving credit facility is guaranteed by all of our upstream
subsidiaries and is collateralized by our upstream oil and natural gas
properties and those of the guaranteeing subsidiaries and the stock of all the
upstream subsidiaries. The borrowing base under the revolving credit facility
at December 31, 2001, is $225.0 million and is subject to redetermination from
time to time by the lenders in good faith, in the exercise of the lenders'
sole discretion, and in accordance with customary practices and standards in
effect from time to time for crude oil and natural gas loans to borrowers
similar to our company. Our borrowing base may be affected from time to time
by the performance of our oil and natural gas properties and changes in oil
and natural gas prices. We incur a commitment fee of 3/8% per annum on the
unused portion of the borrowing base. In addition, we pay a fee of 1 3/8% per
annum of the face amount of letters of credit that are issued under our
revolving credit facility. The revolving credit facility, as amended,
terminates on July 1, 2003, at which time the remaining outstanding balance
converts to a term loan, repayable in eight equal quarterly installments
commencing October 1, 2003, with a final maturity of July 1, 2005. The
revolving credit facility bears interest, at our option, of either LIBOR plus
1 3/8% or the Base Rate (as defined therein). At December 31, 2001, letters of
credit of $0.6 million were outstanding under the revolving credit facility.
F-16
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The revolving credit facility contains covenants which, among other things,
limit the payment of cash dividends on common stock, limit repurchases of
common stock, limit the amount of consolidated debt, limit our ability to make
certain loans and investments and provide that we must maintain a specified
relationship between current assets and current liabilities. At December 31,
2001 we were in compliance with such covenants and could have borrowed the
full $225.0 million available under the facility.
Under the terms of the revolving credit facility we can purchase any
combination of our own common stock, our senior subordinated notes and PAA
common units and pay cash dividends on our common stock (up to $30.0 million)
up to a total of $150.0 million. At December 31, 2001 we had $117.5 million
remaining under this limit. The Board of Directors, subject to the $150.0
million limit, has authorized the purchase of up to eight million shares of
our common stock, our senior subordinated notes and PAA units in the open
market from time to time as market conditions are deemed favorable.
In October 2001 we entered into a three-year interest rate swap agreement,
fixing the interest rate on $7.5 million of borrowing under our revolving
credit facility at 5.29%
10.25% Senior Subordinated Notes Due 2006
At December 31, 2001 we had $267.5 million principal amount of 10.25%
Senior Subordinated Notes Due 2006 (the "10.25% Notes") outstanding, bearing a
coupon rate of 10.25%. In 1996 we issued $150.0 million principal amount at
99.38% of par to yield 10.35%. In 1997 $50.0 million principal amount was
issued at approximately 107% of par and in 1999 $75.0 million principal amount
was issued at approximately 101% of par. In 2001 we repurchased $7.5 million
principal amount at 99.5% of par.
The 10.25% Notes are redeemable, at our option at 105.13% of the principal
amount through March 15, 2002, at 103.42% on or after March 15, 2002, at
101.71% on or after March 15, 2003 and at 100% on or after March 15, 2004
plus, in each case, accrued interest to the date of redemption.
The Indenture contains covenants that include, but are not limited to,
covenants that: (1) limit the incurrence of additional indebtedness; (2) limit
certain investments; (3) limit restricted payments; (4) limit the disposition
of assets; (5) limit the payment of dividends and other payment restrictions
affecting subsidiaries; (6) limit transactions with affiliates; (7) limit the
creation of liens; and (8) restrict mergers, consolidations and transfers of
assets. In the event of a Change of Control and a corresponding Rating
Decline, as both are defined in the Indenture, we will be required to make an
offer to repurchase the 10.25% Notes at 101% of the principal amount thereof,
plus accrued and unpaid interest to the date of the repurchase.
The 10.25% Notes are unsecured general obligations and are subordinated in
right of payment to all our existing and future senior indebtedness and are
guaranteed by certain of our Upstream subsidiaries on a full, unconditional,
joint and several basis.
PAA Credit Facilities
At December 31, 2000, PAA's bank credit agreements consisted of a $400.0
million senior secured revolving credit facility and a $300.0 million senior
secured letter of credit and borrowing facility, both of which were secured by
substantially all of PAA's assets. PAA's credit facilities were nonrecourse to
us.
F-17
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 5--Unauthorized Trading Losses
In November 1999, we discovered that a former employee of PAA had engaged
in unauthorized trading activity, resulting in losses of approximately $174.0
million, including estimated associated costs and legal expenses.
Approximately $7.1 million of the unauthorized trading losses were recognized
in 1998 and the remainder in 1999. In 2000, we recognized an additional $8.0
million charge for litigation related to the unauthorized trading losses.
Note 6--PAA Acquisitions and Dispositions
Scurlock Acquisition
On May 12, 1999, PAA completed the acquisition of Scurlock Permian LLC
("Scurlock") and certain other pipeline assets from Marathon Ashland Petroleum
LLC. Including working capital adjustments and closing and financing costs,
the cash purchase price was approximately $141.7 million.
Financing for the Scurlock acquisition was provided through: (i) borrowings
of approximately $92.0 million under a PAA bank facility; (ii) the sale to the
general partner of 1.3 million Class B common units of PAA for a total cash
consideration of $25.0 million, or $19.125 per unit, the price equal to the
market value of PAA's common units on May 12, 1999; and (iii) a $25.0 million
draw under PAA's existing revolving credit agreement.
The funds for the purchase of the Class B units by the general partner were
provided by a capital contribution from us. We financed our capital
contribution through our revolving credit facility.
The assets, liabilities and results of operations of Scurlock are included
in our consolidated financial statements effective May 1, 1999. The Scurlock
acquisition has been accounted for using the purchase method of accounting and
the purchase price was allocated in accordance with Accounting Principles
Board Opinion No. 16, Business Combinations ("APB 16") as follows (in
thousands):
Crude oil pipeline, gathering and terminal assets.................. $125,120
Other property and equipment....................................... 1,546
Pipeline linefill.................................................. 16,057
Other assets (debt issue costs).................................... 3,100
Other long-term liabilities (environmental accrual)................ (1,000)
Net working capital items.......................................... (3,090)
--------
Cash paid.......................................................... $141,733
========
F-18
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Pro Forma Results for the Scurlock Acquisition
The following unaudited pro forma data is presented to show pro forma
revenues, net loss and basic and diluted net loss per share for the year ended
December 31, 1999 as if the Scurlock acquisition, which was effective May 1,
1999, had occurred on January 1, 1999 (in thousands, except per share data):
Revenues....................................................... $11,323,577
===========
Net loss....................................................... $ (27,147)
===========
Net loss per share available to common stockholders:
Basic and diluted............................................ $ (2.15)
===========
All American Pipeline Linefill Sale and Asset Disposition
In March 2000, PAA sold the segment of the All American Pipeline that
extends from Emidio, California to McCamey, Texas to a unit of El Paso
Corporation for $129.0 million. PAA realized net proceeds of approximately
$124.0 million after the associated transaction costs and estimated costs to
remove some equipment. The proceeds from the sale were used to reduce the
outstanding debt of PAA. PAA recognized a gain of approximately $20.1 million
in connection with the sale.
PAA had suspended shipments of crude oil on this segment of the pipeline in
November 1999. At that time, PAA owned approximately 5.2 million barrels of
crude oil in the segment of the pipeline. PAA sold this crude oil from
November 1999 to February 2000 for net proceeds of approximately $100.0
million and recognized gains of approximately $28.1 million and $16.5 million
in 2000 and 1999, respectively, in connection with the sale of the linefill.
Note 7--Redeemable Preferred Stock
Series F Cumulative Convertible Preferred Stock
On December 14, 1999, we sold in a private placement 50,000 shares of
Series F Preferred Stock for $50.0 million As discussed in Note 2, in
conjunction with the Transactions we redeemed 23,108 shares of the Series F
Preferred Stock and the remaining 26,892 shares were converted into 2.2
million shares of our common stock. Each share of the Series F Preferred Stock
had a stated value of $1,000 per share and bore a dividend of 10% per annum.
Dividends were payable semi-annually in either cash or additional shares of
Series F Preferred Stock at our option and were cumulative from the date of
issue. Dividends paid in additional shares of Series F Preferred Stock were
limited to an aggregate of six dividend periods. Each share of Series F
Preferred Stock was convertible into 81.63 shares of common stock (an initial
effective conversion price of $12.25 per share). At December 31, 2000 there
were 50,000 shares of Series F Preferred Stock outstanding.
The Series F Preferred Stock is stated at liquidation preference on the
consolidated balance sheet at December 31, 2000. Liquidation preference
represents the number of shares outstanding multiplied by the stated value of
the shares. Any unpaid cash dividends are accrued in accounts payable and
other current liabilities on the consolidated balance sheet.
