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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K/A
Amendment No.1
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
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
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(ZIP CODE)
(713) 654-1414
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
Common Stock, par value $0.10 per share American Stock Exchange
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 March 15, 2000, there were 17,948,856 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 $243,674,442 on March 15, 2000 (based on $13 15/16 per share, the
last sale price of the Common Stock as reported on the American Stock Exchange
Composite Tape 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 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. AND SUBSIDIARIES
1999 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
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PAGE
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PART I
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Item 1. Business.............................................................................. 3
Item 2. Properties............................................................................ 29
Item 3. Legal Proceedings..................................................................... 33
Item 4. Submission of Matters to a Vote of Security Holders................................... 33
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters.................. 35
Item 6. Selected Financial Data............................................................... 36
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 38
Item 7a. Quantitative and Qualitative - Disclosures About Market Risks......................... 51
Item 8. Financial Statements and Supplementary Data........................................... 52
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. 52
PART III
Item 10. Directors and Executive Officers...................................................... 52
Item 11. Executive Compensation................................................................ 52
Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 52
Item 13. Certain Relationships and Related Transactions........................................ 52
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 53
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FORWARD-LOOKING STATEMENTS
This annual report on Form 10-K/A contains forward-looking statements and
information that are based on our beliefs, as well as assumptions made by, and
information currently available to us. All statements, other than statements of
historical fact, included in this report 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. Such 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 price fluctuations;
. the effects of competition;
. the success of our risk management activities;
. the availability (or lack thereof) of acquisition or combination
opportunities;
. the availability of adequate supplies of and demand for crude oil in
areas of midstream operations;
. 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 underlying
assumptions prove incorrect, actual results may vary materially from those in
the forward-looking statements. Except as required by applicable securities law,
we do not intend to update these forward-looking statements and information.
DEFINITIONS OF OIL AND GAS TERMS
As used in this report, "Bbl" means barrel, "MBbl" means thousand barrels,
"MMBbls" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "Btu" means British Thermal
Unit, "Mbtus" means thousand Btus, "BOE" means net barrel of oil equivalent and
"MCFE" means Mcf of natural gas equivalent. Natural gas equivalents and crude
oil equivalents are determined using the ratio of six Mcf of natural gas to one
Bbl of crude oil, condensate or natural gas liquids. A "working interest" is a
cost-bearing interest under an oil and gas lease that gives the holder the right
to produce and develop the minerals under the lease. A "net revenue interest" is
the lessee's share of production after satisfaction of all royalty and other non
cost-bearing interest. A "gross acre" is an acre in which an interest is owned.
The number of "net acres" is the sum of the fractional working interests owned
in gross acres. "Net" oil and natural gas wells are obtained by multiplying
"gross" oil and natural gas wells by our working interest in the applicable
properties. "Present Value of Proved Reserves" means the present value
(discounted at 10%) of estimated future cash flows from proved oil and natural
gas reserves, as estimated by our independent engineers, reduced by additional
estimated future operating expenses, development expenditures and abandonment
costs (net of salvage value) associated therewith (before income taxes). The
present value of proved reserves is calculated using product prices in effect on
the date of determination. "Standardized Measure" is such amount further reduced
by the present value (discounted at 10%) of estimated future income taxes on
such cash flows. "NYMEX" means New York Mercantile Exchange.
2
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PART I
ITEMS 1. BUSINESS
GENERAL
We are an independent energy company that is engaged in two related lines of
business within the energy sector industry. Our first line of business, which we
refer to as "upstream", acquires, exploits, develops, explores and produces
crude oil and natural gas. Our second line of business, which we refer to as
"midstream", is engaged in the marketing, transportation and terminalling of
crude oil. 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". We conduct this second line of
business through our majority ownership in Plains All American Pipeline, L.P.
("PAA").
One of our wholly owned subsidiaries, Plains All American Inc., is both the
general partner and majority owner of PAA. Because it holds the general partner
interest and owns approximately 18.2 million common and subordinated units,
Plains All American Inc. holds an approximate 54% interest in PAA. For financial
statement purposes, the assets, liabilities and earnings of PAA are included in
our consolidated financial statements, with the public unitholders' interest
reflected as a minority interest. The following chart sets forth the
organization relationship of the subsidiaries in our two lines of business:
[PLAINS RESOURCES ORGANIZATIONAL CHART]
3
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UNAUTHORIZED TRADING LOSSES
Background
In November 1999, we discovered that a former employee of PAA had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated 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. Because the financial statements of PAA are
consolidated with our financial statements, adverse effects on the financial
statements of PAA directly affect our consolidated financial statements. As a
result, we have restated our previously reported 1999 and 1998 results to
reflect the losses incurred from these unauthorized trading activities (see Note
3 in the notes to our consolidated financial statements appearing elsewhere in
this report.
Normally, as PAA purchases crude oil, it establishes a margin by selling crude
oil for physical delivery to third parties, or by entering into future delivery
obligations with respect to futures contracts. The employee in question violated
PAA's policy of maintaining a substantially balanced position between purchases
and sales (or future delivery obligations) by negotiating one side of a
transaction without negotiating the other, leaving the position "open." The
trader concealed his activities by hiding open trading positions, by rolling
open positions forward using off-market, inter-month transactions, and by
providing to counter-parties forged documents that purported to authorize such
transactions. An "inter-month" transaction is one in which the receipt and
delivery of crude oil are scheduled in different months. An "off-market"
transaction is one in which the price is higher or lower than the prices
available in the market on the day of the transaction. By matching one side of
an inter-month transaction with an open position, and using off-market pricing
to match the pricing of the open position, the trader could present
documentation showing both a purchase and a sale, creating the impression of
compliance with PAA's policy. The offsetting side of the inter-month transaction
became a new, hidden open position.
Investigation; Enhancement of Procedures
Upon discovery of the violation and related losses, PAA engaged an outside law
firm to lead the investigation of the unauthorized trading activities. The law
firm retained specialists from an independent accounting firm to assist in the
investigation. In parallel effort with the investigation mentioned above, the
role of the accounting-firm specialists was expanded to include reviewing and
making recommendations for enhancement of PAA's systems, policies and
procedures. As a result, PAA has developed a new written policy document and
manual of procedures designed to enhance its processes and procedures and
improve its ability to detect any activity that might occur at an early
stage.
The new policy was adopted by the Board of Directors of Plains All American
Inc. in May 2000; however, implementation of many of the procedures commenced in
January 2000, based on information developed throughout the investigation and
the review of the policies, processes and procedures. In March 2000, management
hired another independent accounting firm to provide additional objective input
regarding the processes and procedures, and to supplement management's efforts
to expedite the implementation of the enhanced policies and automation of the
processes and procedures. The procedures have now been implemented, although not
all reports are fully automated. The procedures have been, and will continue to
be, refined.
To specifically address the methods used by the trader to conceal the
unauthorized trading, in January 2000 PAA sent a notice to each of its material
counter-parties that no person at PAA was authorized to enter into off-market
transactions. In addition, PAA has taken the following actions:
. PAA has communicated its trading strategies and risk tolerance to its
traders by more clearly and specifically defining those strategies and risk
limits in its written procedures.
. The new procedures require (i) more comprehensive and frequent reporting
that will allow PAA officials to evaluate risk positions in greater detail,
and (ii) enhanced procedures to check compliance with these reporting
requirements and to confirm that trading activity was conducted within
guidelines.
. The procedures provide a system to educate each employee who is involved,
directly or indirectly, in PAA's crude oil transaction activities with
respect to policies and procedures, and impose an obligation to notify the
Risk Manager (a new, independent function that reports directly to the
Chief Financial Officer) directly or any questionable transactions or
failure of others to adhere to the policies, practices and procedures.
. Finally, following notification to each of its material counter-parties
that off-market trading is against PAA's policy and that any written
evidence to the contrary is unauthorized and false, the Risk Manager and
other PAA representatives have also communicated our policies and enhanced
procedures to our counter-parties to advise them of the information we will
routinely require from them to assure timely recording and confirmation of
trades.
We can give no assurance that the above steps will serve to detect and prevent
all violations of PAA's trading policy; we believe, however, that such steps
substantially reduce the possibility of a recurrence of unauthorized trading
activities, and that any unauthorized trading that does occur would be detected
before any material loss could develop.
Effects of the Loss
The unauthorized trading and associated losses resulted in a default of
certain covenants under PAA's credit facilities and significant short-term cash
and letter of credit requirements. See Item 7. -- "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources."
Although one of our wholly-owned subsidiaries is the general partner of and
owns 54% of PAA, the trading losses do not affect the operations or assets of
our upstream business. The debt of PAA is nonrecourse to us. In addition, our
indirect ownership in PAA does not collateralize any of our credit facilities.
Our $225.0 million credit facility is collateralized by our oil and natural gas
properties.
In December 1999, PAA executed amended credit facilities and obtained default
waivers from all of its lenders. The amended credit facilities:
. waived defaults under covenants contained in the existing credit
facilities;
. increased availability under PAA's letter of credit and borrowing
facility from $175.0 million in November 1999 to $295.0 million in
December 1999, $315.0 million in January 2000, and thereafter decreasing
to $239.0 million in February through April 2000, to $225.0 million in
May and June 2000 and to $200.0 million in July 2000 through July 2001;
. required the lenders' consent prior to the payment of distributions to
unitholders;
. prohibited contango inventory transactions subsequent to January 20,
2000; and
. increased interest rates and fees under certain of the facilities.
PAA paid approximately $13.7 million to its lenders in connection with the
amended credit facilities. This amount was capitalized as debt issue costs and
will be amortized over the remaining term of the amended facilities. In
connection with the amendments, we loaned approximately $114.0 million to PAA.
This subordinated debt is due not later than November 30, 2005. We financed the
$114.0 million that we loaned PAA with:
. the issuance of a new series of our 10% convertible preferred stock for
proceeds of $50.0 million;
. cash distributions of approximately $9.0 million made in November 1999
to PAA's general partner; and
. $55.0 million of borrowings under our revolving credit facility.
In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of PAA's suppliers and trading partners reduced or
eliminated the open credit previously extended to PAA. Consequently, the amount
of letters of credit PAA needed to support the level of its crude oil purchases
then in effect increased significantly. In addition, PAA's cost of obtaining
letters of credit increased under the amended credit facility. In many instances
PAA arranged for letters of credit to secure its obligations to purchase crude
oil from its customers, which increased its letter of credit costs and decreased
its unit margins. In other instances, primarily involving lower margin wellhead
and bulk purchases, certain of PAA's purchase contracts were terminated. As a
result of these changes, aggregate volumes purchased are expected to decrease by
150,000 barrels per day, consisting primarily of lower unit margin purchases.
Approximately 50,000 barrels per day of the decrease is related to barrels
gathered at producer lease locations and 100,000 barrels per day is attributable
to bulk purchases. As a result of the increase in letter of credit costs and
reduced volumes, annual Adjusted EBITDA is expected to be adversely affected by
approximately $5.0 million, excluding the positive impact of current favorable
market conditions. Adjusted EBITDA means earnings before interest expense,
income taxes, depreciation, depletion and amortization ("DD&A"), unauthorized
trading losses, noncash compensation expense, restructuring expense, gain on
unit offerings, linefill gain and extraordinary loss from extinguishment of
debt.
4
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RESULTS OF OPERATIONS
For the year ended December 31, 1999, our Adjusted EBITDA, cash flow from
operations and net loss totaled $139.1 million, $70.4 million and $25.3 million,
respectively. Excluding the unauthorized trading losses, our net income for the
year ended December 31, 1999 would have been $32.9 million. Cash flow from
operations represents net income before noncash items. Cash flow from operations
also excludes the unauthorized trading losses, noncash compensation expense,
restructuring expense, gain on unit offerings, linefill gain and extraordinary
loss from extinguishment of debt. Our upstream operations contributed
approximately 38% of our Adjusted EBITDA for the fiscal year ending December 31,
1999, while our midstream activities accounted for approximately 62%.
UPSTREAM ACTIVITIES
Our upstream business strategy is to increase our proved reserves and cash
flow by:
. exploiting and producing crude oil and associated natural gas from our
existing properties;
. acquiring additional underdeveloped crude oil properties; and
. exploring for significant new sources of reserves.
We concentrate our acquisition and exploitation efforts on mature but
underdeveloped crude oil producing properties that meet our targeted criteria.
Generally, the properties that we consider acquiring and exploiting are owned by
major integrated or large independent oil and natural gas companies and have
produced significant volumes since initial discovery and also 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 nonstrategic or fully valued. These sales enable us to focus
on our core properties, maintain our financial flexibility, control our overhead
and redeploy the sales proceeds to activities that have potentially higher
financial returns. We are able to take advantage of the marketing expertise that
PAA has developed through our marketing agreement with PAA, under which PAA is
the exclusive purchaser/marketer of all our equity crude oil production.
During the five-year period ended December 31, 1999, we incurred aggregate
acquisition, exploitation, development, and exploration costs of approximately
$436.6 million, resulting in proved crude oil and natural gas reserve additions
(including revisions of estimates but excluding production) of approximately
204.9 million BOE, or $2.13 per BOE, through implementation of this business
strategy. We spent approximately 97% of this capital in acquisition,
exploitation and development activities and we spent approximately 3% on our
exploration activities.
To manage our exposure to commodity price risk, our upstream business
routinely hedges a portion of its crude oil production. For 2000, we have
entered into various arrangements under which we will receive an average minimum
NYMEX West Texas Intermediate ("WTI") crude oil price of approximately $16.00
per barrel on 18,500 barrels per day (equivalent to 79% of fourth quarter 1999
crude oil production levels). Approximately 10,000 barrels per day of the
volumes that we have hedged in 2000 will participate in price increases above
the $16.00 floor price, subject to a ceiling limitation of approximately $19.75
per barrel. For 2001, we have entered into various arrangements under which we
will receive an average minimum NYMEX WTI price of approximately $19.00 per
barrel on 12,000 barrels per day, which is equivalent to 51% of our fourth
quarter 1999 crude oil production levels. Of these volumes, 100% have full
market price participation up to $27.00 per barrel, 50% have price participation
between $27.00 per barrel and $30.00 per barrel and 100% have full market price
participation at prices above $30.00 per barrel. All of our NYMEX WTI crude oil
prices are before quality and location differentials. Because of the quality and
location of our crude oil production, these adjustments will reduce our net
price per barrel. 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. At December 31, 1999, the total market
value of our crude oil subject to hedges exceeded the amounts we will receive
under our hedged prices by approximately $21.0 million.
5
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The following table sets forth certain information with respect to our
reserves over the last five years. Our reserve volumes and values were
determined under the method prescribed by the Securities and Exchange Commission
("SEC"), which requires the application of year-end crude oil and natural gas
prices for each year, held constant throughout the projected reserve life. The
benchmark NYMEX crude oil price of $25.60 per barrel used in preparing year-end
1999 reserve estimates was more than double the $12.05 per barrel used in
preparing reserve estimates at the end of 1998. The year-end 1998 NYMEX crude
oil price was the lowest year-end crude oil price since oil was deregulated in
1980.
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AS OF OR FOR THE YEAR ENDED DECEMBER 31,
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1999 1998 1997 1996 1995
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(IN THOUSANDS, EXCEPT RATIOS AND PER UNIT AMOUNTS)
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Present Value of Proved Reserves (1) $1,246,049(1) $226,943(1) $510,993 $764,774 $366,780
Proved Reserves (2)
Crude oil and natural gas liquids (Bbls) 218,922 120,208 151,627 115,996 94,408
Natural gas (Mcf) 90,873 86,781 60,350 37,273 43,110
Oil equivalent (BOE) 234,068(1) 134,672 (1) 161,685 122,208 101,593
Reserve Replacement Ratio (3) 1,263% (229%)(4) 603%(5) 454% 647%(6)
Reserve Replacement Cost per BOE (7) $ 0.68 $ (5.46) $ 2.71 $ 1.76 $ 2.14
Total upstream capital costs incurred $ 72,979 $100,935 $127,378 $ 51,255 $ 84,012
Percentage of total upstream capital
costs attributable to:
Acquisition 5% 10% 34% 7% 71%
Development 89% 88% 65% 88% 27%
Exploration 6% 2% 1% 5% 2%
Year-end Crude Oil Price $ 20.94 $ 7.96 $ 13.91 $ 22.22 $ 15.55
Year-end Natural Gas Price $ 2.77 $ 1.68 $ 2.13 $ 2.79 $ 1.05
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(1) We have reduced the pre-tax present value of proved reserves and the future
net revenues of certain properties to reflect applicable abandonment and
hedging costs and with respect to the LA Basin Properties, a net profits
interest owned by a third party.
(2) A 50% net profits interest attaches to the net proceeds from approximately
7.0 million barrels of our proved reserves in the L.A. Basin at December
31, 1999.
(3) The reserve replacement ratio is calculated by dividing (a) the sum of
reserves added during each respective year through purchases of reserves in
place, extensions, discoveries and other additions and the effect of
revisions, if any (b) each respective years' production.
(4) The reserve replacement ratio for 1998 is negative due to a negative
volume revision related to low crude oil prices at December 31, 1998.
(5) Pro forma as if the acquisitions of the Montebello and Arroyo Grande Fields
occurred on January 1, 1997. Such acquisitions closed in March and November
1997, respectively, with effective dates of February 1, 1997, and November
1, 1997, respectively.
(6) Pro forma as if the acquisition of the Illinois Basin Properties occurred
on January 1, 1995. Such acquisition closed in December 1995 with an
effective date of November 1, 1995.
(7) Reserve replacement cost per BOE for a year is calculated by dividing
upstream capital costs incurred for such year by such year's reserve
additions.
ACQUISITION AND EXPLOITATION
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 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. Generally, 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.
Once we identify a prospective property for acquisition, we conduct a
technical review of existing production and operating practices to identify and
quantify underexploitated value. If the initial studies indicate undeveloped
potential, the various producing and potentially productive formations in the
area are mapped in detail. Historical production data is
6
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evaluated to determine if additional wells or other capital expenditures appear
necessary to optimize the recovery of reserves from the property. Geologic and
engineering information and operating practices utilized by operators on
offsetting leases are analyzed to identify potential additional exploitation and
development opportunities. A market study is also performed analyzing product
markets, available pipeline connections, access to trading locations and
existing contractual arrangements with the goal of maximizing sales and profit
margins from the area. See "--Product Markets and Major Customers". A
comprehensive plan of exploitation is then prepared and used as a basis for our
offer to purchase.
We seek to acquire a majority interest in the properties we have identified
and to act as operator of those properties. We have in the past and may in the
future hedge a significant portion of the acquired production, thereby partially
mitigating product price volatility that could have an adverse impact on
exploitation opportunities. If we successfully purchase properties, we then
implement our exploitation plan by modifying production practices, realigning
existing waterflood patterns, drilling wells and performing workovers,
recompletions and other production 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, 1999, net additions and revisions to proved reserves
totaled 129.7 million BOE or approximately 368% of cumulative net production for
this period. These reserves were added at an aggregate average cost of $2.44 per
BOE. This activity excludes reserves added as a result of our acquisition
activities. Reserve additions related solely to our acquisition activities
totaled 75.2 million BOE and were added at an aggregate average cost of $1.60
per BOE.
The properties in our four core areas represent approximately 99% of total
proved reserves at December 31, 1999. These properties were previously owned and
operated by major integrated oil and natural gas companies and are comprised of
underdeveloped crude oil properties that we believed to have significant upside
potential that can be evaluated through development and exploitation activities.
During 2000, we estimate that we will spend approximately $72.0 million on the
development and exploitation of our upstream crude oil and natural gas
properties. Set forth below is a discussion of these properties.
Current Exploitation Projects
The following table sets forth certain information with respect to our crude
oil and gas properties (dollars in millions):
<TABLE>
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CALIFORNIA PROPERTIES
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ARROYO POINT SUNNILAND ILLINOIS
LA BASIN MONTEBELLO GRANDE MT. POSO ARGUELLO TREND BASIN
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Year(s) Acquired 1992 1997 1997 1998 1999 1993/1994 1995
Year(s) Discovered 1924 - 1966 1917 1906 1926 1981 1943 1905
Proved reserves at acquisition - MMBOE 17.7 23.3 19.9 7.7 6.4 5.0 17.3
CUMULATIVE FROM ACQUISITION DATE:
---------------------------------
Direct acquisition, development and
exploitation capital spent $ 174.7 $ 55.2 $ 27.3 $ 13.9 $ 1.8 $ 81.8 $ 79.6
Production - MMBOE 26.3 1.6 1.2 0.3 0.8 9.0 5.2
Cumulative gross margin(1) $ 199.4 $ 9.6 $ 5.0 $ 2.8 $ 4.0 $ 58.1 $ 51.4
Aggregate reserve addition cost $ 1.49 $ 2.72 $ 0.43 $ 1.74 $0.28 $ 2.50 $ 2.74
AS OF DECEMBER 31, 1999:
------------------------
Proved Reserves - MMBOE 90.8(2) 18.7 62.4 7.6 5.6 23.7 23.8
Future Net Revenues(3) $ 1,197.2 $201.8 $800.1 $103.2 $47.8 $ 205.9 $277.9
Pre-tax Present Value of
Proved Reserves(3) $ 535.0 $ 90.1 $264.3 $ 60.0 $40.5 $ 136.7 $115.5
% Proved Undeveloped 30% 20% 87% 55% 43% 34% 12%
1999 Unit Gross Margin $ 7.45 $ 8.83 $ 7.53 $ 7.92 $4.92 $ 2.48 $ 9.63
Estimated development and
exploitation capital budgeted
in 2000 $ 31.0 $ 3.0 $ 10.0 $ 7.0 $ 9.0 $ 2.0 $ 10.0
</TABLE>
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(1) Represents revenues less production expenses from date of acquisition.
(2) We own a 100% working interest in the LA Basin property. A 50% net profits
interest attaches to the net proceeds from approximately 7.0 million barrels
of our proved reserves in the L.A. Basin at December 31, 1999.
(3) We have reduced the pre-tax present value of proved reserves and the future
net revenues of certain properties to reflect applicable abandonment and
hedging costs and with respect to the L.A. Basin Properties, a 50% net
profits interest owned by a third party.
Onshore California Properties. 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. 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. We refer to all of our
properties in the LA Basin acquired
7
<PAGE>
prior to 1997 collectively as 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
wells, returning previously marginal wells to economic production, optimizing
waterflood operations, improving artificial lift and facility equipment,
reducing unit production expenses and improving marketing margins. 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 11,000 BOE per day during the fourth quarter of 1999.
We expanded our operations in the LA Basin with the acquisition of the
Montebello Field, and expanded into other California areas with the acquisition
of the Arroyo Grande Field and the Mt. Poso Field. Combined, these three fields
added approximately 50.9 million BOE to our proved reserves at the acquisition
dates.
In March 1997, we completed the acquisition of Chevron's interest in the
Montebello Field for approximately $25.0 million, effective February 1, 1997.
The assets acquired consisted of a 100% working interest and a 99.2% net revenue
interest in 55 producing crude oil wells and related facilities and also
included approximately 450 acres of surface fee land. The Montebello Field is
located approximately 15 miles from our existing LA Basin operations. Our net
average daily production from this field has increased from approximately 930
BOE per day at the acquisition date to an average of approximately 2,100 BOE per
day during the fourth quarter of 1999.
In November 1997, we acquired a 100% working interest and a 97% net revenue
interest in the Arroyo Grande Field which is located in San Luis Obispo County,
California from subsidiaries of Shell Oil Company ("Shell"). The Arroyo Grande
field was discovered in 1906 and has produced approximately 11 MMBbls of crude
oil or approximately 5% of the estimated original crude oil in place. The assets
acquired included surface and development rights to approximately 1,000 acres
included in the 1,500 acre unit. The field is under continuous steam injection
and at the acquisition date, was producing approximately 1,600 barrels per day
(approximately 1,500 barrels net to our interest) of 14 degree API gravity crude
oil from 70 wells. The aggregate consideration for the Arroyo Grande Field
consisted of (1) rights to a non-producing property interest conveyed to Shell,
(2) the issuance of 46,600 shares of Series D Cumulative Convertible Preferred
Stock with an aggregate stated value of $23.3 million, and (3) a five-year
warrant to purchase 150,000 shares of our common stock at $25.00 per share. No
proved reserves had been assigned to the rights to the property interest
conveyed. Unit production expenses for the Arroyo Grande Field, which averaged
$9.36 per BOE at the acquisition date, averaged $5.26 per BOE during the fourth
quarter of 1999. Our net average daily production from this field was
approximately 1,600 barrels per day during 1999.
During 1998, we acquired the Mt. Poso Field from Aera Energy LLC for
approximately $7.7 million. The field is located approximately 27 miles north of
Bakersfield, California, in Kern County. At acquisition, the field was producing
900 barrels of crude oil per day of 15 - 17 degree API gravity crude and added
approximately 7.7 MMBbls of crude oil to our proved reserves. Our net average
daily production from this field was approximately 950 barrels per day during
1999.
Offshore California Properties. In July 1999, Arguello Inc., our wholly owned
subsidiary, acquired Chevron's interests in Point Arguello for approximately
$1.0 million. The acquisition, which was funded from our working capital, had an
effective date of July 1, 1999. The interests acquired include Chevron's 26%
working interest in the Point Arguello Unit, its 26% interest in various
partnerships owning the associated transportation, processing and marketing
infrastructure, and Chevron's right to participate in surrounding leases and
certain fee acreage onshore. We assumed Chevron's 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. 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. Arguello Inc. is the operator of record for the Point Arguello Unit
and has entered into an outsourcing agreement with a unit of Torch Energy
Advisors, Inc. for the conduct of certain field operations and other
professional services. At acquisition, gross production from the field was
approximately 20,100 barrels of crude oil per day (approximately 5,200 barrels
per day, net to our interest) from 25 wells located on 3 offshore platforms. The
acquisition added approximately 6.4 MMBbls of crude oil to our proved reserves.
Our net average daily production from this property was approximately 4,400
barrels per day during the six months we owned the property in 1999.
As with our other properties, we intend to aggressively exploit Point
Arguello to evaluate additional reserve potential identified during our
acquisition analysis. Our exploitation plans for this property target improving
the unit gross margin by lowering costs and increasing production volumes
through production enhancement activities similar to those employed in our other
properties.
8
<PAGE>
Sunniland Trend Properties. We have a 100% working interest in four producing
fields in South Florida located in the Sunniland Trend that were previously
owned and operated by Exxon Corporation. We acquired 50% of our interest in the
properties in 1993 and the remaining 50% in 1994. At the time of our initial
acquisition, production net to our interest was approximately 900 barrels per
day. As a result of increasing our interest to 100%, development drilling on the
property, and the implementation of exploitation activities designed primarily
to repair failed wells and to increase the fluid lift capacity of certain wells,
our net production peaked at an annual average of 5,300 barrels per day in 1997.
During 1999, production from this area averaged 2,600 barrels per day. The
production decrease is due to downtime as a result of mechanical problems and
the effects of natural decline. During 1998 and 1999, several wells in this area
had mechanical problems and were not returned to production due to lower
operating margins. We expect that the rate of production decline in this area
will decrease as several wells have been returned to production due to higher
crude oil prices and overall declined rates are flattening out.
Illinois Basin Properties. In December 1995, we acquired all of Marathon Oil
Company's producing and nonproducing upstream crude oil and natural gas assets
in the Illinois Basin for approximately $51.5 million, including transaction
costs. Our initial exploitation plan for the Illinois Basin Properties included
improving the unit gross margin by decreasing unit production expenses and
increasing price realizations. Unit production expenses for these properties,
which averaged $12.00 per BOE in the fourth quarter of 1995, averaged
approximately $8.64 per BOE during 1999. The primary focus of our development
and exploitation program during 2000 for the Illinois Basin Properties will be
directed towards development drilling, performing reservoir characterization and
selecting chemical mixtures to potentially implement an alkaline-surfactant-
polymer pilot enhanced oil recovery project. Our net average daily production
from this property was approximately 3,000 barrels per day during 1999.
General. 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, impediments in marketing
production, 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.
We believe that attractive acquisition opportunities that fit our criteria
will continue to be made available by both major and independent oil companies.
In addition to more typical acquisitions, we also intend to pursue joint
ventures and strategic alliances that provide us the opportunity to use our
exploitation and operating skillsets and our capital without acquiring the
entire property interest. While we are continually evaluating such
opportunities, there can be no assurance that any of these efforts will be
successful. Our ability to continue to acquire attractive properties may be
adversely affected by:
. a reduction in the number of attractive properties offered for sale;
. increased competition for properties from other independent oil
companies;
. unavailability of capital;
. incorrect estimates of reserves;
. exploitation potential or environmental liabilities or other factors.
Although we have historically acquired producing properties located only in the
continental United States, from time to time we evaluate, and may in the future
seek to acquire, properties located outside the continental United States.
DISPOSITION OF PROPERTIES
We periodically evaluate, and from time to time have elected to sell, certain
of our mature producing properties that we consider to be nonstrategic or fully
valued. Such sales enable us to focus on our core properties, maintain financial
flexibility, reduce overhead and redeploy the proceeds therefrom to activities
that we believe have a higher potential financial return. We have not made any
material sales of our producing properties during our last three fiscal
years.
MIDSTREAM ACTIVITIES
GENERAL
We conduct our midstream activities through PAA, which was formed in 1998 to
acquire and operate the business and assets of our wholly owned midstream
subsidiaries. PAA engages in interstate and intrastate crude oil transportation,
terminalling and storage, as well as crude oil gathering and marketing
activities. In 1999, PAA grew through acquisitions and internal development to
become one of the largest transporters, terminal operators, gatherers and
marketers of crude oil in the United States. At the beginning of 2000, PAA
handled an average of approximately 650,000 barrels of crude oil per day. Its
operations are concentrated in California, Texas, Oklahoma, Louisiana and the
Gulf of Mexico.
9
<PAGE>
Our midstream business strategy is to capitalize on the regional crude oil
supply and demand imbalances that exist in the continental United States by
combining the strategic location and unique capabilities of our transportation
and terminalling assets with our extensive marketing and distribution expertise
to generate sustainable earnings and cash flow. We intend to execute our
midstream business strategy by:
. increasing and optimizing the amount of crude oil we transport on our
various pipeline and gathering assets;
. realizing cost efficiencies through operational improvements and
potential strategic alliances;
. utilizing our Cushing Terminal and other assets to service the needs of
refiners and to profit from merchant activities that take advantage of
crude oil pricing and quality differentials; and
. pursuing strategic and accretive acquisitions of crude oil pipeline
assets, gathering systems and terminalling and storage facilities that
complement our existing asset base and distribution capabilities.
Our midstream line of business 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 our storage tanks;
. transferring crude oil from pipelines and storage tanks to trucks,
barges or other pipelines through our terminals;
. marketing crude oil produced by Plains Resources;
. 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.
The principal assets used in this segment include:
. a 3.1 million barrel, above-ground crude oil storage and terminal
facility at Cushing, Oklahoma;
. the segment of the All American Pipeline that extends approximately 140
miles from Las Flores, California to Emidio, California;
. the San Joaquin Valley Gathering System in California;
. the West Texas Gathering System, the Spraberry Pipeline System, and the
East Texas Pipeline System, which are all located in Texas;
. the Sabine Pass Pipeline System in southwest Louisiana and southeast
Texas;
. the Ferriday Pipeline System in eastern Louisiana and western
Mississippi;
. the Illinois Basin Pipeline System in southern Illinois; and
. approximately 280 trucks, 325 tractor-trailers and 290 injection
stations, which are owned or leased and used in our gathering and
marketing activities.
MIDSTREAM ACQUISITIONS AND DISPOSITIONS
Scurlock Acquisition
On May 12, 1999, we completed the acquisition of Scurlock Permian LLC 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.
Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum,
is engaged in crude oil transportation, gathering and marketing, and owns
approximately 2,300 miles of active pipelines, numerous storage terminals and a
fleet of more than 250 trucks. Its largest asset is an 800-mile pipeline and
gathering system located in the Spraberry Trend in West Texas that extends into
Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets
we acquired also included approximately one million barrels of crude oil
linefill.
10
<PAGE>
Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under Plains Scurlock's
limited recourse bank facility with BankBoston, N.A.;
. 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
. 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 Class B units are initially pari
passu with common units with respect to distributions, and are convertible into
common units upon approval of a majority of the common unitholders. The Class B
unitholders may request that PAA call a meeting of common unitholders to
consider approval of the conversion of Class B units into common units. If the
approval of a conversion by the common unitholders is not obtained within 120
days of a request, each Class B unitholder will be entitled to receive
distributions, on a per unit basis, equal to 110% of the amount of distributions
paid on a common unit, with such distribution right increasing to 115% if such
approval is not secured within 90 days after the end of the 120-day period.
Except for the vote to approve the conversion, Class B units have the same
voting rights as the common units.
West Texas Gathering System Acquisition
On July 15, 1999, we completed the acquisition of the West Texas Gathering
System from Chevron Pipe Line Company for approximately $36.0 million. Financing
for the amounts paid at closing was provided by a draw under the term loan
portion of the Plains Scurlock credit facility. The assets acquired include
approximately 450 miles of crude oil transmission mainlines, approximately 400
miles of associated gathering and lateral lines, and approximately 2.9 million
barrels of tankage located along the system.
All American Pipeline Linefill Sale and Asset Disposition
We initiated the sale of approximately 5.2 million barrels of crude oil
linefill from the All American Pipeline in November 1999. This sale was
substantially completed in February 2000. The linefill was located in the
segment of the All American Pipeline that extends from Emidio, California, to
McCamey, Texas. Except for minor third party volumes, Plains Marketing, L.P.,
one of PAA's subsidiaries, has been the sole shipper on this segment of the
pipeline since its predecessor acquired the line from the Goodyear Tire & Rubber
Company in July 1998. Proceeds from the sale of the linefill were approximately
$100 million, net of associated costs, and were used for working capital
purposes. We estimate that we will recognize a total gain of approximately $44.6
million in connection with the sale of linefill. As of December 31, 1999, we had
delivered approximately 1.8 million barrels of linefill and recognized a gain of
$16.5 million.
On March 24, 2000, we completed the sale of the above referenced segment of
the All American Pipeline to a unit of El Paso Energy Corporation for total
proceeds of $129.0 million. The proceeds from the sale were used to reduce
outstanding debt. Our net proceeds are expected to be approximately $124.0
million, net of associated transaction costs and estimated costs to remove
certain equipment. We estimate that we will recognize a gain of approximately
$20.0 million in connection with the sale. During 1999, we reported gross margin
of approximately $5.0 million from volumes transported on the segment of the
line that was sold.
CRUDE OIL PIPELINE OPERATIONS
We present below a description of our principal pipeline assets. All of our
pipeline systems are operated from one of two central control rooms with
computer systems designed to continuously monitor real time operational data
including measurement of crude oil quantities injected in and delivered through
the pipelines, product flow rates and pressure and temperature variations. This
monitoring and measurement technology provides us the ability to efficiently
batch differing crude oil types with varying characteristics through the
pipeline systems. The systems are designed to enhance leak detection
capabilities, sound automatic alarms in the event of operational conditions
outside of pre-established parameters and provide for remote-controlled shut-
down of pump stations on the pipeline systems. Pump stations, storage facilities
and meter measurement points along the pipeline systems are linked by telephone,
microwave, satellite or radio communication systems for remote monitoring and
control, which reduces our requirement for full time site personnel at most of
these locations.
11
<PAGE>
We perform scheduled maintenance on all of our pipeline systems and make
repairs and replacements when necessary or appropriate. We attempt to control
corrosion of the mainlines through the use of corrosion inhibiting chemicals
injected into the crude stream, external coatings and anode bed based or
impressed current cathodic protection systems. Maintenance facilities containing
equipment for pipe repairs, spare parts and trained response personnel are
strategically located along the pipelines and in concentrated operating areas.
We believe that all of our pipelines have been constructed and are maintained in
all material respects in accordance with applicable federal, state and local
laws and regulations, standards prescribed by the American Petroleum Institute
and accepted industry practice.
All American Pipeline
The segment of the All American Pipeline that was not sold to El Paso (see
" - All American Pipeline Linefill Sale and Asset Disposition") is a common
carrier crude oil pipeline system that transports crude oil produced from fields
offshore and onshore California to locations in California pursuant to tariff
rates regulated by the Federal Energy Regulatory Commission ("FERC") (see
" - Regulation - Transportation of Crude Oil"). As a common carrier, the All
American Pipeline offers transportation services to any shipper of crude oil,
provided that the crude oil tendered for transportation satisfies the conditions
and specifications contained in the applicable tariff. The All American Pipeline
transports crude oil for third parties as well as for us.
We currently operate the segment of the system that extends approximately 10
miles from Exxon's onshore facilities at Las Flores on the California coast to
our onshore facilities at Gaviota, California (24 inch diameter pipe) and
continues from Gaviota approximately 130 miles to our station in Emidio,
California (30-inch pipe). Between Gaviota and our Emidio Station, the All
American Pipeline interconnects with our SJV Gathering System as well as various
third party intrastate pipelines, including the Unocap Pipeline System, Pacific
Pipeline, and a pipeline owned by EOTT Energy Partners, L.P.
System Supply. The All American Pipeline currently transports Outer
Continental Shelf crude oil received at the onshore facilities of the Santa Ynez
field at Las Flores, California and the onshore facilities of the Point Arguello
field located at Gaviota, California.
Effective December 1, 1999, the segment of the All American Pipeline that was
sold to El Paso ceased being used for crude oil transportation. Exxon, which
owns all of the Santa Ynez production, Texaco and Sun Operating L.P., which
together own approximately 25% of the Point Arguello production, have entered
into transportation agreements committing to transport all of their production
from these fields on the segment of the All American Pipeline which we retained.
These agreements, which expire in August 2007, provide for a minimum tariff with
annual escalations. At December 31, 1999, the tariffs averaged $1.41 per barrel
for deliveries to connecting pipelines in California. The agreements do not
require these owners to transport a minimum volume. The producers from the Point
Arguello field who do not have contracts with us have no other means of
transporting their production and, therefore, ship their volumes on the All
American Pipeline at the posted tariffs. For the year ended December 31, 1999,
approximately $30.6 million, or 17%, of our gross margin was attributable to the
Santa Ynez field and approximately $10.6 million, or 6% was attributable to the
Point Arguello field. Transportation of volumes from the Point Arguello field on
the All American Pipeline commenced in 1991 and from the Santa Ynez field in
1994.
The table below sets forth the historical volumes received from both of these
fields.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
1999 1998 1997 1996 1995 1994 1993 1992 1991
-------- ------- ------- -------- --------- -------- -------- ------- -------
(BARRELS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average daily volumes received from:
Point Arguello (at Gaviota) 20 26 30 41 60 73 63 47 29
Santa Ynez (at Las Flores) 59 68 85 95 92 34 - - -
------- ------ ------ ------- ------- ------ ------ ------ -------
Total 79 94 115 136 152 107 63 47 29
======= ====== ====== ======= ======= ====== ====== ====== =======
</TABLE>
In July 1999, a wholly-owned subsidiary of ours acquired Chevron USA's 26%
working interest in Point Arguello and is the operator of record for the Point
Arguello Unit. All of the volumes attributable to our interests are committed
for transportation on the All American Pipeline and are subject to our Marketing
Agreement with PAA. We expect that there will continue to be natural production
declines from each of these fields as the underlying reservoirs are depleted. As
operator of Point Arguello, we are conducting additional drilling and other
activities on this field, but we can not assure you that these activities will
affect the production decline.
12
<PAGE>
San Joaquin Valley Supply. The San Joaquin Valley is one of the most prolific
oil producing regions in the continental United States, producing approximately
559,000 barrels per day of crude oil during the first nine months of 1999 that
accounted for approximately 67% of total California production and 11% of the
total production in the lower 48 states.
The following table reflects the historical production for the San Joaquin
Valley as well as total California production (excluding OCS volumes) as
reported by the California Division of Oil and Gas.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------------------
1999 (1) 1998 1997 1996 1995 1994 1993 1992 1991 1990
---------- ------ -------- -------- -------- -------- -------- -------- ------- -------
(BARRELS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Average daily volumes:
San Joaquin Valley production (2) 559 592 584 579 569 578 588 609 634 629
Total California production
(excluding OCS volumes) 731 781 781 772 764 784 803 835 875 879
</TABLE>
-----------
(1) Reflects information through September 1999.
(2) Consists of production from California Division of Oil and Gas District IV.
System Demand. Deliveries from the All American Pipeline are made to
California refineries through connections with third-party pipelines at Sisquoc,
Pentland and Emidio. Deliveries at Mojave were discontinued in the second
quarter of 1999, and volumes previously delivered to Mojave are delivered to
Emidio. Except for the purging of the linefill volumes, deliveries to Texas were
discontinued effective December 1, 1999.
13
<PAGE>
The following table sets forth All American Pipeline average deliveries per
day within and outside California.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------
1999 1998 1997 1996 1995
------------- ----------- ----------- ----------- -----------
(BARRELS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Average daily volumes delivered to:
California
Sisquoc 27 24 21 17 11
Pentland 52 69 74 71 65
Mojave 7 22 32 6 -
Emidio 15 - - - -
------------- ----------- ----------- ----------- -----------
Total California 101 115 127 94 76
Texas (1) 56 59 68 113 141
------------- ----------- ----------- ----------- -----------
Total 157 174 195 207 217
============= =========== =========== =========== ===========
</TABLE>
---------
(1) See " Midstream Acquisitions and Dispositions - All American Linefill and
Asset Disposition".
SJV Gathering System
The SJV Gathering System is a proprietary pipeline system. As a proprietary
pipeline, the SJV Gathering System is not subject to common carrier regulations.
The SJV Gathering System was constructed in 1987 with a design capacity of
approximately 140,000 barrels per day. The system consists of a 16-inch pipeline
that originates at the Belridge station and extends 45 miles south to a
connection with the All American Pipeline at the Pentland station. The SJV
Gathering System is connected to several fields, including the South Belridge,
Elk Hills and Midway Sunset fields, three of the seven largest producing fields
in the lower 48 states. In 1999, we leased a pipeline that provides us access to
the Lost Hills field. The SJV Gathering System also includes approximately
586,000 barrels of tank capacity, which can be used to facilitate movements
along the system as well as to support our other activities.
The SJV Gathering System is supplied with the crude oil production primarily
from major oil companies' equity production from the South Belridge, Cymeric,
Midway Sunset, Elk Hills and Lost Hills fields. The table below sets forth the
historical volumes received into the SJV Gathering System.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------
1999 1998 1997 1996 1995
------------- --------- --------- --------- ---------
(BARRELS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Total average daily volumes 84 85 91 67 50
</TABLE>
West Texas Gathering System
We purchased the West Texas Gathering System from Chevron Pipe Line Company
in July 1999 for approximately $36.0 million. The West Texas Gathering System is
a common carrier crude oil pipeline system located in the heart of the Permian
Basin producing area. The West Texas Gathering System has lease gathering
facilities in Crane, Ector, Upton, Ward and Winkler counties. In aggregate,
these counties have produced on average in excess of 150,000 barrels per day of
crude oil over the last four years. The West Texas Gathering System was
originally built by Gulf Oil Corporation in the late 1920's, expanded during the
late 1950's and updated during the mid 1990's. The West Texas Gathering System
provides us with considerable flexibility, as major segments are bi-directional
and allow us to move crude oil between three of the major trading locations in
West Texas.
Lease volumes gathered into the system are approximately 50,000 barrels per
day. Chevron USA has agreed to transport its equity crude oil production from
fields connected to the West Texas Gathering System on the system through July
2011 (currently representing approximately 22,000 barrels per day, or 44% of
total system gathering volumes and 22% of the total system volumes). Other large
producers connected to the gathering system include Burlington, Devon, Anadarko,
Altura, Bass, and Fina. Volumes from connecting carriers, including Exxon,
Phillips and Unocal, average approximately 42,000 barrels per day. Our West
Texas Gathering System has the capability to transport approximately 190,000
barrels per day. At the time of the acquisition, truck injection stations were
limited and provided less than 1,000 barrels per day. We have installed ten
truck injection stations on the West Texas Gathering System since the
acquisition. Our trucks are used to pick up crude oil produced in the areas
adjacent to the West Texas Gathering System and deliver these volumes into the
pipeline. These additional injection stations allowed us to reduce the distance
of our truck hauls in this area, increase the utilization of
14
<PAGE>
our pipeline assets and reduce our operating costs. Volumes received from truck
injection stations were increased to 10,000 barrels per day by the fourth
quarter of 1999. The West Texas Gathering System also includes approximately 2.9
million barrels of tank capacity located along the pipeline system.
Spraberry Pipeline System
The Spraberry Pipeline System, acquired in the Scurlock acquisition, is a
proprietary pipeline system that gathers crude oil from the Spraberry Trend of
West Texas and transports it to Midland, Texas, where it interconnects with the
West Texas Gathering System and other pipelines. The Spraberry Pipeline System
consists of approximately 800 miles of pipe of varying diameter, and has a
throughput capacity of approximately 50,000 barrels of crude oil per day. The
Spraberry Trend is one of the largest producing areas in West Texas, and we are
one of the largest gatherers in the Spraberry Trend. The Spraberry Pipeline
System gathers approximately 34,000 barrels per day of crude oil. Large
suppliers to the Spraberry Pipeline System include Lantern Petroleum and Pioneer
Natural Resources. The Spraberry Pipeline System also includes approximately
173,000 barrels of tank capacity located along the pipeline.
Sabine Pass Pipeline System
The Sabine Pass Pipeline System, acquired in the Scurlock acquisition, is a
common carrier crude oil pipeline system. The primary purpose of the Sabine Pass
Pipeline System is to gather crude oil from onshore facilities of offshore
production near Johnson's Bayou, Louisiana, and deliver it to tankage and barge
loading facilities in Sabine Pass, Texas. The Sabine Pass Pipeline System
consists of approximately 34 miles of pipe ranging from 4 to 6 inches in
diameter and has a throughput capacity of approximately 26,000 barrels of
Louisiana light sweet crude oil per day. For the year ended December 31, 1999,
the system transported approximately 16,500 barrels of crude oil per day. The
Sabine Pass Pipeline System also includes 245,000 barrels of tank capacity
located along the pipeline.
Ferriday Pipeline System
The Ferriday Pipeline System, acquired in the Scurlock acquisition, is a
common carrier crude oil pipeline system which is located in East Louisiana and
West Mississippi. The Ferriday Pipeline System consists of approximately 600
miles of pipe ranging from 2 inches to 12 inches in diameter. The Ferriday
Pipeline System delivers 9,000 barrels per day of crude oil to third-party
pipelines that supply refiners in the Midwest. The Ferriday Pipeline System also
includes approximately 348,000 barrels of tank capacity located along the
pipeline.
In November 1999, we completed the construction of an 8-inch pipeline
underneath the Mississippi River that connects our Ferriday Pipeline System in
West Mississippi with the portion of the system located in East Louisiana. This
connection provides us with bi-directional capability to access additional
markets and enhances our ability to service our pipeline customers and take
advantage of additional high margin merchant activities.
East Texas Pipeline System
The East Texas Pipeline System, acquired in the Scurlock acquisition, is a
proprietary crude oil pipeline system that is used to gather approximately
10,000 barrels per day of crude oil in East Texas and transport approximately
22,000 barrels per day of crude oil to Crown Central's refinery in Longview,
Texas. The deliveries to Crown Central are subject to a five-year throughput and
deficiency agreement, which extends through 2004. The East Texas Pipeline System
also includes approximately 221,000 barrels of tank capacity located along the
pipeline.
Illinois Basin Pipeline System
The Illinois Basin Pipeline System, acquired in the Scurlock acquisition,
consists of common carrier pipeline and gathering systems and truck injection
facilities in southern Illinois. The Illinois Basin Pipeline System consists of
approximately 170 miles of pipe of varying diameter and delivers approximately
6,400 barrels per day of crude oil to third-party pipelines that supply refiners
in the Midwest. During 1999, approximately 3,600 barrels per day of the supply
on this system are from fields operated by us.