Series E and Series G Convertible Preferred Stock
In July 1998 we issued $85.0 million of Series E Cumulative Convertible
Preferred Stock (the "Series E Preferred Stock"). Each share of the Series E
Preferred Stock had a stated value of $500 per share and bore a dividend of
9.5% per annum. Dividends were payable semi-annually in either
F-19
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
cash or additional shares of Series E Preferred Stock at our option and were
cumulative from the date of issue. Each share of Series E Preferred Stock was
convertible into 27.78 shares of common stock (an initial effective conversion
price of $18.00 per share). In February 2000 each outstanding share of the
Series E Preferred Stock was exchanged for a share of a new Series G
Cumulative Convertible Preferred Stock (the "Series G Preferred Stock") which
had a conversion price of $15.00 per share. Other than the reduced conversion
price, the terms of the Series G Preferred Stock were substantially identical
to those of the Series E Preferred Stock
In December 2000, we exchanged or redeemed all of the shares of Series G
Preferred Stock that had not been previously converted into shares of common
stock. We exchanged 169,571 shares of Series G Preferred Stock for 169,571
shares of Series H Preferred Stock and in connection therewith paid $2.0
million, the amount equal to accrued dividends, and converted 1,825 shares of
Series G Preferred Stock into 62,226 shares of common stock. The remaining 213
shares of the Series G Preferred Stock were redeemed at 105% of stated value
in accordance with the original terms. In connection with that redemption, we
paid $114,000 consisting of $112,000 for stated value and $2,000 for accrued
and unpaid dividends.
Note 8--Common Stock and Non-Redeemable Preferred Stock
Common and Preferred Stock
We have authorized capital stock consisting of 50.0 million shares of
common stock, $0.10 par value, and 2 million shares of preferred stock, $1.00
par value. At December 31, 2001 and 2000, there were 23.6 million shares and
17.5 million shares of common stock outstanding (net of treasury shares),
respectively, and 46,600 and 266,171 shares of preferred stock outstanding.
Stock Warrants and Options
At December 31, 2001, we had a warrant outstanding which entitles the
holder thereof to purchase an aggregate 150,000 shares of common stock at
$25.00 per share expiring in 2002. We have various stock option plans for our
employees and directors (see Note 14).
Series D Cumulative Convertible Preferred Stock
In November 1997, we issued 46,600 shares of Series D Cumulative
Convertible Preferred Stock (the "Series D Preferred Stock"). The Series D
Preferred Stock has an aggregate stated value of $23.3 million and is
redeemable at our option at 140% of stated value. If not previously redeemed
or converted, the Series D Preferred Stock will automatically convert into
932,000 shares of common stock in 2012. Each share of the Series D Preferred
Stock has a stated value of $500 and is convertible into common stock at a
ratio of $25.00 of stated value for each share of Common Stock to be issued.
The Series D Preferred Stock bears an annual dividend of $30.00 per share.
Series H Convertible Preferred Stock
In December 2000, we exchanged 169,571 shares of Series G Preferred Stock
for 169,571 shares of Series H Preferred Stock. The Series H Preferred Stock
was convertible into the same number of shares of common stock as the Series G
Preferred Stock (33.33 shares of common), but did not bear a dividend and did
not contain a mandatory redemption feature. As discussed in Note 2, in
conjunction with the Transactions, 132,022 shares of the Series H Preferred
Stock were converted into 4.4 million shares of our common stock. In the third
quarter of 2001 the remaining outstanding shares were converted into 1.2
million common shares.
F-20
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Treasury Stock
Our Board of Directors has authorized the repurchase of up to eight million
shares of our common stock. In 2001, we repurchased 2.8 million common shares
at a cost of $67.7 million, and in 2000 we repurchased 1.3 million common
shares at a cost of $23.6 million.
Note 9--Earnings Per Share
The following is a reconciliation of the numerators and the denominators of
the basic and diluted earnings per share computations for income (loss) from
continuing operations before extraordinary items and the cumulative effect of
accounting change for the years ended December 31, 2001, 2000 and 1999 (in
thousands, except per share amounts):
For the Year Ended December 31,
--------------------------------------------------------------------------------------------------
2001 2000 1999
-------------------------------- -------------------------------- --------------------------------
Per Per Per
Income Shares Share Income Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------- ------------- ------ ----------- ------------- ------ ----------- ------------- ------
Income (loss) before
extraordinary item
and cumulative
effect of
accounting change.. $155,317 $45,924 $(24,787)
Less: preferred
stock dividends.... (27,245) (14,725) (10,026)
-------- ------- --------
Income (loss)
available to common
stockholders....... 128,072 21,090 $6.07 31,199 17,845 $1.75 (34,813) 17,262 $(2.02)
======== ======= ========
Effect of dilutive
securities:
Preferred Stock
conversion......... 3,365 5,280 14,725 10,673
Employee stock
options and
warrants........... -- 874 -- 855 -- --
-------- ------ ------- ------ -------- ------
Income (loss)
available to common
stockholders
assuming dilution.. $131,437 27,244 $4.82 $45,924 29,373 $1.56 $(34,813) 17,262 $(2.02)
======== ====== ===== ======= ====== ===== ======== ====== ======
In 1999, we recorded a net loss and our options and warrants were not
included in the computations of diluted earnings per share because their
assumed conversion was antidilutive. In addition, our preferred stock that was
outstanding at December 31, 1999 was convertible into 7.0 million shares of
common stock but was not included in the computation of diluted earnings per
share in 1999 because the effect was antidilutive. See Note 14 for additional
information concerning outstanding options and warrants.
F-21
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 10--Income Taxes
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:
Net operating losses...................................... $ 18,142 $64,370
Percentage depletion...................................... 2,450 2,450
Tax credit carryforwards.................................. 8,988 4,662
Excess outside tax basis over outside book basis.......... 9,979 24,504
Other..................................................... 4,926 1,669
-------- -------
44,485 97,655
Deferred tax liabilities:
Net oil & gas acquisition, exploration and development
costs.................................................... (63,693) (42,946)
Commodity hedging contracts and other .................... (9,028) --
-------- -------
Net deferred tax asset (liability)........................ (28,236) 54,709
Valuation allowance....................................... (2,450) (2,555)
-------- -------
(30,686) 52,154
-------- -------
Foreign
Excess outside tax basis over outside book basis.......... 466 --
-------- -------
States
Deferred tax liability...................................... (14,074) (4,180)
-------- -------
Net deferred tax assets (liability)......................... $(44,294) $47,974
======== =======
At December 31, 2001, we have carryforwards of approximately $51.8 million
of regular tax net operating losses ("NOL"), $7.0 million of statutory
depletion, $5.1 million of alternative minimum tax credits and $3.8 million of
enhanced oil recovery credits. At December 31, 2001, we also had approximately
$34.1 million of alternative minimum tax NOL carryforwards available as a
deduction against future alternative minimum tax income. The NOL carryforwards
expire in 2019.
Set forth below is a reconciliation between the income tax provision
(benefit) computed at the United States statutory rate on income (loss) before
income taxes and the income tax provision in the accompanying consolidated
statements of operations (in thousands):
Year Ended December 31,
---------------------------
2001 2000 1999
-------- ------- --------
U.S. federal income tax provision at statutory
rate............................................ $ 89,872 $25,028 $(15,842)
State income taxes, net of federal benefit....... 10,050 2,018 (1,298)
Foreign income taxes, net of federal benefit..... 916 -- --
Full cost ceiling test limitation................ -- -- (3,617)
Other............................................ 622 (1,463) 278
-------- ------- --------
Income tax expense (benefit) on income before
extraordinary item.............................. 101,460 25,583 (20,479)
Income tax benefit allocated to extraordinary
item............................................ -- (3,190) (293)
Income tax benefit allocated to cumulative effect
of accounting change............................ (1,270) (76) --
-------- ------- --------
Income tax (benefit) provision................... $100,190 $22,317 $(20,772)
======== ======= ========
F-22
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of our beneficial ownership within a three-year
period (an "Ownership Change") will place an annual limitation on our ability
to utilize our existing tax carryforwards. Under the Final Treasury
Regulations issued by the Internal Revenue Service, we do not believe that an
Ownership Change has occurred as of December 31, 2001.
Note 11--Early Extinguishment of Debt
In 2000, PAA recognized a $15.2 million extraordinary loss ($5.0 million
net of minority interest of $7.0 million and deferred income taxes of $3.2
million) consisting primarily of unamortized debt issue costs related to the
refinancing of PAA's credit facilities. In addition, interest and other income
for 2000 includes $4.4 million of previously deferred net gains from interest
rate swaps terminated as a result of the debt extinguishment. In 1999, PAA
recognized a $1.5 million extraordinary loss ($0.5 million net of minority
interest of $0.7 million and deferred tax of $0.3 million) related to the
write-off of certain debt issue costs and penalties associated with the
prepayment of debt.
Note 12--Related Party Transactions
Reimbursement of Expenses of the General Partner and Its Affiliates
Prior to the Transactions, the general partner of PAA was a wholly-owned
subsidiary of Plains. As a result of the Transactions another entity was named
general partner and our ownership in that entity is 44%. Previously, we had
sole responsibility for conducting PAA's business and managing its operations.
We did not receive any management fee or other compensation in connection with
the management of PAA's business, but were reimbursed for all direct and
indirect expenses incurred on its behalf. For the period from January 1, 2001
to June 8, 2001, and for the years ended December 31, 2000 and 1999, we were
reimbursed approximately $31.2 million, $63.8 million and $44.7 million,
respectively, for direct and indirect expenses on PAA's behalf. The reimbursed
costs consisted primarily of employee salaries and benefits. PAA does not
employ any persons to manage its business. These functions are provided by
employees of the general partner.
Crude Oil Marketing Agreement
PAA 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. For the years ended December 31, 2001, 2000 and
1999, we paid approximately $223.1 million, $244.9 million and $131.5 million,
respectively, for the purchase of crude oil under the agreement, including the
royalty share of production.
Financing
In December 1999, we loaned PAA $114.0 million, which was repaid in May
2000. Interest on the notes was $3.3 million and $0.6 million for the years
ended December 31, 2000 and 1999, respectively.
Transaction Grant Agreements
In 1998, at no cost to PAA, we agreed to grant 400,000 of our PAA common
units (including distribution equivalent rights attributable to such units) to
certain key officers and employees of the general partner and its affiliates.
The grants vested over a three year period subject to PAA paying
F-23
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
distributions on common and subordinated units. Of these grants, 69,000 vested
in 1999 and 133,000 vested in 2000. The remaining grants vested in 2001 as a
result of the Transactions. PAA recognized noncash compensation expense
related to the transaction grants of approximately $4.8 million, $2.7 million
and $1.0 million in the years ended December 31, 2001, 2000, and 1999,
respectively, and we reflected capital contributions of a similar amount. The
noncash compensation is included in general and administrative expense in the
Consolidated Statements of Operations for the years ended December 31, 2000
and 1999. Our share of this expense is included in our equity in the earnings
of PAA in 2001.
Note 13--Benefit Plans
We have a nonqualified retirement plan (the "Plan") for certain of our
officers. Benefits under the Plan are based on salary at the time of adoption,
vest over a 15-year period and are payable over a 15-year period commencing at
age 60. The Plan is unfunded.
Net pension expense for the years ended December 31, 2001, 2000 and 1999 is
comprised of the following components (in thousands):
Year Ended
December 31,
--------------
2001 2000 1999
---- ---- ----
Service cost--benefits earned during the period.............. $156 $ 99 $109
Interest on projected benefit obligation..................... 131 96 83
Amortization of prior service cost........................... 31 37 37
Unrecognized loss............................................ 17 -- 6
---- ---- ----
Net pension expense.......................................... $335 $232 $235
==== ==== ====
Summarized information of our retirement plan for the periods indicated is
as follows (in thousands):
December 31,
----------------
2001 2000
------- -------
Change in benefit obligation:
Benefit obligation at beginning of year................ $ 1,821 $ 1,233
Service cost........................................... 155 99
Interest cost.......................................... 131 96
Settlement losses...................................... 271 --
Special termination benefits........................... -- 175
Benefits paid.......................................... (67) --
Settlement payments.................................... (1,159) --
Actuarial (gains) losses............................... 755 218
------- -------
Benefit obligation at end of year........................ $ 1,907 $ 1,821
======= =======
Amounts recognized in the consolidated balance sheets:
Projected benefit obligation for service rendered to
date.................................................. $ 1,907 $ 1,821
Plan assets at fair value.............................. -- --
------- -------
Benefit obligation in excess of fair value of plan
assets................................................ (1,907) (1,821)
Unrecognized (gain) loss............................... 720 185
Unrecognized prior service costs....................... 310 508
Adjustment to recognize minimum liability.............. (1,030) (693)
------- -------
Net amount recognized.................................. $(1,907) $(1,821)
======= =======
F-24
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The weighted-average discount rate used in determining the projected
benefit obligation was 7.25% and 7.5% for the years ended December 31, 2001
and 2000, respectively.
We also maintain a 401(k) defined contribution plan whereby we match 100%
of an employee's contribution (subject to certain limitations in the plan).
Matching contributions are made 50% in cash and 50% in common stock of the
Company, with the number of shares for the stock match based on the market
value of the common stock at the time the shares are granted. For the years
ended December 31, 2001, 2000 and 1999, defined contribution plan expense was
$0.3 million, $1.4 million and $1.0 million, respectively. Such expense for
2000 and 1999 includes amounts attributable to employees of the general
partner of PAA.
Note 14--Stock Compensation Plans
Stock Options
Historically, we have used stock options as a long-term incentive for our
employees, officers and directors under various stock option plans. We have
options outstanding under our 2001 and 1996 plans, under which a maximum of
5.6 million shares of common stock were reserved for issuance. Generally, the
options are granted: (i) at an exercise price equal to or greater than the
market price of the underlying stock on the date of grant; and (ii) with a pro
rata vesting period of two to five years and an exercise period of five to ten
years. Certain options have vesting provisions related to the market price of
our common stock. If such options do not vest under such provisions, they vest
at the end of a five-year period.
Performance options to purchase a total of 500,000 shares of common stock
were granted to two executive officers in 1996. Terms of the options provided
for an exercise price of $13.50, the market price on the date of grant, and
were to vest if shares of our common stock traded at or above $24.00 per share
for any 20 trading days in any 30 consecutive trading day period prior to
August 2001, or upon a change in control if certain conditions were met. The
performance options vested in the second quarter of 2001 and we recognized
$4.0 million of noncash compensation expense, which is included in general and
administrative expense.
In May 2001 we granted options on 2,250,000 shares under the terms of our
2001 plan subject to the approval of such plan by our board of directors. The
market price of our common stock at the time the plan was approved in July
2001 exceeded the exercise price with respect to 1,450,000 of such options
and, accordingly, we recognized noncash compensation with respect to such
options. During 2001, $0.3 million in compensation expense with respect to
such options is included in general and administrative expense.
F-25
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
A summary of the status of our stock options as of December 31, 2001, 2000,
and 1999, and changes during the years ending on those dates are presented
below (shares in thousands):
2001 2000 1999
---------------- ---------------- ----------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Fixed Options Shares Price Shares Price Shares Price
------------- ------ -------- ------ -------- ------ --------
Outstanding at beginning of
year...................... 2,749 $12.11 2,811 $11.06 2,749 $10.53
Granted.................... 2,464 24.02 419 13.91 237 15.09
Exercised.................. (1,431) 11.51 (444) 6.96 (158) 7.94
Forfeited.................. (115) 14.06 (37) 14.37 (17) 9.93
------ ----- -----
Outstanding at end of
year...................... 3,667 $20.30 2,749 $12.11 2,811 $11.06
====== ===== =====
Options exercisable at
year-end.................. 1,084 $13.32 1,708 $11.07 1,836 $ 9.50
====== ===== =====
Weighted-average fair value
of options granted during
the year.................. $10.12 $5.39 $5.40
In October 1995, the Financial Accounting Standards Board issued SFAS 123,
which established financial accounting and reporting standards for stock-based
employee compensation. SFAS 123 defines a fair value based method of
accounting for an employee stock option or similar equity instrument. SFAS 123
also allows an entity to continue to measure compensation cost for those
instruments using the intrinsic value-based method of accounting prescribed by
APB 25. We have elected to follow APB 25 and related interpretations in
accounting for our employee stock options because, as discussed below, the
alternative fair value accounting provided for under SFAS 123 requires the use
of option valuation models that were not developed for use in valuing employee
stock options. Under APB 25, because the exercise price of our employee stock
options equals the market price of the underlying stock on the date of grant,
no compensation expense has been recognized in the accompanying financial
statements.
Pro forma information regarding net income (loss) and earnings per share is
required by SFAS 123 and has been determined as if we had accounted for our
employee stock options under the fair value method as provided therein. The
fair value for the options was estimated at the date of grant using a Black-
Scholes option pricing model with the following weighted average assumptions
for grants in 2001, 2000 and 1999: risk-free interest rates of 2.5% for 2001,
6.3% for 2000, and 5.1% for 1999; a volatility factor of the expected market
price of our common stock of .0.50 for 2001, 0.50 for 2000 and 0.50 for 1999;
no expected dividends; and weighted average expected option lives of 5.3 years
in 2001, 2.6 years in 2000 and 2.7 years in 1999. For purposes of pro forma
disclosures, the estimated fair value of the options is amortized to expense
over the options' vesting period.