15
<PAGE>
TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES
Terminalling and Storage Activities
We own approximately 9.7 million barrels of terminalling and storage assets,
including tankage associated with our pipeline and gathering systems. Our
storage and terminal operations increase our margins in our business of
purchasing and selling crude oil and also generate revenue through a combination
of storage and throughput charges to third parties. Storage fees are generated
when we lease tank capacity to third parties. Terminalling fees, also referred
to as throughput fees, are generated when we receive crude oil from one
connecting pipeline and redeliver such crude oil to another connecting carrier
in volumes that allow the refinery to receive its crude oil on a ratable basis
throughout a delivery period. Both terminalling and storage fees are generally
earned from:
. refiners and gatherers that segregate or custom blend crudes for
refining feedstocks;
. pipeline operators, refiners or traders that need segregated tankage for
foreign cargoes;
. traders who make or take delivery under NYMEX contracts; and
. producers and resellers that seek to increase their marketing
alternatives.
The tankage that is used to support our arbitrage activities positions us to
capture margins in a contango market or when the market switches from contango
to backwardation.
Our most significant terminalling and storage asset is our Cushing Terminal
which was constructed in 1993, and expanded by approximately 50% in 1999, to
capitalize on the crude oil supply and demand imbalance in the Midwest. The
imbalance was caused by the continued decline of regional production supplies,
increasing imports and an inadequate pipeline and terminal infrastructure. The
Cushing Terminal is also used to support and enhance the margins associated with
our merchant activities relating to our lease gathering and bulk trading
activities.
The Cushing Terminal has total storage capacity of approximately 3.1 million
barrels. The Cushing Terminal is comprised of fourteen 100,000 barrel tanks,
four 150,000 barrel tanks and four 270,000 barrel tanks which are used to store
and terminal crude oil. The Cushing Terminal also includes a pipeline manifold
and pumping system that has an estimated daily throughput capacity of
approximately 800,000 barrels per day. The pipeline manifold and pumping system
is designed to support more than ten million barrels of tank capacity. The
Cushing Terminal is connected to the major pipelines and terminals in the
Cushing Interchange through pipelines that range in size from 10 inches to 24
inches in diameter.
The Cushing Terminal is a state-of-the-art facility designed to serve the
needs of refiners in the Midwest. In order to service an expected increase in
the volumes as well as the varieties of foreign and domestic crude oil projected
to be transported through the Cushing Interchange, we incorporated certain
attributes into the design of the Cushing Terminal including:
. multiple, smaller tanks to facilitate simultaneous handling of multiple
crude varieties in accordance with normal pipeline batch sizes;
. dual header systems connecting each tank to the main manifold system to
facilitate efficient switching between crude grades with minimal
contamination;
. bottom drawn sumps that enable each tank to be efficiently drained down
to minimal remaining volumes to minimize crude contamination and
maintain crude integrity during changes of service;
. mixer(s) on each tank to facilitate blending crude grades to refinery
specifications; and
. a manifold and pump system that allows for receipts and deliveries with
connecting carriers at their maximum operating capacity.
As a result of incorporating these attributes into the design of the Cushing
Terminal, we believe we are favorably positioned to serve the needs of Midwest
refiners to handle an increase in varieties of crude transported through the
Cushing Interchange.
The Cushing Terminal also incorporates numerous environmental and operational
safeguards. We believe that our terminal is the only one at the Cushing
Interchange in which each tank has a secondary liner (the equivalent of double
bottoms), leak detection devices and secondary seals. The Cushing Terminal is
the only terminal at the Cushing Interchange equipped with aboveground
pipelines. Like the pipeline systems we operate, the Cushing Terminal is
operated by a computer system designed to continuously monitor real time
operational data and each tank is cathodically protected. In addition, each tank
is equipped with an audible and visual high level alarm system to prevent
overflows; a double seal floating roof that minimizes air emissions and prevents
the possible accumulation
16
<PAGE>
of potentially flammable gases between fluid levels and the roof of the tank;
and a foam dispersal system that, in the event of a fire, is fed by a fully-
automated fire water distribution network.
The Cushing Interchange is the largest wet barrel trading hub in the U.S. and
the delivery point for crude oil futures contracts traded on the NYMEX. The
Cushing Terminal has been designated by the NYMEX as an approved delivery
location for crude oil delivered under the NYMEX light sweet crude oil futures
contract. As the NYMEX delivery point and a cash market hub, the Cushing
Interchange serves as a primary source of refinery feedstock for the Midwest
refiners and plays an integral role in establishing and maintaining markets for
many varieties of foreign and domestic crude oil.
The following table sets forth throughput volumes for our terminalling and
storage operations, and quantity of tankage leased to third parties from 1995
through 1999.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ---------- ---------- ---------
(BARRELS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Throughput volumes (average daily volumes):
Cushing Terminal 72 69 69 56 43
Ingleside Terminal 11 11 8 3 -
----------- ------- -------- ------- --------
Total 83 80 77 59 43
=========== ======= ======== ======= ========
Storage leased to third parties
(monthly average volumes):
Cushing Terminal 1,743 890 414 203 208
Ingleside Terminal 232 260 254 211 -
----------- ------- -------- ------- --------
Total 1,975 1,150 668 414 208
=========== ======= ======== ======= ========
</TABLE>
Gathering and Marketing Activities
Our gathering and marketing activities are conducted in 23 states; however,
the vast majority of those activities are in Texas, Louisiana, California,
Illinois and the Gulf of Mexico. These activities include:
. purchasing crude oil from producers at the wellhead and in bulk from
aggregators at major pipeline interconnects and trading locations;
. transporting this crude oil on our own proprietary gathering assets or
assets owned and operated by third parties when necessary or cost
effective;
. exchanging this crude oil for another grade of crude oil or at a
different geographic location, as appropriate, in order to maximize
margins or meet contract delivery requirements; and
. marketing crude oil to refiners or other resellers.
We purchase crude oil from many independent producers and believe that we
have established broad-based relationships with crude oil producers in our areas
of operations. For the year ended December 31, 1999, we purchased approximately
265,000 barrels per day of crude oil directly at the wellhead from more than
2,200 producers from approximately 10,700 leases. We purchase crude oil from
producers under contracts that range in term from a thirty-day evergreen to
three years. Gathering and marketing activities are characterized by large
volumes of transactions with lower margins relative to pipeline and terminalling
and storage operations.
In the period immediately following the disclosure of the unauthorized
trading losses, a significant number of PAA's suppliers and trading partners
reduced or eliminated the open credit previously extended to PAA. Consequently,
the amount of letters of credit PAA needed to support the level its crude oil
purchases then in effect increased significantly. In many instances PAA arranged
for letters of credit to secure its obligations to purchase crude oil from its
customers. In other instances, certain of PAA's purchase contracts were
terminated. As a result of these changes, aggregate volumes purchased are
expected to decrease by 150,000 barrels per day, consisting primarily of lower
unit margin purchases. Approximately 50,000 barrels per day of the decrease is
related to barrels gathered at producer lease locations and 100,000 barrels per
day is attributable to bulk purchases. See "Unauthorized Trading Losses".
17
<PAGE>
The following table shows the average daily volume of our lease gathering and
bulk purchases from 1995 through 1999.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------
1999 (1) 1998 1997 1996 1995
------------- ----------- ----------- ----------- -----------
(BARRELS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Lease gathering 239 88 71 59 46
Bulk purchases 138 98 49 32 10
--- --- --- -- --
Total volumes 377 186 120 91 56
=== === === == ==
</TABLE>
----------------
(1) Includes volumes from Scurlock Permian since May 1, 1999.
Crude Oil Purchases. In a typical producer's operation, crude oil flows from
the wellhead to a separator where the petroleum gases are removed. After
separation, the crude oil is treated to remove water, sand and other
contaminants and is then moved into the producer's on-site storage tanks. When
the tank is full, the producer contacts our field personnel to purchase and
transport the crude oil to market. We utilize our truck fleet and gathering
pipelines and third-party pipelines, trucks and barges to transport the crude
oil to market. We own or lease approximately 280 trucks, 325 tractor-trailers
and 290 injection stations.
We have a Marketing Agreement with PAA, under which they are the exclusive
marketer/purchaser for all of our equity crude oil production. The Marketing
Agreement provides that they will purchase for resale at market prices all of
our crude oil production for which they charge a fee of $0.20 per barrel. This
fee will be adjusted every three years based upon then existing market
conditions. The Marketing Agreement will terminate upon a "change of control" of
us or the general partner.
Bulk Purchases. In addition to purchasing crude oil at the wellhead from
producers, we purchase crude oil in bulk at major pipeline terminal points. This
production is transported from the wellhead to the pipeline by major oil
companies, large independent producers or other gathering and marketing
companies. We purchase crude oil in bulk when we believe additional
opportunities exist to realize margins further downstream in the crude oil
distribution chain. The opportunities to earn additional margins vary over time
with changing market conditions. Accordingly, the margins associated with our
bulk purchases will fluctuate from period to period. Our bulk purchasing
activities are concentrated in California, Texas, Louisiana and at the Cushing
Interchange.
Crude Oil Sales. The marketing of crude oil is complex and requires detailed
current knowledge of crude oil sources and end markets and a familiarity with a
number of factors including grades of crude oil, individual refinery demand for
specific grades of crude oil, area market price structures for the different
grades of crude oil, location of customers, availability of transportation
facilities and timing and costs (including storage) involved in delivering crude
oil to the appropriate customer. We sell our crude oil to major integrated oil
companies, independent refiners and other resellers in various types of sale and
exchange transactions, at market prices for terms ranging from one month to
three years.
As we purchase crude oil, we establish a margin by selling crude oil for
physical delivery to third party users, such as independent refiners or major
oil companies, or by entering into a future delivery obligation with respect to
futures contracts on the NYMEX. Through these transactions, we seek to maintain
a position that is substantially balanced between crude oil purchases and sales
and future delivery obligations. We from time to time enter into fixed price
delivery contracts, floating price collar arrangements, financial swaps and
crude oil futures contracts as hedging devices. Our policy is generally to
purchase only crude oil for which we have a market and to structure our sales
contracts so that crude oil price fluctuations do not materially affect the
gross margin which we receive. We do not acquire and hold crude oil, futures
contracts or other derivative products for the purpose of speculating on crude
oil price changes that might expose us to indeterminable losses. In November
1999, we discovered that this policy was violated and we incurred $174.0 million
in unauthorized trading losses, including estimated associated costs and legal
expenses. See "Unauthorized Trading Losses".
Risk management strategies, including those involving price hedges using NYMEX
futures contracts, have become increasingly important in creating and
maintaining margins. Such hedging techniques require significant resources
dedicated to managing futures positions. We are able to monitor crude oil
volumes, grades, locations and delivery schedules and to coordinate marketing
and exchange opportunities, as well as NYMEX hedging positions. This
coordination ensures that our NYMEX hedging activities are successfully
implemented. We have recently hired a Risk Manager that has direct
responsibility and authority for our risk policies and our trading controls and
procedures and other aspects of corporate risk management.
18
<PAGE>
Crude Oil Exchanges. We pursue exchange opportunities to enhance margins
throughout the gathering and marketing process. When opportunities arise to
increase our margin or to acquire a grade of crude oil that more nearly matches
our delivery requirement or the preferences of our refinery customers, we
exchange physical crude oil with third parties. These exchanges are effected
through contracts called exchange or buy-sell agreements. Through an exchange
agreement, we agree to buy crude oil that differs in terms of geographic
location, grade of crude oil or delivery schedule from crude oil we have
available for sale. Generally, we enter into exchanges to acquire crude oil at
locations that are closer to our end markets, thereby reducing transportation
costs and increasing our margin. We also exchange our crude oil to be delivered
at an earlier or later date, if the exchange is expected to result in a higher
margin net of storage costs, and enter into exchanges based on the grade of
crude oil, which includes such factors as sulfur content and specific gravity,
in order to meet the quality specifications of our delivery contracts.
Producer Services. Crude oil purchasers who buy from producers compete on the
basis of competitive prices and highly responsive services. Through our team of
crude oil purchasing representatives, we maintain ongoing relationships with
more than 2,200 producers. We believe that our ability to offer high-quality
field and administrative services to producers is a key factor in our ability to
maintain volumes of purchased crude oil and to obtain new volumes. High-quality
field services include efficient gathering capabilities, availability of trucks,
willingness to construct gathering pipelines where economically justified,
timely pickup of crude oil from tank batteries at the lease or production point,
accurate measurement of crude oil volumes received, avoidance of spills and
effective management of pipeline deliveries. Accounting and other administrative
services include securing division orders (statements from interest owners
affirming the division of ownership in crude oil purchased by us), providing
statements of the crude oil purchased each month, disbursing production proceeds
to interest owners and calculation and payment of ad valorem and production
taxes on behalf of interest owners. In order to compete effectively, we must
maintain records of title and division order interests in an accurate and timely
manner for purposes of making prompt and correct payment of crude oil production
proceeds, together with the correct payment of all severance and production
taxes associated with such proceeds.
Credit. Our merchant activities involve the purchase of crude oil for resale
and require significant extensions of credit by our suppliers of crude oil. In
order to assure our ability to perform our obligations under crude oil purchase
agreements, various credit arrangements are negotiated with our crude oil
suppliers. Such arrangements include open lines of credit directly with us and
standby letters of credit issued under our letter of credit facility. Due to the
unauthorized trading losses, the amount of letters of credit that we are
required to provide to secure our crude oil purchases has increased. See
"Unauthorized Trading Losses".
When we market crude oil, we must determine the amount, if any, of the line of
credit to be extended to any given customer. If we determine that a customer
should receive a credit line, we must then decide on the amount of credit that
should be extended. Since our typical sales transactions can involve tens of
thousands of barrels of crude oil, the risk of nonpayment and nonperformance by
customers is a major consideration in our business. We believe our sales are
made to creditworthy entities or entities with adequate credit support.
Credit review and analysis are also integral to our leasehold purchases.
Payment for all or substantially all of the monthly leasehold production is
sometimes made to the operator of the lease. The operator, in turn, is
responsible for the correct payment and distribution of such production proceeds
to the proper parties. In these situations, we must determine whether the
operator has sufficient financial resources to make such payments and
distributions and to indemnify and defend us in the event any third party should
bring a protest, action or complaint in connection with the ultimate
distribution of production proceeds by the operator.
OPERATING ACTIVITIES
See Note 22 in the notes to our consolidated financial statements located
elsewhere in this report for information with respect to the operating
activities of our upstream and midstream segments.
PRODUCT MARKETS AND MAJOR CUSTOMERS
Our revenues are highly dependent upon the prices of, and demand for, crude
oil and natural gas. Historically, the markets for crude oil and natural gas
have been volatile and are likely to continue to be volatile in the future. The
prices we receive for our crude oil and natural 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
economy (particularly the manufacturing sector), foreign imports, political
conditions in other crude oil-producing and natural gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
government regulation,
19
<PAGE>
legislation and policies. 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. The
benchmark NYMEX crude oil price of $25.60 per barrel at December 31, 1999 was
more than double the $12.05 per barrel at the end of 1998. See Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- "Outlook".
In order to manage our exposure to price risks in the marketing of our crude
oil and natural gas, from time to time we purchase put options, enter into fixed
price delivery contracts, floating price collar arrangements, financial swaps
and crude oil and natural gas futures contracts as hedging devices. To ensure a
fixed price for future production, we may sell a futures contract and thereafter
either (1) make physical delivery of our product to comply with such contract or
(2) buy a matching futures contract to unwind our futures position and sell our
production to a customer. These same techniques are also utilized to manage
price risk for certain production purchased from customers of PAA. Such
contracts may expose us to the risk of financial loss in certain circumstances,
including instances where production is less than expected, our customers fail
to purchase or deliver the contracted quantities of crude oil or natural gas, or
a sudden, unexpected event materially impacts crude oil or natural gas prices.
Such contracts may also restrict our ability to benefit from unexpected
increases in crude oil and natural gas prices. See Item 2. -- "Properties --
Crude Oil and Natural Gas Reserves".
Substantially all of our California crude oil and natural gas production and
our Sunniland Trend oil 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 crude oil and natural
gas production.
Certain of our natural gas production has been in the past, and may be in the
future, curtailed from time to time depending on the quality of the natural gas
produced and transportation alternatives. In addition, market, economic and
regulatory factors, including issues regarding the quality of certain of our
natural gas, may in the future adversely affect our ability to sell our natural
gas production.
Deregulation of natural gas prices has increased competition and volatility of
natural gas prices. Since demand for natural gas is generally highest during
winter months, prices received for our natural gas are subject to seasonal
variations and other fluctuations. All of our natural gas production is
currently sold under various arrangements at spot indexed prices. In certain
instances we enter into financial arrangements to hedge our exposure to spot
price fluctuations. See Item 2. -- "Properties -- Production and Sales" and Item
7. -- "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Outlook".
Customers accounting for more than 10% of total sales for the periods
indicated are as follows:
<TABLE>
<CAPTION>
PERCENTAGE OF TOTAL SALES
--------------------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
Customer 1999 1998 1997
--------------------------------------------------------
<S> <C> <C> <C>
Sempra Energy Trading Corporation 22% 27% 11%
Koch Oil Company 18% 15% 27%
PERCENTAGE OF OIL AND GAS SALES (1)
--------------------------------------------------------
Chevron 43% - -
Tosco Refining Company 21% 50% -
Conoco Inc. 12% - -
Scurlock Permian LLC - 17% -
Unocal Energy Trading, Inc. - - 52%
Marathon Oil Company 17% - 23%
Exxon Company U.S.A. - - 10%
</TABLE>
----------------
(1) PAA is the exclusive marketer/purchaser for all our equity crude oil
production. These percentages represent the entities that purchased our
equity crude production from PAA. We believe that the loss of an individual
customer would not have a material adverse effect.
20
<PAGE>
Competition
Crude Oil and Natural Gas Producing Activities
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 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.
Midstream Activities
Competition among pipelines is based primarily on transportation charges,
access to producing areas and demand for the crude oil by end users. We believe
that high capital requirements, environmental considerations and the difficulty
in acquiring rights of way and related permits make it unlikely that competing
pipeline systems comparable in size and scope to our pipeline systems will be
built in the foreseeable future.
We face intense competition in our terminalling and storage activities and
gathering and marketing activities. Our competitors include other crude oil
pipelines, the major integrated oil companies, their marketing affiliates and
independent gatherers, brokers and marketers of widely varying sizes, financial
resources and experience. Some of these competitors have capital resources many
times greater than ours and control substantially greater supplies of crude oil.
REGULATION
Our operations are subject to extensive regulation. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil 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 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 regulations than are our competitors. Due to the myriad of
complex federal and state statutes and regulations which may affect us, directly
or indirectly, you should not rely on the following discussion of certain
statutes and regulations as an exhaustive review of all regulatory
considerations affecting our operations.
OSHA
We are also subject to the requirements of the Federal Occupational Safety and
Health Act ("OSHA") and comparable state statutes that regulate the protection
of the health and safety of workers. In addition, the OSHA hazard communication
standard requires 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.
Trucking Regulation
We operate a fleet of trucks to transport crude oil and oilfield materials as
a private, contract and common carrier. We are licensed to perform both
intrastate and interstate motor carrier services. As a motor carrier, we are
subject to certain safety regulations issued by the Department of
Transportation. The trucking regulations cover, among other things, driver
operations, keeping of log books, truck manifest preparations, the placement of
safety placards on the trucks and trailer vehicles, drug and alcohol testing,
safety of operation and equipment, and many other aspects of truck operations.
We are also subject to OSHA with respect to our trucking operations.
Pipeline Regulation
Our pipelines are subject to regulation by the Department of Transportation
under the Hazardous Liquids Pipeline Safety Act of 1979, as amended ("HLPSA")
relating to the design, installation, testing, construction, operation,
replacement and management of pipeline facilities. The HLPSA requires us and
other pipeline operators to comply with regulations issued
21
<PAGE>
pursuant to HLPSA, to permit access to and allow copying of records and to make
certain reports and provide information as required by the Secretary of
Transportation.
The Pipeline Safety Act of 1992 amends the HLPSA in several important
respects. It requires the Research and Special Programs Administration of the
Department of Transportation to consider environmental impacts, as well as its
traditional public safety mandate, when developing pipeline safety regulations.
In addition, the Pipeline Safety Act mandates the establishment by the
Department of Transportation of pipeline operator qualification rules requiring
minimum training requirements for operators, and requires that pipeline
operators provide maps and records to the Research and Special Programs
Administration. It also authorizes the Research and Special Programs
Administration to require that pipelines be modified to accommodate internal
inspection devices, to mandate the installation of emergency flow restricting
devices for pipelines in populated or sensitive areas and to order other changes
to the operation and maintenance of petroleum pipelines. We believe that our
pipeline operations are in substantial compliance with applicable HLPSA and
Pipeline Safety Act requirements. Nevertheless, we could incur significant
expenses in the future if additional safety measures are required or if safety
standards are raised and exceed the current pipeline control system
capabilities.
States are largely preempted by federal law from regulating pipeline safety
but may assume responsibility for enforcing federal intrastate pipeline
regulations and inspection of intrastate pipelines. In practice, states vary
considerably in their authority and capacity to address pipeline safety. We do
not anticipate any significant problems in complying with applicable state laws
and regulations in those states in which we operate.
Transportation of Crude Oil
General Interstate Regulation. Our interstate common carrier pipeline
operations are subject to rate regulation by the FERC under the Interstate
Commerce Act. The Interstate Commerce Act requires that tariff rates for
petroleum pipelines, which includes crude oil, as well as refined product and
petrochemical pipelines, be just and reasonable and non-discriminatory. The
Interstate Commerce Act permits challenges to proposed new or changed rates by
protest, and challenges to rates that are already final and in effect by
complaint. Upon the appropriate showing, a successful complainant may obtain
reparations for overcharges sustained for a period of up to two years prior to
the filing of a complaint.
The FERC is authorized to suspend the effectiveness of a new or changed tariff
rate for a period of up to seven months and to investigate the rate. If upon the
completion of an investigation the FERC finds that the rate is unlawful, it may
require the pipeline operator to refund to shippers, with interest, any
difference between the rates the FERC determines to be lawful and the rates
under investigation. In addition, the FERC will order the pipeline to change its
rates prospectively to the lawful level.
In general, petroleum pipeline rates must be cost-based, although settlement
rates, which are rates that have been agreed to by all shippers, are permitted,
and market-based rates may be permitted in certain circumstances. Under a cost-
of-service basis, rates are permitted to generate operating revenues, on the
basis of projected volumes, not greater than the total of the following:
. operating expenses;
. depreciation and amortization;
. federal and state income taxes; and
. an overall allowed rate of return on the pipeline's "rate base."
Energy Policy Act of 1992 and Subsequent Developments. In October 1992
Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed
petroleum pipeline rates in effect for the 365-day period ending on the date of
enactment of the Energy Policy Act or that were in effect on the 365th day
preceding enactment and had not been subject to complaint, protest or
investigation during the 365-day period to be just and reasonable under the
Interstate Commerce Act. The Energy Policy Act also provides that complaints
against such rates may only be filed under the following limited circumstances:
. a substantial change has occurred since enactment in either the economic
circumstances or the nature of the services which were a basis for the
rate;
. the complainant was contractually barred from challenging the rate prior to
enactment; or
. a provision of the tariff is unduly discriminatory or preferential.
22
<PAGE>
The Energy Policy Act further required the FERC to issue rules establishing a
simplified and generally applicable ratemaking methodology for petroleum
pipelines, and to streamline procedures in petroleum pipeline proceedings. On
October 22, 1993, the FERC responded to the Energy Policy Act directive by
issuing Order No. 561, which adopts a new indexing rate methodology for
petroleum pipelines. Under the new regulations, which were effective January 1,
1995, petroleum pipelines are able to change their rates within prescribed
ceiling levels that are tied to the Producer Price Index for Finished Goods,
minus one percent. Rate increases made pursuant to the index will be subject to
protest, but such protests must show that the portion of the rate increase
resulting from application of the index is substantially in excess of the
pipeline's increase in costs. The new indexing methodology can be applied to any
existing rate, even if the rate is under investigation. If such rate is
subsequently adjusted, the ceiling level established under the index must be
likewise adjusted.