The Black-Scholes option valuation model and other existing models were
developed for use in estimating the fair value of traded options that have no
vesting restrictions and are fully transferable. In addition, option valuation
models require the input of and are highly sensitive to subjective assumptions
including the expected stock price volatility. Because our employee stock
options have characteristics significantly different from those of traded
options, and because changes in the subjective input assumptions can
materially affect the fair value estimate, in management's opinion, the
existing models do not provide a reliable single measure of the fair value of
its employee stock options.
F-26
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Set forth below is a summary of our net income (loss) before extraordinary
item and earnings per share as reported and pro forma as if the fair value
based method of accounting defined in SFAS 123 had been applied (in thousands,
except per share data).
Year Ended December 31,
-------------------------
2001 2000 1999
-------- ------- --------
As Reported:
Net income (loss) before extraordinary item and
cumulative effect of accounting change........... $155,317 $45,924 $(24,787)
Net income (loss) per common share, basic......... 6.07 1.75 (2.02)
Net income (loss) per common share, diluted....... 4.82 1.56 (2.02)
Pro Forma:
Net income (loss) before extraordinary item and
cumulative effect of accounting change........... $152,335 $45,132 $(25,125)
Net income (loss) per common share, basic......... 5.93 1.70 (2.04)
Net income (loss) per common share, diluted....... 4.72 1.54 (2.04)
The following table summarizes information about stock options outstanding
at December 31, 2001 (share amounts in thousands):
Weighted Weighted
Number Weighted Average Average Number Average
Range of Outstanding Remaining Exercise Exercisable Exercise
Exercise Price at 12/31/01 Contractual Life Price at 12/31/01 Price
-------------- ----------- ---------------- -------- ----------- --------
$ 6.25 to $14.19 702 2.4 years $10.08 542 $ 8.97
14.31 to 21.12 508 1.9 years 16.39 461 16.43
23.00 to 23.00 1,000 9.4 years 23.00 -- --
23.74 to 25.30 1,457 5.0 years 24.74 81 24.73
$ 6.25 to $25.30 3,667 5.3 years $20.30 1,084 $13.32
Share Grant
In May 2001, an officer was granted the right to receive an amount, payable
in our common stock, equal to the excess of the "fair market value" (as
defined in our 2001 plan) of a share of common stock on the effective date and
$22.00, multiplied by one million. On the effective date, May 8, 2001, the
closing price of our common stock was $23.00 and accordingly, the employee
will receive $1.0 million, to be paid in five annual installments as of each
anniversary of the effective date, in the form of a direct grant of shares of
common stock. The number of shares is determined by dividing the annual
installment by the fair market value of a share on the applicable anniversary
date. We will recognize $1.0 million of noncash compensation expense ratably
over the five-year period. General and administrative expense for 2001
includes $0.3 million in compensation expense with respect to this share
grant.
F-27
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 15--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, are summarized below (in thousands):
2002.................................................................... $616
2003.................................................................... 593
2004.................................................................... 595
2005.................................................................... 573
2006.................................................................... 143
Thereafter.............................................................. --
Total expenses related to these commitments for the years ended December
31, 2001, 2000 and 1999 were $0.7 million, $7.3 million and $9.3 million,
respectively. Such amounts for 2000 and 1999 include $6.7 million and $8.8
million, respectively, attributable to PAA.
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,
Florida 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
F-28
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 $17.0 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 each include $0.5 million 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 19.
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 our revolving credit facility, with one such counterparty holding contracts
that represent approximately 37% of the fair value of all 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 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.
F-29
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 16--Litigation
Texas Securities Litigation. In November and December of 1999, class action
lawsuits were filed in the United States District Court for the Southern
District of Texas alleging that PAA. and certain of the general partner's
officers and directors violated federal securities laws, primarily in
connection with unauthorized trading by a former employee. The consolidated
class action filed by purchasers of our common stock and options is captioned
Koplovitz v. Plains Resources Inc., et al. The consolidated action filed by
purchasers of PAA's common units is captioned Di Giacomo v. Plains All
American Pipeline, L.P., et al.
We and PAA reached an agreement with representatives for the plaintiffs for
the settlement of all of the class actions, and in January 2001, PAA deposited
approximately $30.0 million under the terms of the settlement agreement. The
total cost of the settlement to us and PAA, including interest and expenses,
and after insurance reimbursements, was $14.9 million. Of that amount, $1.0
million was allocated to us by agreement between special independent
committees of our board of directors and the board of directors of Plains
Holdings Inc. (formerly known as Plains All American Inc.), the then general
partner of PAA. The settlement has received final approval by the court. The
settlement agreement does not affect the Texas Derivative Litigation and
Delaware Derivative Litigation described below.
Delaware Derivative Litigation. Beginning December 3, 1999 derivative
lawsuits were filed in the Delaware Chancery Court, New Castle County naming
Plains Holdings Inc., the then general partner of PAA, its directors and
certain of its officers as defendants, alleging that the defendants breached
the fiduciary duties they owed to PAA and its unitholders by failing to
monitor properly the activities of its employees. The court has consolidated
all of the cases under the caption In Re Plains All American Inc. Shareholders
Litigation. A motion to dismiss was filed on behalf of the defendants on
August 11, 2000.
An agreement has been reached with the plaintiffs to settle the Delaware
litigation by PAA making an aggregate payment of approximately $1.1 million.
On March 6, 2002 the Delaware court approved this settlement.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Fernandez v. Plains All American Inc., et al., naming Plains Holdings
Inc., the then general partner of PAA, its directors and certain of its
officers as defendants. This lawsuit contains the same claims and seeks the
same relief as the Delaware derivative litigation described above. A motion to
dismiss was filed on behalf of the defendants on August 14, 2000. PAA has
reached an agreement in principle to settle the Texas derivative litigation.
The settlement, which is subject to court approval, contemplates a payment of
$112,500 by PAA and does not contemplate any payment by the Company.
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.
F-30
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 17--Financial Instruments
The following 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 ("SFAS 107"). The estimated fair value amounts have been
determined using available market information and valuation methodologies
described below. Considerable judgment is required in interpreting market data
to develop the estimates of fair value. The use of different market
assumptions or valuation methodologies may have a material effect on the
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 in other assets are
stated at fair value. The carrying amounts and fair values of our other
financial instruments are as follows (in thousands):
December 31,
---------------------------------
2001 2000
---------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------- -------- -------
Long-Term Debt:
Bank debt................................ $11,500 $11,500 $27,300 $27,300
Subordinated debt........................ 269,539 272,130 277,543 274,313
Other long-term debt..................... 1,022 1,022 1,533 1,533
The carrying value of bank debt approximates its fair value, as interest
rates are variable, based on prevailing market rates. The fair value of
subordinated debt is based on quoted market prices based on trades of
subordinated debt.
Note 18--Supplemental Disclosures of Cash Flow Information
Selected cash payments and noncash activities were as follows (in
thousands):
Year Ended December 31,
-----------------------
2001 2000 1999
------- ------- -------
Cash paid for interest (net of amount
capitalized)..................................... $27,939 $56,154 $44,329
======= ======= =======
Cash paid for taxes............................... $ 7,048 $ 987 $ 548
======= ======= =======
Noncash sources and (uses) of investing and
financing activities:
Series D Preferred Stock dividends.............. $ -- $ -- $(1,354)
======= ======= =======
Exchange of preferred stock for common stock.... $ -- $ 62 $ 71
======= ======= =======
Series E Preferred Stock dividends.............. $ -- $ -- $(2,030)
======= ======= =======
Tax benefit from exercise of employee stock
options........................................ $ 6,990 $ 1,901 $ 440
======= ======= =======
F-31
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 19--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................................. 1,798 2,433 2,880
Exploration costs................................... 329 872 4,101
Exploitation and development costs.................. 134,304 77,550 65,119
------- ------- -------
136,475 $80,928 $72,979
======= ======= =======
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........................................ $900,898 $762,245
Accumulated DD&A......................................... (435,269) (408,337)
-------- --------
$465,629 $353,908
======== ========
The DD&A rate per equivalent unit of production was $2.75, $2.25, and $2.13
for the years ended December 31, 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.................................... $30,038 $34,087 $42,261
Exploration costs.................................... 3,579 4,456 4,842
Capitalized interest................................. 6,890 4,038 4,928
------- ------- -------
$40,507 $42,581 $52,031
======= ======= =======
Unproved property costs not subject to amortization consist mainly of
acquisition and lease costs and seismic data related to unproved areas. We
will continue to evaluate these properties over the
F-32
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
lease terms; however, the timing of the ultimate evaluation and disposition of
a significant portion of the properties has not been determined. Costs
associated with seismic data and all other costs will become subject to
amortization as the prospects to which they relate are evaluated.
Approximately 13%, 11% and 16% 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 $3.6 million, $4.4 million and
$4.4 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 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 94% of year-end 2001 reserve volumes) is comprised
of crude oil properties that are sensitive to crude oil price volatility.
F-33
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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......... 223,162 93,486 218,922 90,873 120,208 86,781
Revision of previous
estimates................ (15,457) (5,485) (9,834) (3,597) 62,895 (8,234)
Extensions, discoveries,
improved recovery and
other additions.......... 42,210 11,571 22,429 9,252 37,393 15,488
Sale of reserves in-
place.................... -- -- -- -- -- --
Purchase of reserves in-
place.................... -- -- -- -- 6,442 --
Production................ (9,279) (3,355) (8,355) (3,042) (8,016) (3,162)
------- ------ ------- ------ ------- ------
Ending balance............ 240,636 96,217 223,162 93,486 218,922 90,873
======= ====== ======= ====== ======= ======
Proved Developed Reserves
Beginning balance......... 123,532 52,184 120,141 49,255 73,264 58,445
======= ====== ======= ====== ======= ======
Ending balance............ 134,704 59,101 123,532 52,184 120,141 49,255
======= ====== ======= ====== ======= ======
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.................... $3,833,456 $6,057,344 $4,837,010
Future development costs............... (329,393) (275,862) (231,914)
Future production expense.............. (1,826,634) (2,875,301) (1,758,572)
Future income tax expense.............. (511,040) (887,107) (845,133)
---------- ---------- ----------
Future net cash flows.................. 1,166,389 2,019,074 2,001,391
Discounted at 10% per year............. (742,981) (1,099,413) (1,073,591)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows................. $ 423,408 $ 919,661 $ 927,800
========== ========== ==========
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
F-34
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 3. 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 $14.91 per barrel of
crude oil and $2.56 per Mcf of natural gas. Such prices as of December 31,
2000 were $21.02 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 $0.7 billion, $1.3 billion and $1.2 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.
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................... $ 919,661 $ 927,800 $ 226,943
Sales, net of production expenses............ (144,055) (166,571) (60,578)
Net change in sales and transfer prices, net
of production expenses...................... (674,439) 96,104 516,097
Changes in estimated future development
costs....................................... (18,134) (14,593) (52,951)
Extensions, discoveries and improved
recovery, net of costs...................... 94,775 141,638 112,573
Previously estimated development costs
incurred during the year.................... 87,721 31,363 22,842
Purchase of reserves in-place................ -- -- 53,724
Revision of quantity estimates............... (166,869) (104,200) 404,705
Accretion of discount........................ 145,375 115,605 22,694
Net change in income taxes................... 179,373 (107,485) (318,249)
--------- --------- ---------
Balance, end of year......................... $ 423,408 $ 919,661 $ 927,800
========= ========= =========
F-35
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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... $215,247 $149,342 $116,223
Production costs................................. (71,192) (62,140) (55,645)
Depreciation, depletion and amortization......... (27,009) (19,953) (18,177)
Income tax expense............................... (45,987) (26,227) (16,536)
-------- -------- --------
Results of operations from producing activities
(excluding corporate overhead and interest
costs).......................................... $ 71,059 $ 41,022 $ 25,865
======== ======== ========
F-36
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 20--Quarterly Financial Data (Unaudited)
The following table shows summary financial data for 2001 and 2000 (in
thousands, except per share data):
First Second Third Fourth
Quarter Quarter Quarter Quarter(1) Total
---------- ---------- ---------- ---------- ----------
2001
Revenues................ $ 58,232 $ 58,424 $ 54,168 $ 44,896 $ 215,720
Operating profit........ 31,172 22,510 25,217 15,415 94,314
Income before cumulative
effect of accounting
change................. 20,952 100,102 15,154 19,109 155,317
Cumulative effect of
accounting change...... (1,986) -- -- -- (1,986)
Net income.............. 18,966 100,102 15,154 19,109 153,331
Basic EPS
Income before
cumulative effect of
accounting change..... 1.11 3.83 0.63 0.79 6.07
Cumulative effect of
accounting change..... (0.11) -- -- -- (0.09)
Net income............. 1.00 3.83 0.63 0.79 5.98
Diluted EPS
Income before
cumulative effect of
accounting change..... 0.72 2.68 0.58 0.75 4.82
Cumulative effect of
accounting change..... (0.06) -- -- -- (0.07)
Net income............. 0.66 2.68 0.58 0.75 4.75
2000
Revenues................ $2,087,685 $1,427,044 $1,542,463 $1,573,393 $6,630,585
Operating profit........ 53,502 54,400 48,706 55,660 212,268
Income before
extraordinary item and
cumulative effect of
accounting change...... 21,268 8,992 7,026 8,638 45,924
Extraordinary item...... (1,365) (3,623) -- -- (4,988)
Cumulative effect of
accounting change...... (121) -- -- -- (121)
Net income.............. 19,782 5,369 7,026 8,638 40,815
Basic EPS
Income before
extraordinary item and
cumulative effect of
accounting change..... 0.98 0.29 0.19 0.29 1.75
Extraordinary item..... (0.08) (0.20) -- -- (0.28)
Cumulative effect of
accounting change..... -- -- -- -- (0.01)
Net income............. 0.90 0.09 0.19 0.29 1.46
Diluted EPS
Income before
extraordinary item and
cumulative effect of
accounting change..... 0.72 0.28 0.18 0.27 1.56
Extraordinary item..... (0.05) (0.19) -- -- (0.17)
Cumulative effect of
accounting change..... -- -- -- -- --
Net income............ 0.67 0.09 0.18 0.27 1.39
- --------
(1) For 2000, includes a $5.0 million charge to reserve for potentially
uncollectible accounts receivable.
F-37
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 21--Operating Segments
Prior to completion of the Transactions , our operations consisted of two
operating segments: (1) Upstream Operations--engages in the acquisition,
exploitation, development, exploration and production of crude oil and natural
gas and (2) Midstream Operations--engages in pipeline transportation,
purchases and resales of crude oil at various points along the distribution
chain and the leasing of certain terminalling and storage assets. As a result
of the Transactions we no longer have a Midstream segment.
Upstream Midstream Total
-------- ----------- -----------
(In thousands)
2000
Revenues:
External customers....................... $149,342 $ 6,425,644 $ 6,574,986
Intersegment (a)......................... -- 215,543 215,543
Gain on sale of assets................... -- 48,188 48,188
Interest and other income (expense)...... (3,468) 10,879 7,411
-------- ----------- -----------
Total revenues of reportable segments.. $145,874 $ 6,700,254 $ 6,846,128
======== =========== ===========
Segment gross margin (b)................... $ 86,202 $ 126,066 $ 212,268
Segment gross profit (c)................... 76,297 85,195 161,492
Segment income (loss) before income taxes,
extraordinary item and cumulative effect
of accounting change...................... 23,009 91,033 114,042
Interest expense........................... 27,346 28,482 55,828
Depreciation, depletion and amortization... 22,474 24,747 47,221
Income tax expense......................... 6,503 19,080 25,583
Extraordinary item, net of tax and minority
interest.................................. -- (4,988) (4,988)
Capital expenditures....................... 81,475 12,603 94,078
Assets..................................... 458,678 935,651 1,394,329
1999
Revenues:
External customers....................... $116,223 $10,796,998 $10,913,221
Intersegment (a)......................... -- 75,454 75,454
Gain on sale of assets................... -- 16,457 16,457
Interest and other income................ 241 10,783 11,024
-------- ----------- -----------
Total revenues of reportable segments.. $116,464 $10,899,692 $11,016,156
======== =========== ===========
Segment gross margin (b)................... $ 60,578 $ (58,750) $ 1,828
Segment gross profit (c)................... 52,775 (82,349) (29,574)
Segment income (loss) before income taxes
and extraordinary item.................... 8,132 (93,601) (85,469)
Interest expense........................... 25,298 21,080 46,378
Depreciation, depletion and amortization... 19,586 17,412 36,998
Income tax benefit......................... 1,635 18,844 20,479
Extraordinary item, net of tax and minority
interest.................................. -- (544) (544)
Capital expenditures....................... 77,899 189,286 267,185
Assets..................................... 445,921 1,243,639 1,689,560
- --------
(a) Intersegment revenues and transfers were conducted on an arm's-length
basis.
(b) Gross margin is calculated as operating revenues less operating expenses.
(c) Gross profit is calculated as operating revenues less operating expenses
and general and administrative expenses.