In Order No. 561, the FERC said that as a general rule pipelines must utilize
the indexing methodology to change their rates. The FERC indicated, however,
that it was retaining cost-of-service ratemaking, market-based rates, and
settlements as alternatives to the indexing approach. A pipeline can follow a
cost-of-service approach when seeking to increase its rates above index levels
for uncontrollable circumstances. A pipeline can seek to charge market- based
rates if it can establish that it lacks market power. In addition, a pipeline
can establish rates pursuant to settlement if agreed upon by all current
shippers. Initial rates for new services can be established through a cost-of-
service proceeding or through an uncontested agreement between the pipeline and
all of its shippers, including at least one shipper not affiliated with the
pipeline.
On May 10, 1996, the Court of Appeals for the District of Columbia Circuit
affirmed Order No. 561. The Court held that by establishing a general indexing
methodology along with limited exceptions to indexed rates, FERC had reasonably
balanced its dual responsibilities of ensuring just and reasonable rates and
streamlining ratemaking through generally applicable procedures. The FERC
indicated in Order No. 561 that it will assess in 2000 how the rate-indexing
method is operating.
In a proceeding involving Lakehead Pipe Line Company, Limited Partnership
(Opinion No. 397), FERC concluded that there should not be a corporate income
tax allowance built into a petroleum pipeline's rates to reflect income
attributable to noncorporate partners since noncorporate partners, unlike
corporate partners, do not pay a corporate income tax. This result comports with
the principle that, although a regulated entity is entitled to an allowance to
cover its incurred costs, including income taxes, there should not be an element
included in the cost of service to cover costs not incurred. Opinion No. 397 was
affirmed on rehearing in May 1996. Appeals of the Lakehead opinions were taken,
but the parties to the Lakehead proceeding subsequently settled the case, with
the result that appellate review of the tax and other issues never took place.
A proceeding is also pending on rehearing at the FERC involving another
publicly traded limited partnership engaged in the common carrier transportation
of crude oil (the "Santa Fe Proceeding") in which the FERC could further limit
its current position related to the tax allowance permitted in the rates of
publicly traded partnerships, as well as possibly alter the FERC's current
application of the FERC oil pipeline ratemaking methodology. On January 13,
1999, the FERC issued Opinion No. 435 in the Santa Fe Proceeding, which, among
other things, affirmed Opinion No. 397's determination that there should not be
a corporate income tax allowance built into a petroleum pipeline's rates to
reflect income attributable to noncorporate partners. Requests for rehearing of
Opinion No. 435 are pending before the FERC. Petitions for review of Opinion No.
435 are before the D.C. Circuit Court of Appeals, but are being held in abeyance
pending FERC action on the rehearing requests. Once the FERC acts on rehearing,
the FERC's position on the income tax allowance and on other rate issues could
be subject to judicial review.
Our Crude Oil Pipelines. The FERC generally has not investigated rates, such
as those currently charged by us, which have been mutually agreed to by the
pipeline and the shippers or which are significantly below cost of service rates
that might otherwise be justified by the pipeline under the FERC's cost-based
ratemaking methods. Substantially all of our gross margins on transportation are
produced by rates that are either grandfathered or set by agreement of the
parties. These rates have not been decreased through application of the indexing
method. Rates for OCS crude are set by transportation agreements with shippers
that do not expire until 2007 and provide for a minimum tariff with annual
escalation. The FERC has twice approved the agreed OCS rates, although
application of the PPFIG-1 index method would have required their reduction.
When these OCS agreements expire in 2007, they will be subject to renegotiation
or to any of the other methods for establishing rates under Order No. 561. As a
result, we believe that the rates now in effect can be sustained, although no
assurance can be given that the rates currently charged would ultimately be
upheld if challenged. In addition, we do not believe that an adverse
determination on the tax allowance issue in the Santa Fe Proceeding would have a
detrimental impact upon our current rates.
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<PAGE>
Transportation and Sale of Natural Gas
Prior to January 1993, the FERC, under the Natural Gas Policy Act of 1978
("NGPA"), prescribed maximum lawful prices for natural gas sales. Effective
January 1, 1993, natural gas prices were completely deregulated. Consequently,
sales of our natural gas after such date have been made at market prices.
The FERC regulates interstate natural gas pipeline transportation rates and
service conditions, both of which affect our marketing of gas, as well as our
revenues from sales of such gas. Since the latter part of 1985, culminating in
1992 in the Order No. 636 series of orders, the FERC has endeavored to make
natural gas transportation more accessible to gas buyers and sellers on an open
and non-discriminatory basis. FERC's "open access" policies are designed to
improve the competitive structure of the interstate natural gas pipeline
industry and to create a regulatory framework that will put gas sellers into
more direct contractual relations with gas buyers. As a result of the Order No.
636 program, the marketing and pricing of natural gas has been significantly
altered. The interstate pipelines' traditional role as wholesalers of natural
gas has been terminated and replaced by regulations which require pipelines to
provide transportation and storage service to others who buy and sell natural
gas. In addition, on February 9, 2000, FERC issued Order No. 637, promulgating
new regulations designed to refine the Order No. 636 "open access" policies and
revise the rules applicable to capacity release transactions. These new rules
will, among other things, permit existing holders of firm capacity to release or
"sell" their capacity to others at rates in excess of FERC's regulated rate for
transportation services.
Although the FERC does not regulate natural gas producers such as ourselves,
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
transportation industry will have on our gas sales efforts.
Additional proposals and/or proceedings that might affect the natural gas
industry may be considered by FERC, 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. The natural gas industry has
historically been very heavily regulated; thus there is no assurance that the
less stringent regulatory approach recently pursued by the FERC and Congress
will continue indefinitely into the future. The regulatory burden on the oil and
natural gas industry increases our cost of doing business and, consequently,
affects our profitability and cash flow. In as much as laws and regulations are
frequently expanded, amended or reinterpreted, we are unable to predict the
future cost or impact of complying with such regulations. We do not believe,
however, that our operations will be affected any differently than other gas
producers or marketers with which we compete.
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.
ENVIRONMENTAL REGULATION
General
Various 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
regulation. As with the industry generally, compliance with existing and
anticipated regulations increases our overall cost of business. Areas affected
include capital costs to construct, maintain and upgrade equipment and
facilities. While these regulations affect our capital expenditures and
earnings, we believe that these regulations do not affect our competitive
position in that the operations of our competitors that comply with such
regulations are similarly affected. Environmental regulations have historically
been subject to frequent change by regulatory authorities, and we are unable to
predict the ongoing cost to us of complying with
24
<PAGE>
these laws and regulations or the future impact of such regulations on our
operations. Violation of federal or state environmental laws, regulations and
permits can result in the imposition of significant 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 regulations and claims by neighboring landowners
and other third parties for personal injury and property damage.
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 comply with such rules and regulations.
In December 1995, we negotiated an agreement with Chevron, a prior owner 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 11 years) a minimum of five
acres of bioremediation cells for crude oil contaminated soils designated for
excavation and treatment by Chevron. While we believe that we do not have any
material obligations for operations conducted prior to Stocker's 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 are located within the Big Cypress
National Preserve and our operations therein are subject to regulations
administered by the National Park Service ("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. The Master Plan of Operations must
be modified and permits must be secured from the NPS for new wells which require
the use of additional land for drilling operations. The Master Plan of
Operations also requires that we restore the surface property affected by its
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 its current operations.
Approximately 183 acres of the 450 acres acquired 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. Approximately 40 pairs of gnatcatchers are believed
to inhabit the property. In addition, the 450 acres acquired 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 which do not materially interfere with such vegetation, the
gnatcatcher or its habitat. While 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.
Water
The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions of the
Federal Water Pollution Control Act of 1972 ("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 removal
costs and certain other consequences of an oil spill, where such spill is into
navigable waters, along shorelines or in the exclusive economic zone of the U.S.
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 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
pollutants into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA imposes substantial
potential liability for the costs of removal, remediation and damages. We
believe that compliance with existing permits and compliance with
25
<PAGE>
foreseeable new permit requirements will not have a material adverse effect on
our financial condition or results of operations.
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 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 (the "1990
Federal Clean Air Act Amendments") require or will require most industrial
operations in the U.S. to incur capital expenditures in order to meet air
emission control standards developed by the Environmental Protection Agency (the
"EPA") and state environmental agencies. In addition, the 1990 Federal Clean Air
Act Amendments include a new operating permit for major sources ("Title V
permits"), which applies to some of our facilities. Although we can give no
assurances, we believe implementation of the 1990 Federal Clean Air Act
Amendments will not have a material adverse effect on our financial condition or
results of operations.
Solid Waste
We generate non-hazardous solid wastes that are subject to the requirements of
the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA is considering the adoption of stricter disposal standards for
non-hazardous wastes, including oil and gas wastes. RCRA also governs the
disposal of hazardous 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 during operations, will
in the future be designated as "hazardous wastes." Hazardous wastes are subject
to more rigorous and costly disposal requirements than are non-hazardous wastes.
Such changes in the regulations could result in additional capital expenditures
or operating expenses.
Hazardous Substances
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as "Superfund", imposes liability, without regard to
fault or the legality of the original act, on certain classes of persons that
contributed to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the site and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. 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. 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 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 was 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 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.
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<PAGE>
FEDERAL TAXATION
For federal income tax purposes, Plains All American Inc. is the general
partner of PAA, holding a direct and indirect ownership at December 31, 1999 of
approximately 54% in PAA. Because PAA is a pass-through entity for tax purposes,
the income or loss of PAA is generally allocated based upon the owners'
respective ownership percentage. However, the Internal Revenue Code requires
certain items of partnership income, deduction, gain or loss to be allocated so
as to account for the difference between the tax basis and the fair market value
of the property contributed to PAA by the general partner. The federal income
tax burden associated with the difference between allocations based upon the
fair market value of the property contributed by the general partner and the
actual tax basis established for such property will be borne by the general
partner.
At December 31, 1999, we and our subsidiaries that are taxed as corporations
for federal income tax purposes, which together file a consolidated federal
income tax return, had remaining federal income tax net operating loss ("NOL")
carryforwards of approximately $229.3 million and approximately $209.8 million
of alternative minimum tax ("AMT") net operating loss carryforwards available as
a deduction against future AMT income. In addition, we had approximately $0.3
million of enhanced oil recovery credits, $1.4 million of AMT credits and $7.0
million of statutory depletion carryforwards at December 31, 1999. The NOL
carryforwards expire from 2005 through 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 (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% ("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, 1999. Equity transactions after
the date hereof 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.
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. The 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 Item 2. - "Properties -- Crude Oil and Natural 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. 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.
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<PAGE>
Substantially all of our California crude oil and natural gas production and
our Sunniland Trend oil 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 crude oil and natural 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. The occurrence of a
significant event that is not fully insured against could have a material
adverse effect on our financial position.
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, 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.
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.
Our revenues are highly dependent upon the prices of, and demand for, crude
oil and natural gas. Historically, the prices for crude oil and natural gas have
been volatile and are likely to continue to be volatile in the future. The price
we receive for our crude oil and natural gas production and the level of such
production are subject to wide fluctuations and depend on numerous factors
beyond our control, including seasonality, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other crude oil-producing and natural gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
government regulation, legislation and policies. 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 1999 reserve volumes) is comprised of crude oil properties that are
sensitive to crude oil price volatility. The benchmark NYMEX crude oil price of
$25.60 per barrel at December 31, 1999 was more than double the $12.05 per
barrel at the end of 1998. Although we are not currently 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.
In order to manage our exposure to price risks in the marketing of our crude
oil and natural gas, from time to time we purchase put options, enter into fixed
price delivery contracts, floating price collar arrangements, financial swaps
and crude oil and natural gas futures contracts as hedging devices. To ensure a
fixed price for future production, we may sell a futures contract and thereafter
either (1) make physical delivery of our product to comply with such contract or
(2) buy a matching futures contract to unwind our futures position and sell our
production to a customer. These same techniques are also utilized to manage
price risk for certain production purchased from customers of PAA. Such
contracts may expose us to the risk of financial loss in certain circumstances,
including instances where production is less than expected, our customers fail
to purchase or deliver the contracted quantities of crude oil or natural gas, or
a sudden, unexpected event materially impacts crude oil or natural gas prices.
Such contracts may also restrict our ability to benefit from unexpected
increases in crude oil and natural gas prices. See Item 7. -- "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Outlook" and Item 7a. -- "Quantitative and Qualitative Disclosures about Market
Risks".
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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.
Substantially all of our pipelines are constructed on rights-of-way granted by
the apparent record owners of such property and in some instances such rights-
of-way are revocable at the election of the grantor. In many instances, lands
over which rights-of-way have been obtained are subject to prior liens which
have not been subordinated to the right-of-way grants. In some cases, not all of
the apparent record owners have joined in the right-of-way grants, but in
substantially all such cases, signatures of the owners of majority interests
have been obtained. We have obtained permits from public authorities to cross
over or under, or to lay facilities in or along water courses, county roads,
municipal streets and state highways, and in some instances, such permits are
revocable at the election of the grantor. We have also obtained permits from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at the grantor's election. In some cases, property for
pipeline purposes was purchased in fee. All of the pump stations are located on
property owned in fee or property under long-term leases. In certain states and
under certain circumstances, we have the right of eminent domain to acquire
rights-of-way and lands necessary for our common carrier pipelines.
Some of the leases, easements, rights-of-way, permits and licenses transferred
to PAA, upon its formation in 1998 and in connection with acquisitions they
have made since that time, required the consent of the grantor to transfer such
rights, which in certain instances is a governmental entity. We believe that we
have obtained such third-party consents, permits and authorizations that are
sufficient for the transfer to us of the assets necessary for us to operate our
business in all material respects as described in this report. With respect to
any consents, permits or authorizations which have not yet been obtained, we
believe that such consents, permits or authorizations will be obtained within a
reasonable period, or that the failure to obtain such consents, permits or
authorizations will have no material adverse effect on the operation of our
business.
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 PAA's predecessor or 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.
EMPLOYEES
As of December 31, 1999, we had approximately 1,080 full-time employees, none
of whom is represented by any labor union. Approximately 675 of such full-time
employees are field personnel involved in crude oil and natural gas producing
activities, trucking and transport activities and crude oil terminalling and
storage activities. Approximately 910 employees spend the majority of their time
on the business of PAA.
ITEM 2. PROPERTIES
We are an independent energy company that acquires, exploits, develops,
explores and produces crude oil and natural gas. Through our majority ownership
in PAA, we are also engaged in the midstream activities of marketing,
transportation, terminalling and storage of crude oil. Our crude upstream crude
oil and natural gas activities are focused in California in the Los Angeles
Basin, the Arroyo Grande Field, and the Mt. Poso Field, offshore California in
the Point Arguello Field, the Sunniland Trend of South Florida and the Illinois
Basin in southern Illinois. Our midstream activities are concentrated in
California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.
OIL AND NATURAL 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 H.J. Gruy and Associates, Inc., Netherland, Sewell &
Associates, Inc., and Ryder Scott Company in 1999, 1998 and 1997, and in
addition in 1997 by System Technology Associates, Inc. Such reserve
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volumes and values were determined under the method prescribed by the SEC which
requires the application of year-end prices for each year, held constant
throughout the projected reserve life.
<TABLE>
<CAPTION>
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------------
1999 1998 1997
-----------------------------------------------------------------------------------
OIL GAS OIL GAS OIL GAS
(BBL) (MCF) (BBL) (MCF) (BBL) (MCF)
-----------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES
Beginning balance 120,208 86,781 151,627 60,350 115,996 37,273
Revision of previous estimates 62,895 (8,234) (46,282) 2,925 (16,091) 3,805
Extensions, discoveries, improved
recovery and other additions 37,393 15,488 14,729 29,306 17,884 8,126
Sale of reserves in-place - - - (2,799) (26) (547)
Purchase of reserves in-place 6,442 - 7,709 - 40,764 14,566
Production (8,016) (3,162) (7,575) (3,001) (6,900) (2,873)
------- ------- ------- ------ ------- ------
Ending balance 218,922 90,873 120,208 86,781 151,627 60,350
======= ====== ======= ====== ======= ======
PROVED DEVELOPED RESERVES
Beginning balance 73,264 58,445 99,193 38,233 86,515 25,629
======= ====== ======= ====== ======= ======
Ending balance 120,141 49,255 73,264 58,445 99,193 38,233
======= ====== ======= ====== ======= ======
</TABLE>
The following table sets forth the pre-tax Present Value of Proved Reserves at
December 31, 1999, 1998 and 1997.
<TABLE>
<CAPTION>
1999 1998 1997
------------- ------------- -------------
(in thousands)
<S> <C> <C> <C>
Proved developed $ 721,151 $185,961 $386,463
Proved undeveloped 524,898 40,982 124,530
---------- -------- --------
Total Proved $1,246,049 $226,943 $510,993
========== ======== ========
</TABLE>
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 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. A large portion of our reserve base
(approximately 94% of year-end 1999 reserve volumes) is comprised of crude oil
properties that are sensitive to crude oil price volatility. Revisions of
previous estimates set forth above, including upward price related revisions,
were 64 million BOE in 1999 and, including downward price related revisions,
were 46 million BOE and 16 million BOE in 1998 and 1997, respectively. See Item
7. - "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Outlook".
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, 1999 is based on the year-end crude oil price with variations
therefrom based on location and quality of crude oil. We
30
<PAGE>
have entered into various arrangements to fix the NYMEX crude oil price for a
significant portion of our crude oil production. On December 31, 1999, these
arrangements provided for a NYMEX crude oil price for 18,500 barrels per day
from January 1, 2000, through December 31, 2000, at approximately $16.00 per
barrel. Approximately 10,000 barrels per day of the volumes hedged in 2000 will
participate in price increases above the $16.00 per barrel floor price, subject
to a ceiling limitation of $19.75 per barrel. Location and quality differentials
attributable to our properties are not included in the foregoing prices.
Arrangements in effect at December 31, 1999 are reflected in the reserve reports
through the term of the arrangements. The overall average prices used in the
reserve reports as of December 31, 1999 were $20.94 per barrel of crude oil,
condensate and natural gas liquids and $2.77 per Mcf of natural gas. See
Item 1. -- "Business -- Product Markets and Major Customers". Prices for natural
gas and, to a lesser extent, oil are subject to substantial seasonal
fluctuations and prices for each are subject to substantial fluctuations as a
result of numerous other factors.
Since December 31, 1998, we have not filed any estimates of total proved net
crude oil or natural gas reserves with any federal authority or agency other
than the SEC. See Note 20 in our consolidated financial statements appearing
elsewhere in this report for certain additional information concerning our
proved reserves.
PRODUCTIVE WELLS AND ACREAGE
As of December 31, 1999, we had working interests in 1,811 gross (1,796 net)
active oil wells. The following table sets forth certain information with
respect to our developed and undeveloped acreage as of December 31, 1999.
<TABLE>
<CAPTION>
DECEMBER 31, 1999
--------------------------------------------------------------------------------------
DEVELOPED ACRES (1) UNDEVELOPED ACRES (2)
--------------------------------------- ---------------------------------------
GROSS NET GROSS NET (3)
---------------- ---------------- ---------------- ----------------
<S> <C> <C> <C> <C>
Onshore California (4) 9,049 9,003 3,180 1,702
Offshore California 15,326 4,033 41,720 1,449
Florida (5) 12,182 12,182 82,048 78,096
Illinois 16,412 14,423 16,250 7,940
Indiana 1,155 854 1,280 575
Kansas - - 48,147 37,647
Kentucky - - 1,321 521
Louisiana - - 4,875 4,858
------ ------ ------- -------
Total 54,124 40,495 198,821 132,788
====== ====== ======= =======
</TABLE>
------------
(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 2000 through 2003.
(4) Does not include 9,000 acres covered by a farmout from Chevron, in
which we own a 50% interest.
(5) Does not include 29,000 gross (28,000 net) acres under a seismic
option.
31
<PAGE>
DRILLING ACTIVITIES
Certain information with regard to our drilling activities during the years
ended December 31, 1999, 1998 and 1997 is set forth below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------------------------
1999 1998 1997
--------------------------- --------------------------------- ---------------------------------
GROSS NET GROSS NET GROSS NET
----------- ----------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Oil - - - - 2.00 2.00
Natural gas - - - - - -
Dry 1.00 0.50 - - - -
------ ------ ----- ----- ----- -----
Total 1.00 0.50 - - 2.00 2.00
====== ====== ===== ===== ===== =====
Development Wells:
Oil 105.00 105.00 76.00 76.00 58.00 57.06
Natural gas - - - - - -
Dry - - - - - -
------ ------ ----- ----- ----- -----
Total 105.00 105.00 76.00 76.00 58.00 57.06
====== ====== ===== ===== ===== =====
Total Wells:
Oil 105.00 105.00 76.00 76.00 60.00 59.06
Natural gas - - - - - -
Dry 1.00 0.50 - - - -
------ ------ ----- ----- ----- -----
Total 106.00 105.50 76.00 76.00 60.00 59.06
====== ====== ===== ===== ===== =====
</TABLE>
See Item 1. - "Business -- Acquisition and Exploitation" and -- "Productive
Wells and Acreage" for additional information regarding exploitation activities,
including waterflood patterns, workovers and recompletions.
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, 1999, 1998 and 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1999 1998 1997
------------ ------------ -----------
(IN THOUSANDS EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
Production:
Crude oil and natural gas liquids (Bbls) 8,016 7,574 6,900
Natural gas (Mcf) 3,163 3,001 2,873
BOE 8,543 8,075 7,379
Revenue:
Crude oil and natural gas liquids $111,128 $ 98,664 $104,988
Natural gas 5,095 4,090 4,415
-------- -------- --------
Total $116,223 $102,754 $109,403
======== ======== ========
Average sales price:
Crude oil and natural gas liquids per Bbl $ 13.85 $ 13.03 $ 15.22
Natural gas per Mcf 1.61 1.36 1.54
Per BOE 13.61 12.73 14.83
Production expenses per BOE 6.51 6.29 6.16
</TABLE>
PAA PROPERTIES
See description of PAA's properties under Item 1. -- "Business -- Midstream
Activities".
32
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, et al. The suit alleged
that Plains All American Pipeline, L.P. and certain of the general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
were filed in the Southern District of Texas, some of which name the general
partner and us as additional defendants. Plaintiffs allege that the defendants
are liable for securities fraud violations under Rule 10b-5 and Section 20(a) of
the Securities Exchange Act of 1934 and for making false registration statements
under Sections 11 and 15 of the Securities Act of 1933. The court has
consolidated all subsequently filed cases under the first filed action described
above. Two unopposed motions are currently pending to appoint lead plaintiffs.
These motions ask the court to appoint two distinct lead plaintiffs to represent
two different plaintiff classes: (1) purchasers of our common stock and options
and (2) purchasers of PAA's common units. Once lead plaintiffs have been
appointed, the plaintiffs will file their consolidated amended complaints. No
answer or responsive pleading is due until thirty days after a consolidated
amended complaint is filed.
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits
were filed in the Delaware Chancery Court, New Castle County, entitled Susser v.
Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et
al. These suits, and three others which were filed in Delaware subsequently,
named the general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to Plains All American Pipeline, L.P. and its unitholders by failing
to monitor properly the activities of its employees. The derivative complaints
allege, among other things, that Plains All American Pipeline has been harmed
due to the negligence or breach of loyalty of the officers and directors that
are named in the lawsuits. These cases are currently in the process of being
consolidated. No answer or responsive pleading is due until these cases have
been consolidated and a consolidated complaint has been filed.
We intend to vigorously defend the claims made in the Texas securities
litigation and the Delaware derivative litigation. However, there can be no
assurance that we will be successful in our defense or that these lawsuits will
not have a material adverse effect on our financial position or results of
operation.
On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in
the United States District Court for the Middle District of Florida, Exxon
Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action
was filed by Exxon to interplead royalty funds as a result of a title
controversy between certain mineral owners in a field in Florida. One group of
mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a
counterclaim against Exxon alleging fraud, conspiracy, conversion of funds,
declaratory relief, federal and Florida RICO, breach of contract and accounting,
as well as challenging the validity of certain oil and natural gas leases owned
by Exxon, and seeking exemplary and treble damages. In March 1993, but effective
November 1, 1992, Calumet Florida Inc. ("Calumet"), our wholly-owned subsidiary,
acquired all of Exxon's leases in the field affected by this lawsuit. In order
to address those counterclaims challenging the validity of certain oil and
natural gas leases, which constitute approximately 10% of the land underlying
this unitized field, Calumet filed a motion to join Exxon as plaintiff in the
subject lawsuit, which was granted July 29, 1994. In August 1994, the Hughes
Group amended its counterclaim to add Calumet as a counter-defendant. Exxon and
Calumet filed a motion to dismiss the counterclaims. On March 22, 1996, the
Court granted Exxon's and Calumet's motion to dismiss the counterclaims alleging
fraud, conspiracy, and federal and Florida RICO violations and challenging the
validity of certain of our oil and natural gas leases but denied such motion as
to the counterclaim alleging conversion of funds. We have reached an agreement
in principle to settle with the Hughes group. In consideration for full and
final settlement, and dismissal with prejudice, we have agreed to pay to the
Hughes group the total sum of $100,000. We and Exxon have filed motions for
summary judgment with respect to the claims of the remaining parties. The court
has not yet set a date for hearing of these motions. The trial date is currently
scheduled in June 2000.
We, in the ordinary course of business, are a claimant and/or a defendant in
various other legal proceedings in which our exposure, individually and in the
aggregate, is not considered material.
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.
33
<PAGE>
EXECUTIVE OFFICERS OF THE COMPANY
Information regarding our executive officers is presented below. All executive
officers hold office until their successors are elected and qualified.
Greg L. Armstrong, President and Chief Executive Officer Officer Since 1981
Mr. Armstrong, age 41, has been President, Chief Executive Officer and a
director since 1992. He was President and Chief Operating Officer from October
to December 1992, and Executive Vice President and Chief Financial Officer from
June to October 1992. He was Senior Vice President and Chief Financial Officer
from 1991 to June 1992, Vice President and Chief Financial Officer from 1984 to
1991, Corporate Secretary from 1981 to 1988, and Treasurer from 1984 to 1987.
William C. Egg, Jr., Executive Vice President Officer Since 1984
Mr. Egg, age 48, has been Executive Vice President and Chief Operating
Officer-Upstream since May 1998. He was Senior Vice President from 1991 to 1998.
He was Vice President-Corporate Development from 1984 to 1991 and Special
Assistant-Corporate Planning from 1982 to 1984.
Cynthia A. Feeback, Vice President - Accounting Officer Since 1993
and Assistant Treasurer
Ms. Feeback, age 42, has been Vice President and Assistant Treasurer since May
1999. She was Assistant Treasurer, Controller and Principal Accounting Officer
of the Company from May 1998 to May 1999. She was Controller and Principal
Accounting Officer from 1993 to 1998. She was Controller from 1990 to 1993 and
Accounting Manager from 1988 to 1990.
Jim G. Hester, Vice President - Business Development Officer Since 1999
and Acquisitions
Mr. Hester, age 40, has been Vice President -- Business Development and
Acquisitions since May 1999. He was Manager of Business Development and
Acquisitions from 1997 to May 1999, Manager of Corporate Development from 1995
to 1997 and Manager of Special Projects from 1993 to 1995. He was Assistant
Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue
Accounting Supervisor from 1988 to 1990.
Phillip D. Kramer, Executive Vice President, Chief Officer Since 1987
Financial Officer and Treasurer
Mr. Kramer, age 44, has been Executive Vice President, Chief Financial Officer
and Treasurer since May 1998. He was Senior Vice President and Chief Financial
Officer from May 1997 to May 1998. He was Vice President and Chief Financial
Officer from 1992 to 1997, Vice President and Treasurer from 1988 to 1992,
Treasurer from 1987 to 1988, and Controller from 1983 to 1987.
Michael R. Patterson, Vice President and General Counsel Officer Since 1985
Mr. Patterson, age 52, has been Vice President and General Counsel since 1985
and Corporate Secretary since 1988.
Harry N. Pefanis, Executive Vice President Officer Since 1988
Mr. Pefanis, age 42, has been Executive Vice President-Midstream since May
1998. He was Senior Vice President from February 1996 to May 1998. He had been
Vice President-Products Marketing since 1988. From 1987 to 1988 he was Manager
of Products Marketing. From 1983 to 1987 he was Special Assistant for Corporate
Planning. Mr. Pefanis is also President and Chief Operating Officer of Plains
All American Inc.
Mary O. Peters, Vice President - Administration and Officer Since 1991
Human Resources
Ms. Peters, age 51, has been Vice President-Administration and Human Resources
since 1991. She was Manager of Office Administration from 1984 to 1991.
34
<PAGE>
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Our common stock is listed and traded on the American Stock Exchange under the
symbol "PLX". The number of stockholders of record of the common stock as of
March 15, 2000 was 1,133.
The following table sets forth the range of high and low closing sales prices
for the common stock as reported on the American Stock Exchange Composite Tape
for the periods indicated below.
<TABLE>
<CAPTION>
HIGH LOW
---------- ---------
<S> <C> <C>
1999:
1st Quarter $15 1/2 $ 8 1/8
2nd Quarter 20 3/16 13 1/8
3rd Quarter 20 16 1/4
4th Quarter 20 9 1/16
1998:
1st Quarter $17 13/16 $14 7/16
2nd Quarter 21 16 7/8
3rd Quarter 19 3/4 14 5/8
4th Quarter 18 7/8 13 5/8
</TABLE>
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, we are restricted by provisions of the
indentures governing the issue of $275.0 million 10.25% Senior Subordinated
Notes Due 2006 (the "10.25% Notes") and prohibited by our $225.0 million
revolving credit facility from paying dividends on our common stock.
On December 14, 1999, we sold in a private placement 50,000 shares of our
Series F Preferred Stock for $50.0 million. Each share of the Series F Preferred
Stock has a stated value of $1,000 per share and bears a dividend of 10% per
annum. Dividends are payable semi-annually in either cash or additional shares
of Series F Preferred Stock at our option and are cumulative from the date of
issue. Dividends paid in additional shares of Series F Preferred Stock are
limited to an aggregate of six dividend periods. Each share of Series F
Preferred Stock is convertible into 81.63 shares of common stock (an initial
effective conversion price of $12.25 per share) and in certain circumstances may
be converted at our option into common stock if the average trading price for
any sixty-day trading period is equal to or greater than $21.60 per share. After
December 15, 2003, the Series F Preferred Stock is redeemable at our option at
110% of stated value through December 15, 2004, and at declining amounts
thereafter. If not previously redeemed or converted, the Series F Preferred
Stock is required to be redeemed in 2007.
On April 1, 1999, we paid a dividend on our Series E Preferred Stock for the
period from October 1, 1998 through March 31, 1999. The dividend amount of
approximately $4.1 million was paid by issuing 8,209 additional shares of the
Series E Preferred Stock. On September 9, 1999, 3,408 shares of Series E
Preferred Stock, including accrued dividends, were converted into 98,613 shares
of common stock at a conversion price of $18.00 per share. On October 1, 1999,
we paid a cash dividend of approximately $4.2 million on the Series E Preferred
Stock for the period April 1, 1999 through September 30, 1999.
On March 22, 2000, our Board of Directors declared cash dividends on our
Series D Preferred Stock, Series F Preferred Stock and Series G Preferred Stock,
all of which are payable on April 3, 2000 to holders of record on March 23,
2000. The dividend amount of $350,000 on the Series D Preferred Stock is for the
period January 1, 2000 through March 31, 2000. The dividend amount of $1,475,000
on the Series F Preferred Stock is for the period December 15, 1999 (the date of
original issuance) through March 31, 2000. The dividend amount of $4,219,000 for
the Series G Preferred Stock is for the period October 1, 1999 through March 31,
2000.
35
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
(IN THOUSANDS, EXCEPT FOR PER SHARE DATA)
The following selected historical 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).
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
1999(1) 1998(1) 1997 1996 1995
---------- ---------- --------- -------- ---------
(RESTATED) (RESTATED)
<S> <C> <C> <C> <C> <C>
Statement of Operations Data:
Revenues:
Oil and natural gas sales $ 116,223 $ 102,754 $109,403 $ 97,601 $ 64,080
Marketing, transportation,
storage and terminalling revenues 4,626,467 1,129,689 752,522 531,698 339,826
Gain on PAA unit offerings (2) 9,787 60,815 - - -
Gain on sale of linefill 16,457 - - - -
Interest and other income 1,237 834 319 309 319
---------- ---------- --------- -------- --------
Total revenue 4,770,171 1,294,092 862,244 629,608 404,225
---------- ---------- --------- -------- --------
Expenses:
Production expenses 55,645 50,827 45,486 38,735 30,256
Marketing, transportation,
storage and terminalling expenses 4,518,777 1,091,328 740,042 522,167 333,460
Unauthorized trading losses and
related expenses (1) 166,440 7,100 - - -
General and administrative 31,402 10,778 8,340 7,729 7,215
Depreciation, depletion and
amortization 36,998 31,020 23,778 21,937 17,036
Reduction of carrying cost of oil
and natural gas properties (3) - 173,874 - - -
Interest expense 46,378 35,730 22,012 17,286 13,606
Litigation settlement - - - 4,000(4) -
---------- ---------- --------- -------- --------
Total expenses 4,855,640 1,400,657 839,658 611,854 401,573
---------- ---------- --------- -------- --------
Income (loss) before income taxes,
minority interest and
extraordinary item (85,469) (106,565) 22,586 17,754 2,652
Minority interest (40,203) 786 - - -
Income tax expense (benefit):
Current (7) 862 352 - -
Deferred (20,472) (45,867) 7,975 (3,898) -
---------- ---------- --------- -------- --------
Income (loss) before extraordinary
item (24,787) (62,346) 14,259 21,652 2,652
Extraordinary item, net of tax
benefit and minority interest (5) (544) - - (5,104) -
---------- ---------- --------- -------- --------
Net income (loss) (25,331) (62,346) 14,259 16,548 2,652
Less: cumulative preferred stock
dividends 10,026 4,762 163 - -
---------- ---------- --------- -------- --------
Net income (loss) applicable to
common shareholders $ (35,357) $ (67,108) $ 14,096 $ 16,548 $ 2,652
========== ========== ========= ======== ========
Income (loss) per common
share - basic:
Before extraordinary item $ (2.02) $ (3.99) $ 0.85 $ 1.32 $ 0.19
Extraordinary item, net of
income taxes (0.03) - - (0.31) -
---------- ---------- --------- -------- ---------
$ (2.05) $ (3.99) $ 0.85 $ 1.01 $ 0.19
========== ========== ========= ======== =========
Income (loss) per common share -
assuming dilution:
Before extraordinary item $ (2.02) $ (3.99) $ 0.77 $ 1.23 $ 0.16
Extraordinary item, net of
income taxes (0.03) - - (0.29) -
---------- ---------- --------- -------- ---------
$ (2.05) $ (3.99) $ 0.77 $ 0.94 $ 0.16
========== ========== ========= ======== =========
Table and footnotes continued on following page
</TABLE>
36
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1999 1998 (1) 1997 1996 1995
---------- ---------- -------- -------- --------
(RESTATED)
<S> <C> <C> <C> <C> <C>
Other Financial Data:
Cash flow from operations (6) $ 70,382 $ 42,033 $ 46,233 $ 39,942 $ 19,688
EBITDA (7) 139,116 80,344 68,376 56,977 33,294
Net cash provided by (used in) operating
activities (75,964) 37,630 30,307 39,008 16,984
Net cash used in investing activities 266,396 483,422 107,634 52,496 64,398
Net cash provided by financing activities 404,044 448,622 78,524 9,876 52,252
AS OF DECEMBER 31,
-----------------------------------------------------------------------
1999 1998 (1) 1997 1996 1995
---------- ---------- -------- -------- --------
(RESTATED)
Balance Sheet Data:
Cash and cash equivalents $ 68,228 $ 6,544 $ 3,714 $ 2,517 $ 6,129
Working capital (deficit) (8) 115,867 (21,041) (6,011) (4,843) (4,749)
Property and equipment, net 787,653 661,726 413,308 311,040 280,538
Total assets 1,689,560 972,838 556,819 430,249 352,046
Long-term debt 676,703 431,983 285,728 225,399 205,089
Other long-term liabilities 21,107 10,253 5,107 2,577 1,547
Redeemable preferred stock 138,813 88,487 - - -
Non-redeemable preferred stock,
common stock and other stockholders'
equity 40,619 69,170 133,193 95,572 77,029
</TABLE>
-----------
(1) In November 1999, we discovered that a former employee of PAA had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated associated costs and legal
expenses). Approximately $7.1 million was recognized in 1998 and the
remainder in 1999. As a result we have restated our 1998 financial
information. See Item 1. -- "Business -- Unauthorized Trading Losses". We
have restated 1999 marketing, transportation, storage and terminalling
revenues and expenses to appropriately reflect certain transactions between
the upstream and midstream lines of business.
(2) For 1999, includes a $9.8 million noncash gain related to the change in our
ownership of PAA resulting from PAA's 1999 public offering of common units.
For 1998, includes a $60.8 million noncash gain recognized upon the
formation of PAA. See Item 7. -- "Management's Discussion and Analysis of
Financial Condition and Results of Operations".
(3) Includes a $173.9 million pre-tax ($109.0 million after tax) 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.
See Item 7.-- "Management's Discussion and Analysis of Financial Condition
and Results of Operations".
(4) Represents charge related to the settlement of two lawsuits filed in 1992
and 1993.
(5) Relates to the early redemption of PAA debt in 1999 and of our 12% Senior
Subordinated Notes in 1996.
(6) Represents net cash provided by operating activities after minority
interest but before changes in assets and liabilities and other noncash
items.
(7) EBITDA means earnings before interest, taxes and DD&A. Adjusted EBITDA also
excludes unauthorized trading losses, noncash compensation expense,
restructuring expense, gain on unit offerings, linefill gain and
extraordinary loss from extinguishment of debt. Adjusted EBITDA is not a
measurement presented in accordance with generally accepted accounting
principles ("GAAP") and is not intended to be used in lieu of GAAP
presentations 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.
(8) For working capital includes $37.9 million of pipeline linefill and $103.6
million for the segment of the All American Pipeline that were both sold in
the first quarter of 2000. See Item 1. -- "Midstream Acquisitions and
Dispositions -- All American Pipeline Linefill Sale and Asset Disposition".
37
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
General
We are an independent energy company that is engaged in two related lines of
business within the energy sector industry. Our first line of business, which we
refer to as "upstream", acquires, exploits, develops, explores and produces
crude oil and natural gas. Our second line of business, which we refer to as
"midstream", is engaged in the marketing, transportation and terminalling of
crude oil. 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". We conduct this second line of
business through our majority ownership in PAA. For financial statement
purposes, the assets, liabilities and earnings of PAA are included in our
consolidated financial statements, with the public unitholders' interest
reflected as a minority interest.
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 $162.0
million ($174.0 million, including estimated associated costs and legal
expenses). Approximately $7.1 million of the unauthorized trading loss was
recognized in 1998 and the remainder in 1999. As a result, we have restated our
1998 financial information. See Item 1. "Business - Unauthorized Trading Losses"
for a discussion of the unauthorized trading loss, its financial effects and the
steps taken to prevent future violations of PAA's trading policies.
Results of Operations
For the year ended December 31, 1999, we reported a net loss of $25.3 million,
or $2.05 per share on total revenue of $4.8 billion as compared to a net loss of
$62.3 million, or $3.99 per share on total revenue of $1.3 billion in 1998. For
the year ended December 31, 1997, we reported net income of $14.3 million or
$0.85 per share ($0.77 per share diluted), on total revenue of $862.2 million.
The net losses for the years ended December 31, 1999 and 1998 include the
following unusual or nonrecurring items:
1999
. $166.4 million of unauthorized trading losses;
. a $16.5 million gain on the sale of crude oil linefill that was sold in
1999;
. a $6.0 million after-tax gain ($9.8 million pre-tax) related to the sale of
units by PAA;
. restructuring expense of $1.4 million; and
. an extraordinary loss of $0.5 million related to the early extinguishment
of debt (net of minority interest and tax benefit).
1998
. $7.1 million of unauthorized trading losses;
. a $109.0 million after-tax ($173.9 million pre-tax) reduction in carrying
cost of oil and natural gas properties due to low crude oil prices at
December 31, 1998; and
. a $37.1 million after-tax ($60.8 million pre-tax) gain associated with the
initial public offering of PAA.
Excluding these nonrecurring items we would have reported net income of
approximately $17.0 million and $8.4 million in 1999 and 1998, respectively.
Adjusted EBITDA increased 73% in 1999 to $139.1 million from the $80.3 million
reported in 1998 and 103% from the $68.4 million reported in 1997. Cash flow
from operations (net income before noncash items) was $70.4 million, $42.0
million and $46.2 million in 1999, 1998 and 1997, respectively. Adjusted EBITDA
and cash flow from operations exclude the nonrecurring items discussed above.
Oil and natural gas sales. Oil and natural gas sales were $116.2 million in
1999, an increase of $13.5 million over 1998 due to higher product prices and
increased production volumes which contributed approximately $7.5 million and
$6.0 million to the increase, respectively. Oil and natural gas revenues
decreased to $102.8 million in 1998 as compared to $109.4 million in 1997 due to
decreased product prices, which had an approximate $16.9 million negative
impact, offset by increased production volumes, which had the effect of
increasing revenues by approximately $10.3 million.
38
<PAGE>
Marketing, transportation, storage and terminalling revenues. Marketing,
transportation, storage and terminalling revenues increased to $4.6 billion from
$1.1 billion and $0.8 billion in 1998 and 1997, respectively. The increase in
1999 as compared to 1998 was primarily due to an increase in lease gathering and
bulk purchase volumes, resulting from the Scurlock acquisition in May 1999, and
higher crude oil prices. The increase in 1998 from 1997 reflects the acquisition
of the All American Pipeline in July 1998 as well as increased lease gathering
and bulk purchase volumes. These increases in 1998 were partially offset by
lower crude oil prices. The NYMEX benchmark WTI crude oil price averaged $19.25
per barrel in 1999, $14.43 per barrel in 1998, and $20.63 per barrel in 1997.
See "Midstream Results".
Production expenses. Total production expenses increased to $55.6 million from
$50.8 million and $45.5 million in 1998 and 1997, respectively, primarily due to
increased production volumes resulting from our acquisition and exploitation
activities.
Marketing, transportation, storage and terminalling expenses. Marketing,
transportation, storage and terminalling expenses increased to $4.5 billion from
$1.1 billion and $0.7 billion in 1998 and 1997, respectively. The increase in
1999 as compared to 1998 was primarily due to an increase in lease gathering and
bulk purchase volumes, resulting from the Scurlock acquisition in May 1999, and
higher crude oil prices. The increase in 1998 from 1997 reflects the acquisition
of the All American Pipeline in July 1998 as well as increased lease gathering
and bulk purchase volumes. These increases in 1998 were partially offset by
lower crude oil prices.
General and administrative. General and administrative expenses were $31.4
million for the year ended December 31, 1999, compared to $10.8 million and $8.3
million for 1998 and 1997, respectively. Our upstream and midstream activities
accounted for approximately $3.3 million and $17.3 million, respectively, of the
increase from 1998 to 1999 and $0.7 million and $1.8 million, respectively, of
the increase from 1997 to 1998.
Noncash compensation expense. During 1999, we incurred a charge of $1.0
million related to noncash incentive compensation paid to certain officers and
key employees of Plains All American Inc., the general partner of PAA. In 1998,
Plains All American Inc. granted the employees the right to earn ownership in
common units of PAA owned by Plains All American Inc. The units vest over a
three-year period subject to PAA paying distributions on the common and
subordinated units. This amount is included in general and administrative
expense on the Consolidated Statements of Operations.
Depreciation, depletion and amortization. Primarily as a result of the
aforementioned midstream acquisitions and increased upstream production levels,
total DD&A expense for the year ended December 31, 1999, was $37.0 million as
compared to $31.0 million and $23.8 million in 1998 and 1997, respectively.
Interest expense. Interest expense, net of capitalized interest, for 1999
increased to $46.4 million as compared to $35.7 million in 1998 and $22.0
million in 1997. The increase in 1999 is primarily due to (1) interest
associated with the debt incurred for the Scurlock and West Texas Gathering
System acquisitions, (2) interest for a full year on debt outstanding from the
All American Pipeline acquisition, (3) an increase in interest related to hedged
inventory transactions (4) higher debt levels related to our acquisition,
exploitation, development and exploration activities and (5) higher interest
rates. The increase in interest expense in 1998 is primarily associated with the
debt incurred for the acquisition of the All American Pipeline and the SJV
Gathering System and our upstream acquisition, exploitation, development and
exploration activities. During 1999, 1998 and 1997, we capitalized $4.4 million,
$3.7 million and $3.3 million of interest, respectively.
Provision (benefit) for income taxes. For the year ended December 31, 1999, we
recognized a deferred tax benefit of $20.5 million. For the year ended December
31, 1998, we recognized a deferred tax benefit of $45.9 million and a current
tax provision of $0.9 million. For the year ended December 31, 1997, we
recognized a deferred tax provision of $8.0 million and a current tax provision
of $0.4 million. At December 31, 1999, we have a net deferred tax asset of $69.0
million, primarily attributable to net operating loss carryforwards. The minimum
amount of future taxable income necessary to utilize the net operating loss
carryforwards is $229.3 million. Based on current levels of pre-tax income,
excluding nonrecurring items, management believes that it is more likely than
not that we will generate taxable income from operations sufficient to realize
the deferred tax asset.
Nonrecurring Items
Gain on PAA unit offerings. In 1999, we recognized a pre-tax gain of $9.8
million ($6.0 million after-tax) in connection with PAA's October 1999 public
offering. The gain is the result of an increase in the book value of our equity
in PAA to reflect our proportionate share of the underlying net assets of PAA
due to the sale of the units. We held approximate interests of 59% and 54%
before and after this offering, respectively. During 1998, we recognized a pre-
tax gain of $60.8 million (
39
<PAGE>
approximately $37.1 million after-tax) in connection with the formation of PAA
as a result of an increase in the book value of our equity as previously
discussed. The formation-related expenses consist primarily of amounts due to
certain key employees in connection with the successful formation of PAA and
debt prepayment penalties. PAA may in the future issue additional units in
public or private sales if it needs additional capital and if market conditions
are favorable. Such sales could reduce our ownership in PAA and could generate
additional gains.
Gain on sale of linefill. We initiated the sale of 5.2 million barrels of
crude oil linefill from the All American Pipeline in November 1999. The sale was
substantially completed in February 2000. The linefill was located in the
segment of the All American Pipeline that extends from Emidio, California, to
McCamey, Texas. Proceeds from the sale of the linefill were approximately $100.0
million, net of associated costs, and were used for working capital purposes. We
estimate that we will recognize a total gain of approximately $44.6 million in
connection with the sale of the linefill. As of December 31, 1999, we had
delivered approximately 1.8 million barrels of linefill and recognized a gain of
$16.5 million.
Unauthorized trading losses. As previously discussed, we recognized losses of
approximately $166.4 million and $7.1 million in 1999 and 1998, respectively, as
a result of unauthorized trading by a former employee.
Restructuring charge. A $1.4 million restructuring charge, primarily
associated with severance-related expenses of 24 employees who were terminated,
was incurred by PAA in 1999. Approximately $1.1 million of these costs are
included in marketing, transportation, storage and terminalling expenses and
approximately $0.3 million are included general and administrative expenses. As
of December 31, 1999, all severance costs were paid and the terminated employees
were not employed by PAA. As a result of the restructuring, PAA expects to
reduce cash compensation costs by approximately $1.3 million per year.