F-38
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following table reconciles segment revenues to amounts reported in our
financial statements:
For the Year Ended
December 31,
-----------------------
2000 1999
---------- -----------
Revenues of reportable segments................... $6,846,128 $11,016,156
Intersegment...................................... (215,543) (75,454)
Net gain recorded upon the formation of PAA not
allocated to reportable segments................. -- --
---------- -----------
Total company revenues.......................... $6,630,585 $10,940,702
========== ===========
PAA is the exclusive purchaser of all of our equity oil production. The
following table reflects for the years ended December 31, 2000 and 1999,
during which periods PAA was included in our consolidated financial
statements, customers accounting for more than 10% of consolidated sales
(excluding hedging effects):
Percentage of
Consolidated Sales
---------------------
Year Ended
December 31,
---------------------
2000 1999
Customer --------- ---------
Marathon Ashland Petroleum (1)....................... 12% --
Sempra Energy Trading Corporation (1)................ -- 22%
Koch Oil Company (1)................................. -- 18%
Percentage of Oil
and Gas Sales(2)
---------------------
Chevron.............................................. 43% 39%
Equiva Trading Company............................... 23% --
Tosco Refining Company............................... -- 19%
Conoco Inc........................................... -- 11%
Marathon Ashland Petroleum........................... 13% 16%
- --------
(1) These customers pertain to our midstream segment Represents percentage of
oil and gas sales revenues plus marketing, transportation, storage and
terminalling revenues.
(2) These percentages represent the entities that purchased our equity crude
production from PAA.
We do not believe the loss of PAA as the exclusive purchaser of our equity
production would have a material adverse effect on our results of operations.
We believe PAA could be replaced by other purchasers under contracts with
similar terms and conditions.
Note 22--Consolidating Financial Statements
The following financial information presents consolidating financial
statements, which include:
. the parent company only ("Parent");
. the guarantor subsidiaries on a combined basis ("Guarantor
Subsidiaries");
. the nonguarantor subsidiaries on a combined basis ("Nonguarantor
Subsidiaries");
. elimination entries necessary to consolidate the Parent, the Guarantor
Subsidiaries and the Nonguarantor Subsidiaries; and
. Plains Resources Inc. on a consolidated basis.
These statements are presented because the 10.25% Notes discussed in Note 4
are not guaranteed by all of our subsidiaries.
F-39
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (in thousands)
DECEMBER 31, 2001
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
ASSETS --------- ------------ ------------ ------------ ------------
Current Assets
Cash and cash
equivalents......... $ 1,013 $ 13 $ 153 $ -- $ 1,179
Accounts receivable
and other........... 26,773 18,050 -- -- 44,823
Current intercompany
advances............ -- 13,662 (13,662) -- --
Inventory............ -- 6,721 -- -- 6,721
--------- -------- -------- --------- ---------
27,786 38,446 (13,509) -- 52,723
--------- -------- -------- --------- ---------
Property and Equipment,
at cost............... 243,969 701,587 -- (149) 945,407
Less allowance for
depreciation,
depletion and
amortization........ (217,801) 164,795) -- (55,386) (437,982)
--------- -------- -------- --------- ---------
26,168 536,792 -- (55,535) 507,425
--------- -------- -------- --------- ---------
Investment in
Subsidiaries and
Intercompany
Advances.............. 467,837 (279,496) 178,202 (301,917) 64,626
--------- -------- -------- --------- ---------
Other Assets........... 10,313 13,769 383 (451) 24,014
--------- -------- -------- --------- ---------
$ 532,104 $309,511 $165,076 $(357,903) $ 648,788
========= ======== ======== ========= =========
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current Liabilities
Accounts payable and
other current
liabilities......... $ (68,896) $ 42,581 $ 80,210 $ -- $ 53,895
Interest payable..... 8,286 -- -- -- 8,286
Notes payable........ -- 511 -- -- 511
--------- -------- -------- --------- ---------
(60,610) 43,092 80,210 -- 62,692
--------- -------- -------- --------- ---------
Long-Term Debt
Bank debt............ 11,500 -- -- -- 11,500
Subordinated debt.... 269,539 -- -- -- 269,539
Other................ -- 1,022 -- -- 1,022
--------- -------- -------- --------- ---------
281,039 1,022 -- -- 282,061
--------- -------- -------- --------- ---------
Other Long-Term
Liabilities........... 3,013 1,413 463 -- 4,889
--------- -------- -------- --------- ---------
Deferred Income Taxes.. 53,810 8,415 (17,931) -- 44,294
--------- -------- -------- --------- ---------
Non-redeemable
Preferred Stock,
Common Stock and Other
Stockholders' Equity
Series D Cumulative
Convertible
Preferred Stock..... 23,300 -- -- -- 23,300
Common Stock......... 2,768 837 -- (837) 2,768
Additional paid-in
capital............. 268,520 3,805 43,390 (47,195) 268,520
Retained earnings
(accumulated
deficit)............ 37,676 250,927 61,263 (312,190) 37,676
Accumulated other
comprehensive
income.............. 13,930 -- (2,319) 2,319 13,930
Treasury stock, at
cost................ (91,342) -- -- -- (91,342)
--------- -------- -------- --------- ---------
254,852 255,569 102,334 (357,903) 254,852
--------- -------- -------- --------- ---------
$ 532,104 $309,511 $165,076 $(357,903) $ 648,788
========= ======== ======== ========= =========
F-40
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (in thousands)
DECEMBER 31, 2000
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
ASSETS --------- ------------ ------------ ------------ ------------
Current Assets
Cash and cash
equivalents......... $ 4 $ 597 $ 4,479 $ -- $ 5,080
Accounts receivable
and other........... 12,193 15,596 347,696 -- 375,485
Current intercompany
advances............ -- 17,605 (17,605) -- --
Inventory............ -- 8,063 46,781 -- 54,844
--------- --------- -------- --------- ----------
12,197 41,861 381,351 -- 435,409
--------- --------- -------- --------- ----------
Property and Equipment,
at cost............... 237,591 570,677 473,471 -- 1,281,739
Less allowance for
depreciation,
depletion and
amortization........ (215,942) (138,871) (27,266) (55,386) (437,465)
--------- --------- -------- --------- ----------
21,649 431,806 446,205 (55,386) 844,274
--------- --------- -------- --------- ----------
Investment in
Subsidiaries and
Intercompany
Advances.............. 389,467 (254,891) (6,372) (128,204) --
Other Assets........... 8,151 16,005 90,490 -- 114,646
--------- --------- -------- --------- ----------
$ 431,464 $ 234,781 $911,674 $(183,590) $1,394,329
========= ========= ======== ========= ==========
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current Liabilities
Accounts payable and
other current
liabilities......... $ 7,105 $ 46,368 $359,823 $ 13 $ 413,309
Notes payable and
other current
obligations......... -- 511 1,300 -- 1,811
--------- --------- -------- --------- ----------
7,105 46,879 361,123 13 415,120
--------- --------- -------- --------- ----------
Long-Term Debt
Bank debt............ 27,300 -- -- -- 27,300
Bank debt of a
subsidiary.......... -- -- 320,000 -- 320,000
Subordinated debt.... 277,543 -- -- -- 277,543
Other................ -- 1,533 -- -- 1,533
--------- --------- -------- --------- ----------
304,843 1,533 320,000 -- 626,376
--------- --------- -------- --------- ----------
Other Long-Term
Liabilities........... 2,413 -- 1,009 -- 3,422
--------- --------- -------- --------- ----------
Minority Interest in
PAA................... (70,037) -- 232,216 92 162,271
--------- --------- -------- --------- ----------
Cumulative Convertible
Preferred Stock,
Stated at Liquidation
Preference............ 50,000 -- -- -- 50,000
--------- --------- -------- --------- ----------
Non-redeemable
Preferred Stock,
Common Stock and Other
Stockholders' Equity
Series D Cumulative
Convertible Preferred
Stock................. 23,300 -- -- -- 23,300
Series H Cumulative
Convertible Preferred
Stock................. 84,785 -- -- -- 84,785
Common Stock........... 1,875 78 -- (78) 1,875
Additional paid-in