Extraordinary item. The extraordinary item of $0.5 million (net of minority
interest of $.07 million and deferred tax of $0.3 million) in 1999 relates to
the write-off of certain debt issue costs and penalties associated with the
prepayment of debt.
Reduction in carrying cost of oil and natural gas properties. In 1998, we
incurred an impairment of our oil and natural gas properties due to low crude
oil prices at December 31, 1998. Under full-cost accounting rules, unamortized
costs of proved oil and natural gas properties are subject to a ceiling, which
limits such costs. At December 31, 1998, the capitalized costs of our proved oil
and natural gas properties exceeded this limit and we reduced the carrying cost
of those properties by $109.0 million after tax ($173.9 million pre-tax).
Upstream Results
The following table sets forth certain of our upstream operating information
for the periods presented.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1999 1998 1997
------------- ------------- -------------
(in thousands, except per unit data)
<S> <C> <C> <C>
Average Daily Production Volumes:
Barrels of oil equivalent
California (approximately 91% oil) 15.6 13.8 11.2
Offshore California (100% oil) 2.2 - -
Gulf Coast (100% oil) 2.6 4.8 5.3
Illinois Basin (100% oil) 3.0 3.5 3.6
Sold properties - - 0.1
------------ ------------ ------------
Total (approximately 94% oil) 23.4 22.1 20.2
============ ============ ============
Unit Economics:
Average sales price per BOE $ 13.61 $ 12.73 $ 14.83
Production expense per BOE 6.51 6.29 6.16
------------ ------------ ------------
Gross margin per BOE 7.10 6.44 8.67
Upstream G&A expense per BOE 0.85 0.68 0.65
------------ ------------ ------------
Gross profit per BOE $ 6.25 $ 5.76 $ 8.02
============ ============ ============
</TABLE>
Total oil equivalent production increased approximately 6% to an average of
23,400 BOE per day over the 1998 level of 22,100 BOE per day and 16% above the
1997 level of 20,200 BOE per day. The volume increase in 1999 is primarily
associated with our ongoing acquisition and exploitation activities, offset
somewhat by decreased production from certain of our other properties. The
offshore California Point Arguello Unit, which we acquired from Chevron in July
1999, accounted
40
<PAGE>
for approximately 2,200 BOE per day of the increase. Net daily production from
our onshore California properties increased to approximately 15,600 BOE per day
in 1999, up 1,800 BOE per day, or 13% over 1998 and 39% over 1997, due to our
acquisition and exploitation activities. Excluding production from the Mt. Poso
Field, which we acquired in December 1998, California production was up 6% from
1998. The increase in 1998 as compared to 1997 is partially attributable to the
acquisition of the Arroyo Grande Field in the fourth quarter of 1997. Net daily
production for our Gulf Coast properties averaged approximately 2,600 BOE per
day in 1999, compared to 4,800 BOE per day in 1998 and 5,300 BOE per day in
1997. The Gulf Coast production decrease is due to downtime as a result of
mechanical problems and the effects of natural decline. During 1998 and 1999,
several wells in this area had mechanical problems and were not returned to
production due to lower operating margins. We expect that the rate of production
decline in this area will decrease from the levels discussed above, as several
wells have been returned to production due to higher crude oil prices and
overall decline rates are flattening out. Net daily production for this area was
approximately 2,700 barrels per day in May 2000. Net daily production in the
Illinois Basin averaged 3,000 BOE per day during 1999, 3,500 BOE per day in 1998
and 3,600 BOE per day in 1997. The decrease is primarily due to natural decline
and the impact of wells that were shut-in due to low crude oil prices in 1998.
Our product price averaged $13.61 per BOE in 1999, 7% higher than the price
received in 1998 and 8% lower than the price received in 1997. Our product price
represents a combination of fixed and floating price arrangements, typically
tied to a benchmark price index and subjected to discounts for location and
quality differentials. The price index is the NYMEX benchmark WTI crude oil
price, which averaged $19.25 per barrel in 1999, $14.43 per barrel in 1998, and
$20.63 per barrel in 1997. Our average product prices also include the effects
of hedging transactions such as financial swap and collar arrangements and
futures transactions. These transactions had the effect of decreasing the
overall average price we received (relative to the price we would have received
in the absence of hedging) by $1.30 per BOE in 1999, increasing the price by
$2.98 per BOE in 1998 and decreasing the price by $1.26 per BOE in 1997. We
maintained hedges on approximately 63% of our crude oil production throughout
1999 at an average NYMEX WTI crude oil price of approximately $18.00 per barrel.
We routinely hedge a portion of our crude oil production. See "Outlook" and Item
7a. - "Quantitative and Qualitative Disclosures about Market Risk".
Upstream unit gross margin (well-head revenue less production expenses) for
1999 was $7.10 per BOE, compared to $6.44 per BOE in 1998 and $8.67 per BOE in
1997. Average unit production expenses were $6.51 per BOE, $6.29 per BOE and
$6.16 per BOE in 1999, 1998, and 1997, respectively.
Unit general and administrative expense increased to $0.85 per BOE in 1999
compared to $0.68 per BOE during 1998 and $0.65 per BOE during 1997. Total
upstream general and administrative expense was $7.8 million, $5.5 million and
$4.8 million in 1999, 1998 and 1997, respectively. The increase in 1999 as
compared to 1998 is primarily attributable to increased personnel costs
(approximately $0.8 million), expenses related to our Year 2000 computer
readiness project (approximately $0.4 million), and legal expenses
(approximately $0.4 million). The increase in 1998 as compared to 1997 is
primarily due to our California producing property acquisitions.
Total upstream DD&A was $19.6 million, $25.6 million and $22.6 million in
1999, 1998 and 1997, respectively. On a per unit basis, DD&A was $2.13, $3.00
and $2.83 in 1999, 1998 and 1997, respectively. These amounts exclude the
reduction in the carrying cost of our oil and natural gas properties in 1998.
Midstream Results
Gross margin from our midstream activities, excluding the unauthorized trading
losses was $107.7 million, $38.4 million and $12.5 million for the years ended
December 31, 1999, 1998 and 1997, respectively. An analysis of these results is
discussed below. The following table sets forth certain of our midstream
operating information for the periods presented (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------
1999 1998 1997
---------------- ---------------- ------------------
(restated)
<S> <C> <C> <C>
Operating Results:
Gross margin
Pipeline $ 56,864 $ 16,490 $ -
Terminalling and storage
and gathering and marketing 50,826 21,871 12,480
Unauthorized trading losses (166,440) (7,100) -
--------------- ---------------- -----------------
Total (58,750) 31,261 12,480
General and administrative expense (23,599) (5,297) (3,529)
-------------- --------------- ----------------
Gross profit $ (82,349) $ 25,964 $ 8,951
============== =============== ================
</TABLE>
41
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------
1999 1998 1997
---------------- ---------------- ------------------
(restated)
<S> <C> <C> <C>
Average Daily Volumes (barrels):
Pipeline Activities:
All American
Tariff activities 101 113 -
Margin activities 56 50 -
Other 61 - -
---------------- ---------------- ------------------
Total 218 163 -
================ ================ ==================
Lease gathering 239 88 71
Bulk purchases 138 98 49
---------------- ---------------- ------------------
Total 377 186 120
================ ================ ==================
Terminal throughput 83 80 77
================ ================ ==================
Storage leased to third parties,
monthly average volumes 1,975 1,150 668
================ ================ ==================
</TABLE>
Pipeline Operations. Gross margin from pipeline operations was $56.9 million
for the year ended December 31, 1999, compared to $16.5 million for 1998. The
increase resulted from twelve months of results from the All American Pipeline
in 1999 versus five months in 1998, increased margins from our pipeline merchant
activities, and to the 1999 acquisitions of Scurlock and the West Texas
gathering system which contributed approximately $4.8 million of pipeline gross
margin. The increase was partially offset by lower tariff transport volumes, due
to lower production from Exxon's Santa Ynez Field and the Point Arguello Field,
both offshore California. Volumes from these fields have steadily declined from
1995 through 1999. A 5,000 barrel per day decline in volumes shipped from these
fields would result in a decrease in annual pipeline tariff revenues of
approximately $2.6 million.
The margin between revenue and direct cost of crude purchased was $33.5
million for the year ended December 31, 1999, compared to $3.9 million in 1998.
Pipeline tariff revenues were approximately $46.4 million for the year ended
December 31, 1999, compared to approximately $19.0 million in 1998. Pipeline
operations and maintenance expenses were approximately $24.0 million for the
year ended December 31, 1999, as compared to $6.1 million for 1998.
Tariff transport volumes on the All American Pipeline decreased from an
average of 113,000 barrels per day for the year ended December 31, 1998, to
101,000 barrels per day in 1999 due primarily to a decrease in shipments of
offshore California production, which decreased from 90,000 barrels per day in
1998 to 79,000 barrels per day in 1999. Barrels associated with our merchant
activities on the All American Pipeline increased from 50,000 barrels per day in
1998 to 56,000 barrels per day for the year ended December 31, 1999. Tariff
volumes shipped on the Scurlock and West Texas Gathering systems averaged 61,000
barrels per day during 1999.
In March 2000, we sold the segment of the All American Pipeline that extends
from Emidio, California to McCamey, Texas. We initiated the sale of
approximately 5.2 million barrels of crude oil linefill from the All American
Pipeline in November 1999. The sale of the linefill was substantially complete
in February 2000. We estimate that we will recognize a total gain of
approximately $44.6 million in connection with the sale of the linefill. As of
December 31, 1999, we had delivered approximately 1.8 million barrels of
linefill and recognized a gain of $16.5 million. During 1999, we reported gross
margin of approximately $5.0 million associated with operating the segment of
the All American Pipeline that was sold. See Item 1. - "Business - Midstream
Activities - Midstream Acquisitions and Dispositions".
The following table sets forth the All American Pipeline average deliveries
per day within and outside California from July 30, 1998, our date of
acquisition (in thousands):
Year Ended December 31,
---------------------------
1999 1998
--------- --------
Deliveries:
Average daily volumes (barrels):
Within California 101 111
Outside California 56 52
--------- --------
Total 157 163
========= ========
42
<PAGE>
Gathering and Marketing Activities and Terminalling and Storage Activities.
Excluding the unauthorized trading losses, gross margin from terminalling and
storage and gathering and marketing activities was approximately $50.8 million
for the year ended December 31, 1999, reflecting a 132% increase over the $21.9
million reported for 1998 and a 307% increase over the $12.5 million reported
for 1997. The increase in gross margin is due to an increase in lease gathering
and bulk purchase volumes, primarily as a result of the Scurlock acquisition,
which contributed approximately $26.3 million of 1999 gross margin, and an
increase in storage capacity leased at our Cushing Terminal. Lease gathering
volumes increased from an average of 88,000 and 71,000 barrels per day in 1998
and 1997, respectively, to approximately 239,000 barrels per day in 1999. Bulk
purchase volumes increased from approximately 98,000 and 49,000 barrels per day
for 1998 and 1997, respectively, to approximately 138,000 barrels per day this
year. Leased terminal capacity increased significantly from approximately 1.1
million barrels and 0.7 million barrels per month in 1998 and 1997,
respectively, to 2.0 million barrels per month during 1999. The 1.1 million
barrel expansion of our Cushing Terminal was placed in service in the second
quarter of 1999. Throughput volumes at our terminals increased approximately
3,000 and 6,000 barrels per day in the current year period from 1998 and 1997,
respectively.
In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of PAA's suppliers and trading partners reduced or
eliminated the open credit previously extended to PAA. Consequently, the amount
of letters of credit PAA needed to support the level of crude oil purchases then
in effect increased significantly. In addition, the cost to PAA of obtaining
letters of credit increased under the amended credit facility. In many instances
PAA arranged for letters of credit to secure its obligations to purchase crude
oil from its customers, which increased its letter of credit costs and decreased
its unit margins. In other instances, primarily involving lower margin wellhead
and bulk purchases, certain of PAA's purchase contracts were terminated. As a
result of these changes, aggregate volumes purchased are expected to decrease by
150,000 barrels per day, consisting primarily of lower unit margin purchases.
Approximately 50,000 barrels per day of the decrease is related to barrels
gathered at producer lease locations and 100,000 barrels per day is attributable
to bulk purchases. As a result of the increase in letter of credit costs and
reduced volumes, annual Adjusted EBITDA is expected to be adversely affected by
approximately $5.0 million, excluding the positive impact of current favorable
market conditions.
Midstream General and Administrative. General and administrative expenses were
$23.6 million for the year ended December 31, 1999, compared to $5.3 million and
$3.5 million for 1998 and 1997, respectively. The increase from 1998 to 1999 was
primarily attributable to the Scurlock acquisition in 1999 ($13.1 million), the
All American Pipeline acquisition in 1998 ($0.7 million), expenses related to
the operation of Plains All American Pipeline as a public entity ($0.7 million)
and continued expansion of our midstream business activities. The increase in
1998 compared to 1997 is primarily due to the July 1998 All American Pipeline
acquisition and expansion of our business activities. As a result of the
unauthorized trading losses, we will incur increased expenses in 2000, primarily
accounting and consulting related.
Midstream Depreciation and Amortization. Depreciation and amortization expense
was $17.4 million in 1999, $5.4 million in 1998 and $1.2 million in 1997. The
increase in 1999 is due primarily to the Scurlock and West Texas Gathering
System acquisitions in 1999 and the All American Pipeline acquisition in July
1998. The increase in 1998 is due to the All American Pipeline acquisition.
Liquidity and Capital Resources
General
The financial loss resulting from the unauthorized trading activity placed PAA
in default under certain of the covenants of its credit facilities and also
created significant liquidity issues. In December 1999, PAA executed amended
credit facilities and obtained default waivers from all of its lenders. In
connection with the amendments, we loaned approximately $114.0 million to PAA.
By May 2000 our liquidity was significantly improved through PAA's sales of the
segment of the All American Pipeline and the related crude oil linefill for
total proceeds of $224.0 million and the refinancing of PAA's credit facilities.
Consolidated debt subsequent to the May 2000 refinancing was approximately
$564.0 million, of which $256.0 million was reflected on the balance sheet as
PAA debt. This balance compares to consolidated debt at December 31, 1999, of
approximately $787.0 million, of which $369.0 million was PAA debt.
In May 2000, PAA entered into two new credit facilities totaling $700.0
million. See "Credit Facilities." The new PAA facilities provide PAA with
significant working capital availability, as well as flexibility for both
internal and external growth opportunities. Giving effect to the repayment of
existing debt and closing costs, PAA had approximately $256.0 million
outstanding on its revolving credit facility as of May 8, 2000. Accordingly, PAA
has approximately $144.0 million of additional borrowing capacity for
acquisitions, capital expansion projects and general working capital purposes.
In addition, the capacity available under the letter of credit facility should
enable PAA to absorb additional acquisitions of other midstream assets and
entities.
43
<PAGE>
Subsequent to the refinancing and repayment to us of the intercompany loan,
the balance outstanding on our $225.0 million revolving credit facility was
approximately $28.0 million. This provides approximately $197.0 of liquidity to
fund upstream working capital requirements, capital expenditures for 2000, as
well as acquisition opportunities. The borrowing base under the revolving credit
facility was reconfirmed by the lenders in the second quarter of 2000.
We believe that we have sufficient liquid assets, cash from operations and
borrowing capacity under our credit agreements to meet our financial
commitments, debt service obligations, contingencies and anticipated capital
expenditures.
Cash Flows
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------
1999 1998 1997
------------------ ------------------- --------------------
<S> <C> <C> <C>
(in millions)
Cash provided by (used in):
Operating activities $ (76.0) $ 37.6 $ 30.3
Investing activities (266.4) (483.4) (107.6)
Financing activities 404.0 448.6 78.5
</TABLE>
Operating Activities. Net cash used in operating activities in 1999 resulted
from the unauthorized trading losses. The losses were partially offset by
increased midstream margins due to the Scurlock and West Texas gathering system
acquisitions and higher crude oil prices and increased volumes associated with
our ongoing upstream acquisition and exploitation activities.
Investing Activities. 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. Net cash used in investing
activities for 1998 consisted primarily of approximately $394.0 million for the
purchase of the All American Pipeline and SJV gathering system and $80.3 million
for acquisition, exploration, exploitation and development costs.
Financing activities. Cash provided by financing activities in 1999 was
generated primarily from net issuances of (1) $50.0 million of Series F
Preferred Stock (2) $50.8 million in PAA common units and (3) $325.2 million of
short-term and long-term debt.
In connection with the private placement sale of the Series F Preferred Stock,
we agreed with the purchasers of the Series F Preferred Stock (who were also
holders of the Series E Preferred Stock), to reduce the conversion price of the
Series E Preferred Stock from $18.00 to $15.00. This reduction of the conversion
price of the Series E Preferred Stock was effected through an exchange of each
outstanding share of Series E Preferred Stock for a share of a new Series G
Preferred Stock. Other than the reduction of the conversion price, the terms of
the Series G Preferred Stock are substantially identical to those of the Series
E Preferred Stock.
In October 1999, PAA completed a public offering of an additional 2,990,000
common units, representing limited partner interests in PAA, at $18.00 per unit.
Net proceeds to PAA from the offering, excluding our general partner
contribution, were approximately $50.8 million after deducting underwriters'
discounts and commissions and offering expenses of approximately $3.1 million.
The proceeds were used to reduce outstanding debt. Approximately $44.0 million
was used to prepay the term loan portion of the Plains Scurlock bank credit
agreement and the remainder was used to reduce the balance outstanding on PAA's
other revolving credit facility.
Net issuances of debt include the sale of $75.0 million principal amount of
Senior Subordinated Notes due 2006, Series E, bearing a coupon rate of 10.25%.
The Series E Notes were issued pursuant to a Rule 144A private placement at
approximately 101% of par. The stated coupon rate of interest and maturity date
are the same as those of our existing $200.0 million principal amount of senior
subordinated notes. Our net proceeds, after costs of the transaction, were
approximately $74.6 million, and were used to reduce the outstanding balance on
our revolving credit facility. See Note 7 to the consolidated financial
statements.
Financing activities for 1999 also included dividend payments of approximately
$4.2 million on the Series E Preferred Stock and distributions to PAA
unitholders of $22.2 million.
44
<PAGE>
Cash provided by financing activities during 1998 included net issuances of
(1) $138.8 million of short-term and long-term debt, (2) $241.7 million of
common units in connection with PAA's initial public offering and (3) $85.0
million in preferred stock.
Working Capital
At December 31, 1999, we had working capital of approximately $115.9 million.
Working capital at December 31, 1999 includes $37.9 million of pipeline linefill
and $103.6 million for the segment of the All American Pipeline that were both
sold in the first quarter of 2000. See Item 1. "Business - Midstream Activities
- Midstream Acquisitions and Dispositions." Proceeds from the linefill sale of
approximately $100.0 million were used to repay short term working capital loans
incurred in December 1999 and January 2000 and to fund the portion of the
unauthorized trading losses that were settled in cash during the first quarter
of 2000. Proceeds from the sale of the pipeline of approximately $129.0 million
were used to reduce PAA's outstanding debt under its bank credit agreement. We
had a working capital deficit of approximately $21.0 million at December 31,
1998. We have historically operated with a working capital deficit due primarily
to ongoing capital expenditures that have been financed through cash flow and
our revolving credit facility subsequently causing a timing difference between
the expenditure and the payment.
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 sale of
subordinated notes, common stock and preferred stock. We intend to make
aggregate capital expenditures of approximately $81.0 million in 2000, including
approximately $72.0 million on the development and exploitation of our upstream
properties, and approximately $9.0 million for midstream activities. In
addition, we intend to continue to pursue the acquisition of underdeveloped
producing properties. We believe that we will have sufficient cash from
operating activities and borrowings under the revolving credit facility to fund
our upstream capital expenditures. We plan to fund the midstream capital
expenditures through working capital, cash flow and draws under PAA's revolving
credit facility under its bank credit agreement.
Commitments
The aggregate amounts of maturities of all long-term indebtedness for the next
five years based on balances outstanding subsequent to the May 2000 refinancing
are: 2000 - $0.5 million, 2001 - $2.2 million, 2002 - $7.4 million, 2003 - $7.4
million, and 2004 - $263.4 million. These amounts consist principally of amounts
due under our revolving credit facilities Historically, we have renewed and/or
extended the revolving credit portion of our credit facilities prior to
commencing scheduled payments.
PAA will distribute 100% of its available cash within 45 days after the end of
each quarter to unitholders of record, and to us. Available cash is generally
defined as all cash and cash equivalents on hand at the end of the quarter less
reserves established for future requirements. Minimum quarterly distributions
are $0.45 for each full fiscal quarter. Distributions of available cash to the
holders of subordinated units are subject to the prior rights of the holders of
common units to receive the minimum quarterly distributions for each quarter
during the subordination period, and to receive any arrearages in the
distribution of minimum quarterly distributions on the common units for prior
quarters during the subordination period. The expiration of the subordination
period will generally not occur prior to December 31, 2003. There were no
arrearages on common units at December 31, 1999.
In connection with its crude oil marketing, PAA provides certain purchasers
and transporters with irrevocable standby letters of credit to secure their
obligation for the purchase of crude oil. Generally, these letters of credit are
issued for up to seventy day periods and are terminated upon completion of each
transaction. At December 31, 1999, PAA had outstanding letters of credit of
approximately $321.5 million. Such letters of credit are secured by PAA's crude
oil inventory and accounts receivable.
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
local, state and federal environmental laws and regulations may require
substantial expenditures to comply with such rules and regulations.
45
<PAGE>
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 are approximately $13.4 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 1999, 1998 and 1997 include $0.5 million, $0.8 million and $0.6 million,
respectively, of expense associated with these estimated future costs. For
valuation and realization purposes of the affected crude oil and natural gas
properties, these estimated future costs are also deducted from estimated future
gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in the accompanying Consolidated Financial
Statements.
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 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.
Credit Facilities
Amounts borrowed under our credit agreements before and after refinancing were
as follows (in thousands):
<TABLE>
<CAPTION>
December 31, May 8,
1999 2000
---------------- ----------------
<S> <C> <C>
Revolving credit facility $ 137,300 $ 27,600
New Plains Marketing, L.P. revolving credit facility - 256,000
New Plains Marketing, L.P. letter of credit and hedged inventory facility - 20,250
PAA bank credit agreement 225,000 -
Plains Scurlock bank credit agreement 85,100 -
PAA letter of credit and borrowing facility 13,719 -
PAA secured term credit facility 45,000 -
---------------- ----------------
$ 506,119 $ 303,850
================ ================
</TABLE>
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 upstream subsidiaries. The
borrowing base under the revolving credit facility at December 31, 1999, 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.
The revolving credit facility, as amended, matures on July 1, 2001, at which
time the remaining outstanding balance converts to a term loan which is
repayable in sixteen equal quarterly installments commencing October 1, 2001,
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 Base Rate (as defined
therein). At December 31, 1999, letters of credit of $0.6 million and borrowings
of approximately $137.3 million were outstanding under the revolving credit
facility.
The revolving credit facility contains covenants which, among other things,
prohibit 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. We are currently in
compliance with the covenants in the revolving credit facility. Under the most
restrictive of these covenants, at December 31, 1999, we could have borrowed the
full $225.0 million available under the revolving credit facility.
The unauthorized trading losses discovered in November 1999 resulted in a
default of the covenants under PAA's 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 its lenders. PAA
paid approximately $13.7 million in connection with the amended credit
facilities.
46
<PAGE>
On May 8, 2000, PAA entered into new bank credit agreements. The borrower
under the new facilities is Plains Marketing, L.P., a subsidiary of PAA. PAA is
a guarantor of the obligations under the credit facilities. The obligations are
also guaranteed by the subsidiaries of Plains Marketing, L.P. PAA entered into
the credit agreements in order to:
. refinance the existing bank debt of Plains Marketing, L.P. and Plains
Scurlock Permian, L.P. in conjunction with the merger of these
subsidiaries;
. refinance existing bank debt of All American Pipeline, L.P.;
. repay to us $114.0 million plus accrued interest of subordinated debt, and
. provide additional flexibility for working capital, capital expenditures,
and for other general corporate purposes.
PAA's new bank credit agreements consist of:
. a $400.0 million senior secured revolving credit facility. At closing, PAA
had $256.0 million outstanding under the revolving credit facility. The
revolving credit facility is secured by substantially all of PAA's assets
and matures in April 2004. No principal is scheduled for payment prior to
maturity. The revolving credit facility bears interest at PAA's option at
either the base rate, as defined, plus an applicable margin, or LIBOR plus
an applicable margin. PAA incurs a commitment fee on the unused portion of
the revolving credit facility.
. A $300.0 million senior secured letter of credit and borrowing facility,
the purpose of which is to provide standby letters of credit to support the
purchase and exchange of crude oil for resale and borrowings to finance
crude oil inventory which has been hedged against future price risk. The
letter of credit facility is secured by substantially all of PAA's assets
and has a sublimit for cash borrowings of $100.0 million to purchase crude
oil which has been hedged against future price risk. The letter of credit
facility expires in April 2003. Aggregate availability under the letter of
credit facility for direct borrowings and letters of credit is limited to a
borrowing base which is determined monthly based on certain of PAA's
current assets and current liabilities, primarily accounts receivable and
accounts payable related to the purchase and sale of crude oil. At closing,
there were letters of credit of approximately $173.8 million and borrowings
of approximately $20.3 million outstanding under this facility.
PAA's bank credit agreements prohibit distributions on, or purchases or
redemptions of, units if any default or event of default is continuing. In
addition, the agreements contain various covenants limiting PAA's ability to,
among other things:
. incur indebtedness;
. grant liens;
. sell assets;
. make investments;
. engage in transactions with affiliates;
. enter into prohibited contracts; and
. enter into a merger or consolidation.
PAA's bank credit agreements treat a change of control as an event of default
and also require PAA to maintain:
. a current ratio (as defined) of 1.0 to 1.0;
. a debt coverage ratio which is not greater that 4.0 to 1.0 for the period
from March 31, 2000, to March 31, 2002, and subsequently 3.75 to 1.0;
. an interest coverage ratio which is not less than 2.75 to 1.0; and
. a debt to capital ratio of not greater than 0.65 to 1.0.
A default under PAA's bank credit agreements would permit the lenders to
accelerate the maturity of the outstanding debt and to foreclose on the assets
securing the credit facilities. As long as PAA is in compliance with its bank
credit agreements, they do not restrict its ability to make distributions of
"available cash" as defined in its partnership agreement. PAA is currently in
compliance with the covenants in its bank credit agreements. Under the most
restrictive of these covenants, at May 8, 2000, PAA could have borrowed the full
$400.0 million under its secured revolving credit facility.
47
<PAGE>
Contingencies
Since our announcement in November 1999 of PAA's losses resulting from
unauthorized trading by a former employee, numerous class action lawsuits have
been 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. See Item 3. - "Legal Proceedings."
We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover releases that were previously
unidentified. While we maintain an extensive inspection program designed to
prevent and, as applicable, to detect and address such releases promptly,
damages and liabilities incurred due to any future environmental releases from
our assets may substantially affect our business.
Outlook
Our upstream activities are affected by changes in crude oil prices, which
historically have been volatile. The benchmark NYMEX crude oil price of $25.60
per barrel at December 31, 1999 was more than double the $12.05 per barrel price
at year-end 1998. Although we have routinely hedged a substantial portion of our
crude oil production and intend to continue this practice, substantial future
crude oil price declines would adversely affect our overall results, and
therefore our liquidity. Furthermore, low crude oil prices could affect our
ability to raise capital on favorable terms. 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. In order to manage our exposure to commodity price risk, we have
routinely hedged a portion of our crude oil production. For 2000, we have
entered into various arrangements which provide for us to receive an average
minimum NYMEX WTI price of $16.00 per barrel on 18,500 barrels of oil per day.
Thus, based on our average fourth quarter 1999 crude oil production rate, these
arrangements generally provide us with downside price protection for
approximately 79% of our production. Approximately 10,000 barrels per day of the
volumes hedged in 2000 will participate in price increases above the $16.00 per
barrel floor price, subject to a ceiling limitation of $19.75 per barrel. For
2001, we have entered into various arrangements under which we will receive an
average minimum NYMEX WTI price of approximately $19.00 per barrel on 12,000
barrels per day, which is equivalent to 51% of our fourth quarter 1999 crude oil
production levels. Of these volumes, 100% have full market price participation
up to $27.00 per barrel, 50% have price participation between $27.00 per barrel
and $30.00 per barrel and 100% have full market price participation at prices
above $30.00 per barrel. All of our NYMEX crude oil prices are before quality
and location differentials. Because of the quality and location of our crude oil
production, these adjustments will reduce our net price per barrel. Management
intends to continue to maintain hedging arrangements for a significant portion
of our production. Such contracts may expose us to the risk of financial loss in
certain circumstances. See Item 1. - "Business -- Product Markets and Major
Customers" and Item 7a. - "Quantitative and Qualitative Disclosures About Market
Risk".
As is common with most merchant activities, our ability to generate a profit
on our midstream margin activities is not tied to the absolute level of crude
oil prices but is generated by the difference between the price paid and other
costs incurred in the purchase of crude oil and the price at which we sell crude
oil. The gross margin generated by tariff activities depends on the volumes
transported on the pipeline and the level of the tariff charged, as well as the
fixed and variable costs of operating the pipeline. These operations are
affected by overall levels of supply and demand for crude oil.
A significant portion of the gross margin of PAA is derived from the Santa
Ynez and Point Arguello fields located offshore California. Volumes received
from the Santa Ynez and Point Arguello fields have declined from 92,000 and
60,000 average daily barrels, respectively, in 1995 to 59,000 and 20,000 average
daily barrels, respectively, for the year ended December 31, 1999. We expect
that there will continue to be natural production declines from each of these
fields as the underlying reservoirs are depleted. As operator of Point Arguello,
we are conducting additional drilling and other activities on this field, but we
can not assure you that these activities will affect the production decline. A
5,000 barrel per day decline in volumes shipped from these fields would result
in a decrease in annual pipeline tariff revenues of approximately $2.6 million.
As previously discussed, our future results will also be affected by (1)
natural decline in our producing oil and natural gas properties, (2) decreased
gross margin due to the sale of the segment of the All American Pipeline (3)
declines in offshore California production transported on the All American
Pipeline and (4) reduced lease gathering and bulk purchase volumes and increased
expenses resulting from the unauthorized trading losses.
48
<PAGE>
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS 133"). SFAS 133 requires that all
derivative instruments be recorded on the balance sheet at their fair value.
Changes in the fair value of derivatives are recorded each period in current
earnings or other comprehensive income, depending on whether a derivative is
designated as part of a hedge transaction and, if so, the type of hedge
transaction. For fair value hedge transactions in which we are hedging changes
in an asset's, liability's, or firm commitment's fair value, changes in the fair
value of the derivative instrument will generally be offset in the income
statement by changes in the hedged item's fair value. For cash flow hedge
transactions, in which we are hedging the variability of cash flows related to a
variable-rate asset, liability, or a forecasted transaction, changes in the fair
value of the derivative instrument will be reported in other comprehensive
income. The gains and losses on the derivative instrument that are reported in
other comprehensive income will be reclassified as earnings in the periods in
which earnings are affected by the variability of the cash flows of the hedged
item. This statement was amended by Statement of Financial Accounting Standards
No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral
of the Effective Date of FASB Statement No. 133 ("SFAS 137") issued in June
1999. SFAS 137 defers the effective date of SFAS 133 to fiscal years beginning
after June 15, 2000. We are required to adopt this statement beginning in 2001.
We have not yet determined the effect that the adoption of SFAS 133 will have on
our financial position or results of operations.
Year 2000
Year 2000 Project. In order to address the Year 2000 issue, we initiated a
Year 2000 project. We incurred approximately $2.1 million through December 31,
1999, in connection with our Year 2000 project, approximately $1.4 million of
which were costs paid to third parties. We did not encounter any critical system
application, hardware or equipment failures during the date roll over to the
Year 2000, and have not experienced any disruptions of business activities as a
result of Year 2000 failures by our customers, suppliers, service providers or
business partners.
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 our
inventory levels, current economic conditions and our expectations of future
commodity prices and interest rates when making decisions with respect to risk
management. We do not enter into derivative transactions for speculative trading
purposes. Substantially all of our derivative contracts are exchanged or traded
with major financial institutions and the risk of credit loss is considered
remote.
Commodity Price Risk. The fair value of outstanding derivative commodity
instruments and the change in fair value that would be expected from a 10
percent adverse price change are shown in the table below (in millions):
<TABLE>
<CAPTION>
December 31,
----------------------------------------------------------------------------
1999 1998
------------------------------------- ----------------------------------
10% 10%
Adverse Adverse
Fair Price Fair Price
Value Change Value Change
----------------- --------------- --------------- ---------------
<S> <C> <C> <C> <C>
Crude oil:
Futures contracts $ - $ (2.8) $ 1.8 $ (0.3)
Swaps and options contracts (22.0) (6.2) 16.9 (4.3)
</TABLE>
The fair values of the futures contracts are based on quoted market prices
obtained from the NYMEX. The fair value of the swaps 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 across-the-board 10 percent adverse change in prices
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.
49
<PAGE>
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 for debt outstanding
at December 31, 1999. Our variable rate debt bears interest at LIBOR plus the
applicable margin. The average interest rates presented below are based upon
rates in effect at December 31, 1999. The carrying value of variable rate bank
debt approximates fair value as 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. The fair value of the Redeemable
Preferred Stock approximates its liquidation value at December 31, 1999.
<TABLE>
<CAPTION>
Expected Year of Maturity Fair
--------------------------------------------------------------------------------
2000 2001 2002 2003 2004 Thereafter Total Value
-------------------------------------------------------------------------------- -------
(dollars in millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Liabilities:
Short-term debt - variable rate $ 58.7 $ - $ - $ - $ - $ - $ 58.7 $ 58.7
Average interest rate 8.74% 8.74%
Long-term debt - variable rate 50.6 9.2 37.5 35.0 114.3 200.8 447.4 447.4
Average interest rate 8.44% 7.70% 7.76% 7.64% 8.63% 8.17% 8.23%
Long-term debt - fixed rate 0.5 0.5 0.5 0.5 0.5 275.0 277.5 268.1
Average interest rate 8.00% 8.00% 8.00% 8.00% 8.00% 10.25% 10.23%
Redeemable Preferred Stock - - - - - - $ 138.8 $ 138.8
</TABLE>
At December 31, 1998, the carrying value of all variable rate bank debt and
the Redeemable Preferred Stock of $184.7 million and $88.5 million,
respectively, approximated the fair value and liquidation value, respectively,
at that date. The carrying value and fair value of the fixed rate debt was
$200.0 million and $202.0 million, respectively, at that date.
Interest rate swaps and collars 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, 1999, we had
interest rate swap and collar arrangements for an aggregate notional principal
amount of $240.0 million, which positions had an aggregate value of
approximately $1.0 million as of such date. These instruments are based on LIBOR
margins and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0
million of debt and a floor of 6% and a ceiling of 8% for $125.0 million of
debt. In August 1999, we terminated our swap arrangements on an aggregate
notional principal amount of $175.0 million and we received consideration in the
amount of approximately $10.8 million.
At December 31, 1998, we had interest rate swap arrangements for an aggregate
notional principal amount of $200.0 million and would have been required to pay
approximately $3.3 million to terminate the instruments at that date.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in the 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.
50
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in the 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.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding our directors will be included in the proxy statement
for the 2000 annual meeting of stockholders (the "Proxy Statement") to be filed
within 120 days after December 31, 1999, and is incorporated herein by
reference. Information with respect to our executive officers is presented in
Part I, Item 4 of this report.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation will be included in the Proxy
Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table lists the only persons who, to our knowledge, may be
deemed to be beneficial owners, as of April 20, 2000 of more than 5% of the
Company's Common Stock.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
Shares Beneficially Percent of
Beneficial Owner Owned Class
------------------------------------------------------------------------------------------------
<S> <C> <C>
Advisory Research, Inc and David B. Heller 1,220,667 (1) 6.6%
Two Prudential Plaza
180 N. Stetson, Suite 5780
Chicago, IL 60601
------------------------------------------------------------------------------------------------
EnCap Energy Capital Fund III, L.P. 3,693,203 (2) 17.0%
EnCap Energy Capital Fund III-B, L.P.
Energy Capital Investment Company PLC
BOCP Energy Partners, L.P.
1100 Louisiana St., Suite 3150
Houston, TX 77002
------------------------------------------------------------------------------------------------
FMR Corp 1,038,400 (3) 5.8%
82 Devonshire Street
Boston, MA 02109
------------------------------------------------------------------------------------------------
Arthur E. Hall and Hallco Inc. 1,210,235 (4) 6.7%
1726 Cedarwood Drive
Minden, NV 89423
------------------------------------------------------------------------------------------------
KAIM Non-Traditional L.P and Richard A. Kayne 6,217,371 (5) 29.1%
1800 Avenue of the Stars, Second Floor
Los Angeles, CA 90067
------------------------------------------------------------------------------------------------
Schroder Capital Management, Inc. 954,600 5.31%
787 Seventh Avenue - 34/th/ Floor
New York, NY 10019
------------------------------------------------------------------------------------------------
Shell Land & Energy Company and Shell Oil Company 1,082,000 (6) 5.7%
One Shell Plaza
Houston, TX 77002
------------------------------------------------------------------------------------------------
State Street Research & Management Company 1,804,258 (7) 10.0%
One Financial Center, 30/th/ Floor
Boston, MA 02111-2690
------------------------------------------------------------------------------------------------
Strome Investment Management, L.P., 1,322,017 (8) 7.1%
SSCO, Inc., and Mark E. Strome
100 Wilshire Blvd., Suite 1500
Santa Monica, CA 90401
------------------------------------------------------------------------------------------------
</TABLE>
_______________
(1) As reported on Schedule 13G filed on February 11, 2000, Advisory Research,
Inc. and David B. Heller have shared voting and dispositive power for these
shares. Includes 569,667 shares of Common Stock issuable upon conversion of
shares of Series G Cumulative Convertible Preferred Stock ("Series G
Preferred Stock"). David B. Heller is President and the controlling
shareholder of Advisory Research, Inc.
(2) Includes 1,774,836 shares issuable upon conversion of Series G Preferred
Stock and 1,918,367 shares issuable upon conversion of Series F
Cumulative Convertible Preferred Stock ("Series F Preferred Stock"). EnCap
Investments L.L.C., a Delaware Corporation, serves as general partner for
EnCap Energy Capital Fund III, L.P. and EnCap Energy Capital Fund III-B,
L.P. In addition, EnCap Investments L.L.C. serves as Manager of BOCP
Energy Partners, L.P. As such, EnCap Investments L.L.C. has sole discretion
over investments made by these entities. The Managing Directors of EnCap
Investments L.L.C. include Gary R. Petersen, Robert L. Zorich, D. Martin
Phillips, and David B. Miller. Energy Capital Investment Company PLC has
sole discretion over its own investments. The Board of Directors for
Energy Capital Investment Company PLC consists of Peter Tudball (Chairman),
Leo Deschuyteneer, Alan Henderson, James Ladner, Gary Petersen, and William
Vanderfelt.
(3) As reported on Schedule 13G filed February 14, 2000, FMR Corp. has sole
voting power for 156,400 shares and sole dispositive power for 1,038,400
shares. As reported on Schedule 13G filed February 14, 2000, members of
the Edward C. Johnson 3d family are the predominant owners of Class B
shares of common stock of FMR Corp., representing approximately 49% of
the voting power of FMR Corp. Mr. Johnson 3d owns 12.0% and Abigail
Johnson owns 24.5% of the aggregate outstanding voting stock of FMR Corp.
The Johnson family group and all other Class B shareholders have entered
into a shareholders' voting agreement under which all Class B shares will
be voted in accordance with the majority vote of Class B shares.
Accordingly, through their ownership of voting common stock and the
execution of the shareholders' voting agreement, members of the Johnson
family may be deemed, under the Investment Company Act of 1940, to form a
controlling group with respect to FMR Corp.
(4) Includes 58,570 shares issuable upon conversion of Series G Preferred
Stock and 163,265 shares issuable upon conversion of Series F Preferred
Stock. As reported on Schedule 13D filed on November 1, 1999, Valarian
Associates, a Nevada limited partnership, Hallco, Inc., a Nevada
corporation, A. E. Hall & Co. Money Purchase Plan (the "Plan") and Mr.
Arthur E. Hall may be deemed to constitute a "group" within the meaning of
Section 13(d)(3) of the Securities Exchange Act. Mr. Hall is (1) the sole
general partner of Valarian, (2) the sole trustee and beneficiary of the
Plan and (3) the President and controlling stockholder of Hallco.
(5) As reported on Schedule 13D/A filed on December 15, 1999, KAIM Non-
Traditional LP ("KAIM N-T, LP") and Mr. Kayne have shared voting and
dispositive power for 5,897,574 shares held by investment partnerships and
managed accounts. Mr. Kayne has sole voting and dispositive power for
319,797 shares which he holds individually. Total includes 101,350 shares
of Common Stock issuable upon the exercise of a warrant, and 2,173,373 and
1,126,531 shares issuable upon conversion of shares of Series G Preferred
Stock and Series F Preferred Stock, respectively. As reported on Schedule
13D/A filed on December 15, 1999, Kayne Anderson Investment Management,
Inc. ("KAIM, Inc."), a Nevada corporation, serves as general partner of
KAIM N-T, L.P. It serves as general partner of and investment adviser to
six investment funds named Arbco Associates, L.P., Kayne Anderson Non-
Traditional Investments, L.P., Offense Group Associates, L.P. and
Opportunity Associates, L.P., each a California limited partnership and
Kayne Anderson Energy Fund, L.P., Kayne Anderson Target Return Fund (QP),
L.P., each a Delaware limited partnership. KAIM N-T, LP also serves as
investment adviser to other clients, including Kayne Anderson Offshore
Limited, a British Virgin Islands corporation.
(6) Includes 932,000 shares issuable upon the conversion of Series D Cumulative
Convertible Preferred Stock and 150,000 shares issuable upon the exercise
of a warrant. As reported on Schedule 13D filed November 12, 1997, Shell
Land & Energy Company, a Delaware corporation ("SLEC") is an indirect
subsidiary of Shell Oil Company, a Delaware corporation ("Shell"). Shell
is wholly-owned by Shell Petroleum Inc., a Delaware corporation, whose
shares are directly or indirectly owned 60% by Royal Dutch Petroleum
Company, The Hague, The Netherlands, and 40% by The "Shell" Transport and
Trading Company, p.l.c., London, England. Royal Dutch Petroleum Company
and The "Shell" Transport and Trading Company, p.l.c., are holding
companies which together directly or indirectly own securities of companies
of the Royal Dutch/Shell Group of Companies.
(7) As reported on Schedule 13G filed April 5, 2000, filed by State Street
Research & Management Company. According to such report, State Street had
sole dispositive power for 1,804,258 shares and the sole voting power for
1,667,958 shares. State Street advised that all such shares are owned by
various clients.
(8) Includes 452,519 and 244,898 shares issuable upon conversion of shares of
Series G Preferred Stock and Series F Preferred Stock, respectively. As
reported on Schedule 13G filed on December 31, 1999, SSCO, Inc. is the sole
general partner of Strome Investment Management, L.P. Mark E. Strome is the
trustee of the trust that is the controlling shareholder of SSCO, Inc.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions will
be included in the Proxy Statement and is incorporated herein by reference.
51
<PAGE>
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).
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, as amended to date (incorporated by
reference to Exhibit 3(b) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993).
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 Certificate of Designation, Preference and Rights of Series F
Cumulative Convertible Preferred Stock.
3.5 Certificate of Designation, Preference and Rights of Series G
Cumulative Convertible Preferred Stock.
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 Purchase Agreement for Stock Warrant dated May 16, 1994, between
Plains Resources Inc. and Legacy Resources, Co., L.P. (incorporated
by reference to Exhibit 4(d) to the Company's Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 1994).
4.5 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).
4.6 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).
4.7 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).
4.8 Stock Purchase Agreement dated as of December 15, 1999, among
Plains Resources Inc. and the purchasers named therein.
4.9 Amendment to Stock Purchase Agreement dated as of December 17,
1999, among Plains Resources Inc. and the purchasers named therein.
**10.1 Employment Agreement dated as of March 1, 1993, between the Company
and Greg L. Armstrong (incorporated by reference to Exhibit 10(b)
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
**10.2 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)).
**10.3 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)).
**10.4 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).
**10.5 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)).
52
<PAGE>
**10.6 Stock Option Agreement dated August 27, 1996 between the Company
and Greg L. Armstrong (incorporated by reference to Exhibit 10(l)
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1996).
**10.7 Stock Option Agreement dated August 27, 1996 between the Company
and William C. Egg Jr. (incorporated by reference to Exhibit 10(m)
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1996).
**10.8 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).
**10.9 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).
10.10 Fourth Amended and Restated Credit Agreement dated May 22,1998,
among the Company and ING (U.S.) Capital Corporation, et. al.
(incorporated by reference to Exhibit 10(y) to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 1998)
**10.11 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)
**10.12 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)
10.13 First Amendment to Fourth Amended and Restated Credit Agreement
dated as of November 17, 1998, among the Company and ING (U.S.)
Capital Corporation, et. al. (incorporated by reference to
Exhibit 10(m) to the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
10.14 Second Amendment to Fourth Amended and Restated Credit Agreement
dated as of March 15, 1999, among the Company and ING (U.S.)
Capital Corporation, et. al. (incorporated by reference to
Exhibit 10(n) to the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
**10.15 Employment Agreement dated as of November 23, 1998, between Harry
N. Pefanis and the Company (incorporated by reference to
Exhibit 10(o) to the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
10.16 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).
10.17 Third Amendment to Fourth Amended and Restated Credit Agreement
dated June 21, 1999, among the Company and ING (U.S.) Capital
Corporation, et. al. (incorporated by reference to Exhibit 10(p) to
the Company's Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1999).
10.18 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).
10.19 Fourth Amendment to Fourth Amended and Restated Credit Agreement
dated September 15, 1999, among the Company and First Union
National Bank, et al. (incorporated by reference to Exhibit 10(q)
to the Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
10.20 Fifth Amendment to Fourth Amended and Restated Credit Agreement
dated December 1, 1999, among the Company and First Union National
Bank, et al.
10.21 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, L.P.).
10.22 Plains All American Inc., 1998 Long-Term Incentive Plan
(incorporated by reference to Exhibit 10.04 to Annual Report on
Form 10-K for the Year Ended December 31, 1998 for Plains All
American Pipeline, L.P.).
10.23 Plains All American Inc., 1998 Management Incentive Plan Plains All
American Inc., 1998 Long-Term Incentive Plan (incorporated by
reference to Exhibit 10.05 to Annual Report on Form 10-K for the
Year Ended December 31, 1998 for Plains All American Pipeline,
L.P.).
10.24 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.).
10.25 Omnibus Agreement among Plains Resources Inc., Plains All American
Pipeline, L.P., Plains Marketing, L.P., All American Pipeline,
L.P., and 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.).
10.26 Transportation Agreement dated July 30, 1993, between All American
Pipeline Company and Exxon Company, U.S.A. (incorporated by
reference to Exhibit 10.9 to Registration Statement, file No.
333-64107 for Plains All American Pipeline, L.P.).
10.27 Transportation Agreement dated August 2, 1993, between All American
Pipeline Company and Texaco Trading and Transportation Inc.,
Chevron U.S.A. and Sun Operating Limited Partnership (incorporated
by reference to Exhibit 10.10 to Registration Statement, file No.
333-64107 for Plains All American Pipeline, L.P.).
10.28 Form of Transaction Grant Agreement (Payment on Vesting)
(incorporated by reference to Exhibit 10.12 to Registration
Statement, file No. 333-64107 for Plains All American Pipeline,
L.P.).
10.29 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.).