capital............... 139,203 3,951 43,393 (47,344) 139,203
Retained earnings
(accumulated
deficit).............. (88,410) 182,340 (46,067) (136,273) (88,410)
Treasury stock, at
cost.................. (23,613) -- -- -- (23,613)
--------- --------- -------- --------- ----------
137,140 186,369 (2,674) (183,695) 137,140
--------- --------- -------- --------- ----------
$ 431,464 $ 234,781 $911,674 $(183,590) $1,394,329
========= ========= ======== ========= ==========
F-41
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 2001
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------ ------------
Revenues
Crude oil and
liquids.............. $ -- $186,476 $ -- $ -- $186,476
Natural gas........... -- 28,771 -- -- 28,771
Other operating
revenues............. -- 473 -- -- 473
-------- -------- -------- --------- --------
-- 215,720 -- -- 215,720
-------- -------- -------- --------- --------
Expenses
Production expenses... -- 71,192 -- -- 71,192
General and
administrative....... 10,023 11,260 10 -- 21,293
Depreciation,
depletion and
amortization......... 1,502 27,419 -- -- 28,921
-------- -------- -------- --------- --------
11,525 109,871 10 -- 121,406
-------- -------- -------- --------- --------
Income (Loss) from
Operations............. (11,525) 105,849 (10) -- 94,314
Other Income (Expense)
Equity in earnings of
subsidiary........... 176,527 -- 18,540 (176,527) 18,540
Gain on PAA unit
transactions and
public offerings..... -- -- 170,157 -- 170,157
Interest expense...... (2,805) (23,580) -- -- (26,385)
Interest and other
income............... (312) 463 -- -- 151
-------- -------- -------- --------- --------
Income (Loss) Before
Income Taxes and
Cumulative Effect of
Accounting Change...... 161,885 82,732 188,687 (176,527) 256,777
Income tax (expense)
benefit:
Current............. 44,749 -- (54,696) -- (9,947)
Deferred............ (51,175) (13,532) (26,806) -- (91,513)
-------- -------- -------- --------- --------
Income (Loss) Before
Cumulative Effect of
Accounting Change...... 155,459 69,200 107,185 (176,527) 155,317
Cumulative effect of
accounting change,
net of tax benefit... (2,128) -- 142 -- (1,986)
-------- -------- -------- --------- --------
Net Income (Loss)....... 153,331 69,200 107,327 (176,527) 153,331
Cumulative preferred
dividends............ (27,245) -- -- -- (27,245)
-------- -------- -------- --------- --------
Income (Loss) Available
to Common
Stockholders........... $126,086 $ 69,200 $107,327 $(176,527) $126,086
======== ======== ======== ========= ========
F-42
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 2000
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
------- ------------ ------------ ------------ ------------
Revenues
Crude oil and
liquids.............. $ 4 $131,667 $ -- $ 1,654 $ 133,325
Natural gas........... -- 16,017 -- -- 16,017
Marketing,
transportation,
storage and
terminalling......... -- -- 6,641,187 (215,543) 6,425,644
Gain on sale of
assets............... -- -- 48,188 -- 48,188
------- -------- --------- -------- ---------
4 147,684 6,689,375 (213,889) 6,623,174
------- -------- --------- -------- ---------
Expenses
Production expenses... -- 62,140 -- -- 62,140
General and
administrative....... 2,054 7,851 40,871 -- 50,776
Marketing,
transportation,
storage and
terminalling......... -- -- 6,506,504 (213,889) 6,292,615
Unauthorized trading
losses and related
expenses............. 1,000 -- 6,963 -- 7,963
Depreciation,
depletion and
amortization......... 3,068 19,406 24,747 -- 47,221
------- -------- --------- -------- ---------
6,122 89,397 6,579,085 (213,889) 6,460,715
------- -------- --------- -------- ---------
Income from Operations.. (6,118) 58,287 110,290 -- 162,459
Other Income (Expense)
Equity in earnings of
subsidiary........... 64,115 -- -- (64,115) --
Interest expense...... (9,581) (20,827) (28,482) 3,062 (55,828)
Interest and other
income............... (737) 331 10,879 (3,062) 7,411
------- -------- --------- -------- ---------
Income (Loss) Before
Income Taxes, Minority
Interest, Extraordinary
Item and Cumulative
Effect of Accounting
Change................. 47,679 37,791 92,687 (64,115) 114,042
Minority interest..... -- -- (42,535) -- (42,535)
Income tax (expense)
benefit:
Current............. 24,094 -- (25,114) -- (1,020)
Deferred............ (30,958) 361 6,034 -- (24,563)
------- -------- --------- -------- ---------
Income (Loss) Before
Extraordinary Item and
Cumulative Effect of
Accounting Change...... 40,815 38,152 31,072 (64,115) 45,924
Extraordinary item,
net of tax benefit
and minority
interest............. -- -- (4,988) -- (4,988)
Cumulative effect of
accounting change,
net of tax benefit... -- (121) -- -- (121)
------- -------- --------- -------- ---------
Net Income (Loss)....... 40,815 38,031 26,084 (64,115) 40,815
Cumulative preferred
dividends............ (14,725) -- -- -- (14,725)
------- -------- --------- -------- ---------
Income (Loss) Available
to Common
Stockholders........... $26,090 $ 38,031 $ 26,084 $(64,115) $ 26,090
======= ======== ========= ======== =========
F-43
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 1999
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------ ------------
Revenues
Crude oil and
liquids.............. $ -- $109,641 $ -- $ 1,487 $ 111,128
Natural gas........... -- 5,095 -- -- 5,095
Marketing,
transportation,
storage and
terminalling......... -- -- 10,872,452 (75,454) 10,796,998
Gain on sale of
assets............... -- -- 16,457 -- 16,457
-------- -------- ----------- -------- -----------
-- 114,736 10,888,909 (73,967) 10,929,678
-------- -------- ----------- -------- -----------
Expenses
Production expenses... -- 55,645 -- -- 55,645
General and
administrative....... 2,311 5,492 23,599 -- 31,402
Depreciation,
depletion and
amortization......... 2,096 17,490 17,412 -- 36,998
Marketing,
transportation,
storage and
terminalling......... -- -- 10,763,275 (73,967) 10,689,308
Unauthorized trading
losses and related
expenses............. -- -- 166,440 -- 166,440
-------- -------- ----------- -------- -----------
4,407 78,627 10,970,726 (73,967) 10,979,793
-------- -------- ----------- -------- -----------
Income (Loss) from
Operations............. (4,407) 36,109 (81,817) -- (50,115)
Other Income (Expense)
Equity in earnings
(loss) of
subsidiary........... (11,510) -- -- 11,510 --
Gain on PAA unit
offering............. -- -- 9,787 -- 9,787
Interest expense...... (6,994) (18,851) (21,080) 547 (46,378)
Interest and other
income............... 699 89 996 (547) 1,237
-------- -------- ----------- -------- -----------
Income (Loss) Before
Income Taxes, Minority
Interest and
Extraordinary Item..... (22,212) 17,347 (92,114) 11,510 (85,469)
Minority interest in
PAA.................. -- -- 40,203 -- 40,203
Income tax (expense)
benefit:
Current............. 338 -- (331) -- 7
Deferred............ (3,457) 4,754 19,175 -- 20,472
-------- -------- ----------- -------- -----------
Income (Loss) Before
Extraordinary Item..... (25,331) 22,101 (33,067) 11,510 (24,787)
Extraordinary item,
net of tax benefit
and minority
interest............. -- -- (544) -- (544)
-------- -------- ----------- -------- -----------
Net Income (Loss)....... (25,331) 22,101 (33,611) 11,510 (25,331)
Cumulative preferred
dividends............ (10,026) -- -- -- (10,026)
-------- -------- ----------- -------- -----------
Income (Loss) Available
to Common
Stockholders........... $(35,357) $ 22,101 $ (33,611) $ 11,510 $ (35,357)
======== ======== =========== ======== ===========
F-44
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, 2001
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
CASH FLOWS FROM
OPERATING ACTIVITIES
Net income (loss)....... $ 153,331 $ 69,200 $ 107,327 $(176,527) $ 153,331
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Depreciation,
depletion, and
amortization......... 1,502 27,419 -- -- 28,921
Equity earnings in
subsidiary........... (176,527) -- (18,540) 176,527 (18,540)
Distributions from
subsidiary........... -- -- 31,553 -- 31,553
Noncash gains......... -- -- (170,157) -- (170,157)
Deferred income tax... 51,175 13,532 26,806 -- 91,513
Cumulative effect of
adoption of SFAS
123.................. 2,128 -- (142) -- 1,986
Change in derivative
fair value........... 1,227 -- -- -- 1,227
Noncash compensation
expense.............. 4,514 -- -- -- 4,514
Other noncash items... 1,626 -- -- -- 1,626
Change in assets and
liabilities resulting
from operating
activities:............
Accounts receivable
and other............ (14,580) (7,461) 43,064 -- 21,023
Inventory............. -- 1,342 1,133 -- 2,475
Accounts payable and
other current
liabilities.......... (76,001) (3,787) (1,486) -- (81,274)
Other long-term
liabilities.......... 600 1,413 (546) -- 1,467
Advances from
(payments to)
affiliates........... 143,285 (101,731) 8,909 -- 50,463
--------- --------- --------- --------- ---------
Net cash provided by
(used in) operating
activities............. 92,280 (73) 27,921 -- 120,128
--------- --------- --------- --------- ---------
CASH FLOWS FROM
INVESTING ACTIVITIES
Acquisition, exploration
and development costs.. -- -- (131,785) -- (131,785)
Additions to other
property and assets.... (561) -- -- -- (561)
Proceeds from the sale
of PAA units........... -- -- 106,941 -- 106,941
Investment in PAA....... -- -- (3,978) -- (3,978)
--------- --------- --------- --------- ---------
Net cash provided by
(used in) investing
activities............. (561) -- (28,822) -- (29,383)
--------- --------- --------- --------- ---------
CASH FLOWS FROM
FINANCING ACTIVITIES
Proceeds from long-term
debt................... 204,900 -- -- -- 204,900
Proceeds from sale of
capital stock, options
and warrants........... 9,169 -- -- -- 9,169
Proceeds from issuance
of preferred stock..... -- -- -- -- --
Purchase of senior
subordinated notes..... (7,550) -- -- -- (7,550)
Principal payments of
long-term debt......... (220,700) (511) -- -- (221,211)
Purchase of treasury
stock.................. (67,729) -- -- -- (67,729)
Preferred stock
dividends.............. (8,698) -- -- -- (8,698)
Other................... (102) -- -- -- (102)
--------- --------- --------- --------- ---------
Net cash used in
financing activities... (90,710) (511) -- -- (91,221)
--------- --------- --------- --------- ---------
Net decrease in cash and
cash equivalents....... 1,009 (584) (901) -- (476)
Decrease in cash due to
deconsolidation of
PAA.................... -- -- (3,425) -- (3,425)
Cash and cash
equivalents, beginning
of period.............. $ 4 $ 597 $ 4,479 $ -- 5,080
--------- --------- --------- --------- ---------
Cash and cash
equivalents, end of
period................. $ 1,013 $ 13 $ 153 $ -- $ 1,179
========= ========= ========= ========= =========
F-45
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, 2000
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
-------- ------------ ------------ ------------ ------------
CASH FLOWS FROM
OPERATING ACTIVITIES
Net income (loss)....... $ 40,815 $38,031 $ 26,084 $(64,115) $ 40,815
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Depreciation,
depletion, and
amortization......... 3,068 19,406 24,747 -- 47,221
Gain on sale of assets
(Note 6)............. -- -- (48,188) -- (48,188)
Minority interest in
income of a
subsidiary........... -- -- 35,566 -- 35,566
Equity earnings in
subsidiary........... (64,115) -- -- 64,115 --
Deferred income tax... 30,958 (362) (9,299) -- 21,297
Noncash compensation
expense.............. (407) -- 3,089 -- 2,682
Allowance for doubtful
accounts............. -- -- 5,000 -- 5,000
Other noncash items... 6,351 -- 4,574 -- 10,925
Change in assets and
liabilities resulting
from operating
activities:
Accounts receivable
and other............ (10,385) (7,461) 120,497 -- 102,651
Inventory............. -- (2,023) (11,954) -- (13,977)
Pipeline linefill..... -- -- (16,679) -- (16,679)
Accounts payable and
other current
liabilities.......... (16,595) 34,685 (161,543) -- (143,453)
Other long-term
liabilities.......... 591 -- (8,591) -- (8,000)
Advances from
(payments to)
affiliates........... 119,735 (9,889) (109,846) -- --
-------- ------- ---------- -------- ----------
Net cash provided by
(used in) operating
activities............. 110,016 72,387 (146,543) -- 35,860
-------- ------- ---------- -------- ----------
CASH FLOWS FROM
INVESTING ACTIVITIES
Payments for crude oil
pipeline, gathering and
terminal assets........ -- -- (12,219) -- (12,219)
Payments for
acquisition,
exploration, and
development costs...... (3,894) (74,448) (384) -- (78,726)
Payments for additions
to other property and
assets................. -- (2,476) (657) -- (3,133)
Proceeds from asset
sales (Note 6)......... -- -- 224,261 -- 224,261
-------- ------- ---------- -------- ----------
Net cash provided by
(used in) investing
activities............. (3,894) (76,924) 211,001 -- 130,183
-------- ------- ---------- -------- ----------
CASH FLOWS FROM
FINANCING ACTIVITIES
Proceeds from long-term
debt................... 264,825 -- 1,433,750 -- 1,698,575
Proceeds from short-term
debt................... -- -- 51,300 -- 51,300
Proceeds from sale of
capital stock, options
and warrants........... 2,301 -- -- -- 2,301
Principal payments of
long-term debt......... (375,336) -- (1,423,850) -- (1,799,186)
Principal payments of
short-term debt........ -- -- (108,719) -- (108,719)
Purchase of treasury
stock.................. (23,613) -- -- -- (23,613)
Costs incurred in
connection with
financing
arrangements........... -- -- (6,748) -- (6,748)
Preferred stock
dividends.............. (13,409) -- -- -- (13,409)
Distribution to
unitholders............ 30,133 -- (59,565) -- (29,432)
Other................... (260) -- -- -- (260)
-------- ------- ---------- -------- ----------
Net cash used in
financing activities... (115,359) -- (113,832) -- (229,191)
-------- ------- ---------- -------- ----------
Net decrease in cash and
cash equivalents....... (9,237) (4,537) (49,374) -- (63,148)
Cash and cash
equivalents, beginning
of period.............. $ 9,241 $ 5,134 $ 53,853 $ -- 68,228
-------- ------- ---------- -------- ----------
Cash and cash
equivalents, end of
period................. $ 4 $ 597 $ 4,479 $ -- $ 5,080
======== ======= ========== ======== ==========
F-46
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, 1999
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
CASH FLOWS FROM
OPERATING ACTIVITIES
Net income (loss)....... $ (25,331) $ 22,101 $ (33,611) $ 11,510 $ (25,331)
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Depreciation,
depletion, and
amortization......... 2,096 17,490 17,412 -- 36,998
Noncash gains (Note 4
and 6)............... -- -- (26,244) -- (26,244)
Minority interest in
income of a
subsidiary........... -- -- (40,203) -- (40,203)
Equity in earnings of
subsidiary........... 11,510 -- -- (11,510) --
Deferred income tax... 3,457 (4,754) (19,175) -- (20,472)
Noncash compensation
expense.............. -- -- 1,013 -- 1,013
Other noncash items... (1,108) -- 1,047 -- (61)
Change in assets and
liabilities resulting
from operating
activities:
Accounts receivable
and other............ (970) (1,287) (224,181) -- (226,438)
Inventory............. -- (842) 34,772 -- 33,930
Pipeline linefill..... -- -- (3) -- (3)
Accounts payable and
other current
liabilities.......... 5,275 2,169 164,530 -- 171,974
Other long-term
liabilities.......... -- -- 18,873 -- 18,873
--------- -------- --------- -------- ---------
Net cash provided by
(used in) operating
activities............. (5,071) 34,877 (105,770) -- (75,964)
--------- -------- --------- -------- ---------
CASH FLOWS FROM
INVESTING ACTIVITIES
Payments for midstream
acquisitions (See Note
6)..................... -- -- (176,918) -- (176,918)
Payments for crude oil
pipeline, gathering and
terminal assets........ -- -- (12,507) -- (12,507)
Payments for
acquisition,
exploration, and
development costs...... (3,793) (74,106) -- -- (77,899)
Payments for additions
to other property and
assets................. (267) (2,137) (68) -- (2,472)
Proceeds from sale of
pipeline linefill...... -- -- 3,400 -- 3,400
--------- -------- --------- -------- ---------
Net cash provided by
(used in) investing
activities............. (4,060) (76,243) (186,093) -- (266,396)
--------- -------- --------- -------- ---------
CASH FLOWS FROM
FINANCING ACTIVITIES
Advances/investments
with affiliates........ (194,902) 46,306 148,396 200 --
Proceeds from long-term
debt................... 341,250 -- 403,721 -- 744,971
Proceeds from short-term
debt................... -- -- 131,119 -- 131,119
Proceeds from sale of
capital stock, options
and warrants........... 5,542 -- -- -- 5,542
Proceeds from issuance
of preferred stock..... 50,000 -- -- -- 50,000
Proceeds from issuance
of common units (Note
4)..................... (25,000) -- 75,759 -- 50,759
Principal payments of
long-term debt......... (180,711) -- (268,621) -- (449,332)
Principal payments of
short-term debt........ -- -- (82,150) -- (82,150)
Costs incurred in
connection with
financing
arrangements........... (2,205) -- (17,243) -- (19,448)
Preferred stock
dividends.............. (4,245) -- -- -- (4,245)
Distribution to
unitholders............ 29,472 -- (51,673) -- (22,201)
Other................... (971) -- -- -- (971)
--------- -------- --------- -------- ---------
Net cash provided by
financing activities... 18,230 46,306 339,308 200 404,044
--------- -------- --------- -------- ---------
Net increase in cash and
cash equivalents....... 9,099 4,940 47,445 200 61,684
Cash and cash
equivalents, beginning
of period.............. 142 194 6,408 (200) 6,544
--------- -------- --------- -------- ---------
Cash and cash
equivalents, end of
period................. $ 9,241 $ 5,134 $ 53,853 $ -- $ 68,228
========= ======== ========= ======== =========
F-47