10.30 Agreement for Purchase and Sale of Membership Interest in Scurlock
Permian LLC between Marathon Ashland LLC and Plains Marketing,
L.P. dated as of March 17, 1999 (incorporated by reference to
Exhibit
10.31 Asset Sales Agreement between Chevron Pipe Line Company and Plains
Marketing, L.P. dated as of April 16, 1999 (incorporated by
reference to Exhibit 10.17 to Quarterly Report on Form 10-Q for the
Quarter Ended March 31, 1999 for Plains All American Pipeline,
L.P.).
**10.32 Transaction Grant Agreement with Greg L. Armstrong (incorporated by
reference to Exhibit 10.20 to Registration Statement on Form S-1,
file no. 333-86907 1999 for Plains All American Pipeline, L.P.).
10.33 Pipeline Sale and Purchase Agreement dated January 31, 2000, among
Plains All American Pipeline, L.P., All American Pipeline, L.P., El
Paso Natural Gas Company and El Paso Pipeline Company (incorporated
by reference to Exhibit 10.26 to Annual Report on Form 10-K for the
Year Ended December 31, 1999 for Plains All American Pipeline,
L.P.).
10.34 Credit Agreement [Letter of Credit and Hedged Inventory Facility]
dated May 8, 2000, among Plains Marketing, L.P., All American
Pipeline, L.P., Plains All American Pipeline, L.P. and Fleet
National Bank and certain other lenders (incorporated by reference
to Exhibit 10.01 to the Quarterly Report on Form 10-Q for Plains
All American Pipeline, L.P. for the quarterly period ended March
31, 2000).
10.35 Credit Agreement [Revolving Credit Facility] dated May 8, 2000,
among Plains Marketing, L.P., All American Pipeline, L.P., Plains
All American Pipeline, L.P. and Fleet National Bank and certain
other lenders (incorporated by reference to Exhibit 10.02 to the
Quarterly Report on Form 10-Q for Plains All American Pipeline,
L.P. for the quarterly period ended March 31, 2000).
21.1 Subsidiaries of the Company.
*23.1 Consent of PricewaterhouseCoopers LLP.
*27.1 Financial Data Schedule for the year ended December 31, 1999.
________________________
* Filed herewith
** A management contract or compensation plan.
(b) REPORTS ON FORM 8-K
A Current Report on Form 8-K was filed on November 29, 1999, regarding the
discovery of unauthorized trading activity by a former employee of PAA,
which was expected to result in losses to PAA of approximately $160.0
million.
A Current Report on Form 8-K was filed on December 1, 1999, regarding the
execution of agreements with PAA's lenders to provide for a $300.0 million
credit facility and the waiver of defaults under certain covenants in its
credit facilities which resulted from its unauthorized trading losses, as
well as the execution by us of commitment letters for the sale of up to
$50.0 million of a new series of preferred stock, the proceeds of which
would constitute a portion of the $114.0 million in debt financing which we
agreed to provide to PAA.
53
<PAGE>
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: January 18, 2001 By: /s/ Phillip D. Kramer
-------------------------------------------
Phillip D. Kramer, Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
54
<PAGE>
PLAINS RESOURCES INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Financial Statements
Report of Independent Accountants.............................................................. F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998................................... F-3
Consolidated Statements of Operations for the years ended December 31, 1999, 1998 and 1997..... F-4
Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997..... F-5
Consolidated Statements of Changes in Non-redeemable Preferred Stock, Common Stock and other
Stockholders' Equity for the years ended December 31, 1999, 1998 and 1997.................... F-6
Notes to Consolidated Financial Statements..................................................... F-7
</TABLE>
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
<PAGE>
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, after the restatement described in Note 3, present fairly, in all
material respects, the financial position of Plains Resources Inc. and its
subsidiaries at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999 in conformity with accounting principles generally accepted in the
United States. 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, 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 the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 29, 2000
F-2
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1999 1998
---------- ----------
(RESTATED)
ASSETS
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 68,228 $ 6,544
Accounts receivable and other 521,948 130,402
Inventory 40,478 42,520
Assets held for sale (Note 6) 141,486 -
---------- ----------
Total current assets 772,140 179,466
---------- ----------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
Subject to amortization 671,928 596,203
Not subject to amortization 52,031 54,545
Crude oil pipeline, gathering and terminal assets 458,502 378,254
Other property and equipment 7,706 8,606
---------- ----------
1,190,167 1,037,608
Less allowance for depreciation, depletion and amortization (402,514) (375,882)
---------- ----------
787,653 661,726
---------- ----------
OTHER ASSETS 129,767 131,646
---------- ----------
$1,689,560 $ 972,838
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 546,393 $ 190,246
Notes payable and other current obligations 109,880 10,261
---------- ----------
Total current liabilities 656,273 200,507
BANK DEBT 137,300 52,000
BANK DEBT OF A SUBSIDIARY 259,450 175,000
SUBORDINATED DEBT 277,909 202,427
OTHER LONG-TERM DEBT 2,044 2,556
OTHER LONG-TERM LIABILITIES AND DEFERRED CREDITS 21,107 10,253
---------- ----------
1,354,083 642,743
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTE 16)
MINORITY INTEREST 156,045 172,438
---------- ----------
CUMULATIVE CONVERTIBLE PREFERRED STOCK,
STATED AT LIQUIDATION PREFERENCE 138,813 88,487
---------- ----------
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,
net of discount of $1,354 at December 31, 1998 23,300 21,946
Common Stock, $0.10 par value, 50,000,000 shares authorized; issued and outstanding
17,924,050 and 16,881,938 shares at December 31, 1999 and 1998, respectively 1,792 1,688
Additional paid-in capital 130,027 124,679
Accumulated deficit (114,500) (79,143)
---------- ----------
40,619 69,170
---------- ----------
$1,689,560 $ 972,838
========== ==========
</TABLE>
See notes to consolidated financial statements.
F-3
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share data)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1999 1998 1997
---------------- ----------------- --------------
(RESTATED)
<S> <C> <C> <C>
REVENUES
Oil and natural gas sales $ 116,223 $ 102,754 $ 109,403
Marketing, transportation, storage and terminalling revenues 4,626,467 1,129,689 752,522
Gain on PAA unit offerings 9,787 60,815 -
Gain on sale of linefill 16,457 - -
Interest and other income 1,237 834 319
---------- ---------- ---------
4,770,171 1,294,092 862,244
---------- ---------- ---------
EXPENSES
Production expenses 55,645 50,827 45,486
Marketing, transportation, storage and terminalling expenses 4,518,777 1,091,328 740,042
Unauthorized trading losses and related expenses (Note 3) 166,440 7,100 -
General and administrative 31,402 10,778 8,340
Depreciation, depletion and amortization 36,998 31,020 23,778
Reduction in carrying cost of oil and natural gas properties - 173,874 -
Interest expense 46,378 35,730 22,012
---------- ---------- ---------
4,855,640 1,400,657 839,658
---------- ---------- ---------
Income (loss) before income taxes,
minority interest and extraordinary item (85,469) (106,565) 22,586
Minority interest (40,203) 786 -
---------- ---------- ---------
Income (loss) before income taxes and extraordinary item (45,266) (107,351) 22,586
Income tax expense (benefit):
Current (7) 862 352
Deferred (20,472) (45,867) 7,975
---------- ---------- ---------
Income (loss) before extraordinary item (24,787) (62,346) 14,259
Extraordinary item, net of tax benefit
and minority interest (Note 12) (544) - -
---------- ---------- ---------
NET INCOME (LOSS) (25,331) (62,346) 14,259
Less: cumulative preferred stock dividends 10,026 4,762 163
---------- ---------- ---------
NET INCOME (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS $ (35,357) $ (67,108) $ 14,096
========== ========== =========
Basic earnings per share:
Income (loss) before extraordinary item $ (2.02) $ (3.99) $ 0.85
Extraordinary item (0.03) - -
---------- ---------- ---------
Net income (loss) $ (2.05) $ (3.99) $ 0.85
========== ========== =========
Diluted earnings per share:
Income (loss) before extraordinary item $ (2.02) $ (3.99) $ 0.77
Extraordinary item (0.03) - -
---------- ---------- ---------
Net income (loss) $ (2.05) $ (3.99) $ 0.77
========== ========== =========
</TABLE>
See notes to consolidated financial statements.
F-4
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1999 1998 1997
---------------- ----------------- -------------
(RESTATED)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (25,331) $ (62,346) $ 14,259
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization 36,998 31,020 23,778
Reduction in carrying costs of oil and natural gas properties - 173,874 -
Noncash gain (Notes 4 and 6) (26,244) (70,037) -
Minority interest in income of a subsidiary (40,203) 786 -
Deferred income taxes (20,472) (45,867) 7,975
Noncash compensation expense 1,013 - -
Other noncash items (61) 90 221
Change in assets and liabilities from operating activities:
Accounts receivable and other (226,438) 24,084 (9,390)
Inventory 33,930 (19,057) (18,239)
Pipeline linefill (3) (3,904) -
Accounts payable and other current liabilities 171,974 8,987 11,703
Other long-term liabilities 18,873 - -
---------- ---------- ---------
Net cash provided by (used in) operating activities (75,964) 37,630 30,307
---------- ---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for midstream acquisitions (Note 6) (176,918) (394,026) -
Payment for crude oil pipeline, gathering and terminal assets (12,507) (8,131) (923)
Proceeds from the sale of oil and natural gas properties - 131 2,667
Payment for acquisition, exploration and developments costs (77,899) (80,318) (105,646)
Payment for additions to other property and assets (2,472) (1,078) (3,732)
Proceeds from sale of pipeline linefill (Note 6) 3,400 - -
---------- ---------- ---------
Net cash used in investing activities (266,396) (483,422) (107,634)
---------- ---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 744,971 570,560 266,905
Proceeds from short-term debt 131,119 31,750 39,000
Proceeds from sale of capital stock, options and warrants 5,542 828 1,104
Proceeds from issuance of preferred stock 50,000 85,000 -
Proceeds from issuance of common units, net (Note 4) 50,759 241,690 -
Principal payments of long-term debt (449,332) (423,560) (207,011)
Principal payments of short-term debt (82,150) (40,000) (21,000)
Costs incurred in connection
with financing arrangements (19,448) (13,075) -
Preferred stock dividends (4,245) - -
Distributions to unitholders (22,201) - -
Other (971) (4,571) (474)
---------- ---------- ---------
Net cash provided by financing activities 404,044 448,622 78,524
---------- ---------- ---------
Net increase in cash and cash equivalents 61,684 2,830 1,197
Cash and cash equivalents, beginning of year 6,544 3,714 2,517
---------- ---------- ---------
Cash and cash equivalents, end of year $ 68,228 $ 6,544 $ 3,714
========== ========== =========
</TABLE>
See notes to consolidated financial statements.
F-5
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN NON-REDEEMABLE
PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(in thousands)
<TABLE>
<CAPTION>
SERIES D
CUMULATIVE ADDITIONAL ACCUMU-
CONVERTIBLE PAID-IN LATED
PREFERRED STOCK COMMON STOCK CAPITAL DEFICIT TOTAL
-------------------------- --------------------- ----------- ----------- --------
SHARES AMOUNT SHARES AMOUNT
------------ ---------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at
December 31, 1996 - $ - 16,519 $ 1,652 $120,051 $ (26,131) $ 95,572
Capital stock issued
upon exercise of
options and other - - 184 18 1,936 - 1,954
Issuance of preferred
stock and warrant
in connection with
an acquisition 47 20,508 - - 900 - 21,408
Amortization of discount 163 (163) -
Net income for the year - - - - - 14,259 14,259
-------- --------- -------- -------- -------- --------- --------
Balance at
December 31, 1997 47 20,671 16,703 1,670 122,887 (12,035) 133,193
Capital stock issued
upon exercise of
options and other - - 179 18 1,792 - 1,810
Issuance of
preferred stock - - - - - - -
Preferred stock dividends
and amortization of discount - 1,275 - - - (4,762) (3,487)
Net loss for the year (restated) - - - - - (62,346) (62,346)
-------- --------- -------- -------- -------- --------- --------
Balance at
December 31, 1998 (restated) 47 21,946 16,882 1,688 124,679 (79,143) 69,170
Capital stock issued
upon exercise of
options, warrants and other - - 943 94 3,583 - 3,677
Conversion of preferred
stock into common stock - - 99 10 1,765 - 1,775
Preferred stock dividends
and amortization of discount - 1,354 - - - (10,026) (8,672)
Net loss for the year - - - - - (25,331) (25,331)
-------- --------- -------- -------- -------- --------- --------
Balance at
December 31, 1999 47 $ 23,300 17,924 $ 1,792 $130,027 $(114,500) $ 40,619
======== ========= ======== ======== ======== ========= ========
</TABLE>
See notes to consolidated financial statements.
F-6
<PAGE>
PLAINS RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND BASIS OF PRESENTATION
Organization
We are an independent energy company that is engaged in two related lines of
business within the energy sector industry. Our first line of business, which we
refer to as "upstream", acquires, exploits, develops, explores and produces
crude oil and natural gas. Our second line of business, which we refer to as
"midstream", is engaged in the marketing, transportation and terminalling of
crude oil. 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". We conduct this second line of
business through our majority ownership in Plains All American Pipeline, L.P.
("PAA"). Our upstream crude oil and natural gas activities are focused in
California (in the Los Angeles Basin, the Arroyo Grande Field, and the Mt. Poso
Field), offshore California (in the Point Arguello Field), the Sunniland Trend
of South Florida and the Illinois Basin in southern Illinois. Our midstream
activities are concentrated in California, Texas, Oklahoma, Louisiana and the
Gulf of Mexico.
Basis of Consolidation and Presentation
The consolidated financial statements include the accounts of Plains Resources
Inc., our wholly-owned subsidiaries and PAA in which we have an approximate 54%
ownership interest, Plains All American Inc., one of our wholly owned
subsidiaries, serves as PAA's sole general partner. For financial statement
purposes, the assets, liabilities and earnings of PAA are included in our
consolidated financial statements, with the public unitholders' interest
reflected as a minority interest. All significant intercompany transactions have
been eliminated. We have restated 1999 marketing, transportation, storage and
terminalling revenues and expenses to appropriately reflect certain transactions
between the upstream and midstream lines of business. Certain reclassifications
have been made to the prior year statements to conform to the current year
presentation.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 and
(4) accrued liabilities. Although management believes these estimates are
reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand
deposits and funds invested in highly liquid instruments with original
maturities of three months or less.
Inventory. Crude oil inventory is carried at the lower of cost, as adjusted
for deferred hedging gains and losses, or market value using an average cost
method. Materials and supplies inventory is stated at the lower of cost or
market with cost determined on a first-in, first-out method.
Inventory consists of the following:
DECEMBER 31,
---------------------------
1999 1998
------- -------
(IN THOUSANDS)
Crude oil $35,664 $37,702
Materials and supplies 4,814 4,818
------- -------
$40,478 $42,520
======= =======
Oil and Natural 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 unrecovered proved oil and natural gas
F-7
<PAGE>
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 reduced by future operating expenses, development expenditures and
abandonment costs (net of salvage values), and estimated future income taxes
thereon (the "Standardized Measure") (see Note 20).
Crude Oil Pipeline, Gathering and Terminal Assets. Crude oil pipeline,
gathering and terminal assets are recorded at cost. Depreciation is computed
using the straight-line method over estimated useful lives as follows:
. crude oil pipelines - 40 years;
. crude oil pipeline facilities - 25 years;
. crude oil terminal and storage facilities - 30 to 40 years;
. trucking equipment, injection stations and other - 5 to 10 years; and
Acquisitions and improvements are capitalized; maintenance and repairs are
expensed as incurred.
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.
Other Assets. Other assets consist of the following (in thousands):
DECEMBER 31,
-------------------
1999 1998
------- -------
(RESTATED)
Pipeline linefill $ 17,633 $ 54,511
Deferred tax asset (See Note 11) 67,366 46,356
Land 8,853 8,853
Debt issue costs 35,101 18,668
Other 10,965 8,245
-------- --------
139,918 136,633
Accumulated amortization (10,151) (4,987)
-------- --------
$129,767 $131,646
======== ========
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. Debt issue costs at December 31, 1999 include
approximately $13.7 million paid in the fourth quarter of 1999 to amend PAA's
credit facilities as a result of defaults caused by unauthorized trading losses
(see Note 3).
Pipeline Linefill. Pipeline linefill is recorded at cost and consists of crude
oil linefill used to pack a pipeline such that when an incremental barrel enters
a pipeline it forces a barrel out at another location. After the sale of the
linefill discussed below, we own approximately 1.2 million barrels of crude oil
that is used to maintain the vast majority of our minimum operating linefill
requirements. Proceeds from the sale and repurchase of pipeline linefill are
reflected as cash flows from operating activities in the accompanying
consolidated statements of cash flows. Proceeds from the sale of linefill in
connection with the segment of the All American Pipeline that we sold are
included in investing activities in the accompanying consolidated statements of
cash flows (see Note 6).
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.
F-8
<PAGE>
Revenue Recognition. Gathering and marketing revenues are accrued at the time
title to the product sold transfers to the purchaser, which typically occurs
upon receipt of the product by the purchaser, and purchases are accrued at the
time title to the product purchased transfers to us, which typically occurs upon
our receipt of the product. Terminalling and storage revenues are recognized at
the time service is performed. Revenues for the transportation of crude oil are
recognized based upon regulated and non-regulated tariff rates and the related
transported volumes. Crude oil exchanges whereby like volumes are purchased and
sold with the same customers with little effect on gross margin are reflected
net and included in marketing, transportation, storage and terminalling
expenses. We recognize oil and gas revenue from our interests in producing wells
as oil and gas is produced and sold from those wells.
Hedging. We utilize various derivative instruments, for purposes other than
trading, to hedge our exposure to price fluctuations on crude in storage and
expected purchases, sales and transportation of crude oil. The derivative
instruments consist primarily of futures and option contracts traded on the
New York Mercantile Exchange and crude oil swap contracts entered into with
financial institutions. We also utilize interest rate swaps and collars to
manage the interest rate exposure on our long-term debt.
These derivative instruments qualify for hedge accounting as they reduce the
price risk of the underlying hedged item and are designated as a hedge at
inception. Additionally, the derivatives result in financial impacts which are
inversely correlated to those of the items being hedged. This correlation,
generally in excess of 80%, (a measure of hedge effectiveness) is measured both
at the inception of the hedge and on an ongoing basis. If correlation ceases to
exist, we would discontinue hedge accounting and apply mark to market
accounting. Gains and losses on the termination of hedging instruments are
deferred and recognized in income as the impact of the hedged item is recorded.
Unrealized changes in the market value of crude oil hedge contracts are not
generally recognized in our statement of operations until the underlying hedged
transaction occurs. The financial impacts of crude oil hedge contracts are
included in our statements of operations as a component of revenues. Such
financial impacts are offset by gains or losses realized in the physical market.
Cash flows from crude oil hedging activities are included in operating
activities in the accompanying statements of cash flows. Net deferred gains and
losses on futures contracts, including closed futures contracts, entered into to
hedge anticipated crude oil purchases and sales are included in current assets
or current liabilities in the accompanying balance sheets. Deferred gains or
losses from inventory hedges are included as part of the inventory costs and
recognized when the related inventory is sold.
Amounts paid or received from interest rate swaps and collars are charged or
credited to interest expense and matched with the cash flows and interest
expense of the long-term debt being hedged, resulting in an adjustment to the
effective interest rate. Deferred gains of $10.1 million received upon the
termination of an interest rate swap are included in other long-term liabilities
and deferred credits in the accompanying balance sheet at December 31, 1999.
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 exercise price of options equals the
fair value (market price) of the underlying stock on the date of grant.
Sale of Units by a Subsidiary. When a subsidiary 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. When we buy additional units from a subsidiary, resulting in a change in
our percentage ownership interest, the difference between our cost and
underlying equity in investee net assets is assigned first to identifiable
tangible and intangible assets and to liabilities based on their fair values at
the date of the change of interest; any unassigned difference is assigned to
goodwill.
Recent Accounting Pronouncements. In June 1998, the FASB issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities ("SFAS 133"). SFAS 133 requires that all derivative
instruments be recorded on the balance sheet at their fair value. Changes in the
fair value of derivatives are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if so, the type of hedge transaction. For fair value
hedge transactions in which we are hedging changes in an asset's, liability's,
or firm commitment's fair value, changes in the fair value of the derivative
instrument will generally be offset in the income statement by changes in the
hedged item's fair value. For cash flow hedge transactions, in which we are
hedging the variability of cash flows related to a variable-rate asset,
liability, or a forecasted transaction, changes in the fair value of the
derivative instrument will be reported in other comprehensive income. The gains
and losses on the derivative instrument that are reported in other comprehensive
income will be reclassified as earnings in the periods in which earnings are
affected by the variability of the cash flows of the hedged item. This statement
was amended by Statement of Financial Accounting Standards No. 137, Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 defers
the effective date of SFAS 133 to
F-9
<PAGE>
fiscal years beginning after June 15, 2000. We are required to adopt this
statement beginning in 2001. We have not yet determined the effect that the
adoption of SFAS 133 will have on our financial position or results of
operations.
NOTE 3 -- UNAUTHORIZED TRADING LOSSES AND RESTATED FINANCIAL STATEMENTS
In November 1999, we discovered that a former employee of PAA had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated 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. Because the financial statements of PAA are
consolidated with our financial statements, adverse effects on the financial
statements of PAA directly affect our consolidated financial statements. As a
result, we have restated our previously reported 1999 and 1998 results to
reflect the losses incurred from these unauthorized trading activities.
Approximately $7.1 million of the unauthorized trading losses were recognized in
1998 and the remainder in 1999.
Normally, as it purchases crude oil, PAA establishes a margin by selling crude
oil for physical delivery to third-party users or by entering into a future
delivery obligation with respect to futures contracts. The employee in question
violated PAA's policy of maintaining a position that is substantially balanced
between crude oil purchases and sales or future delivery obligations. The
unauthorized trading and associated losses resulted in a default of certain
covenants under PAA's credit facilities and significant short-term cash and
letter of credit requirements.
Although one of our wholly-owned subsidiaries is the general partner of and
owns 54% of PAA, the trading losses do not affect the operations or assets of
our upstream business. The debt of PAA is nonrecourse to us. In addition, our
indirect ownership in PAA does not collateralize any of our credit facilities.
Our $225.0 million credit facility is collateralized by our oil and natural gas
properties.
In December 1999, PAA executed amended credit facilities and obtained default
waivers from all of its lenders. The amended credit facilities:
. waived defaults under covenants contained in the existing credit
facilities;
. increased availability under PAA's letter of credit and borrowing facility
from $175.0 million in November 1999 to $295.0 million in December 1999,
$315.0 million in January 2000, and thereafter decreasing to $239.0 million
in February through April 2000, to $225.0 million in May and June 2000 and
to $200.0 million in July 2000 through July 2001;
. required the lenders' consent prior to the payment of distributions to
unitholders;
. prohibited contango inventory transactions subsequent to January 20, 2000;
and
. increased interest rates and fees under certain of the facilities.
PAA paid approximately $13.7 million to its lenders in connection with the
amended credit facilities. This amount was capitalized as debt issue costs and
will be amortized over the remaining term of the amended facilities. In
connection with the amendments, we loaned approximately $114.0 million to PAA.
This subordinated debt is due not later than November 30, 2005. We financed the
$114.0 million that we loaned PAA with:
. the issuance of a new series of our 10% convertible preferred stock for
proceeds of $50.0 million (see Note 8);
. cash distributions of approximately $9.0 million made in November 1999 to
PAA's general partner; and
. $55.0 million of borrowings under our revolving credit facility.
In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of PAA's suppliers and trading partners reduced or
eliminated the open credit previously extended to PAA. Consequently, the amount
of letters of credit PAA needed to support the level of its crude oil purchases
then in effect increased significantly. In addition, the cost to PAA of
obtaining letters of credit increased under the amended credit facility. In many
instances PAA arranged for letters of credit to secure its obligations to
purchase crude oil from its customers, which increased its letter of credit
costs and decreased its unit margins. In other instances, primarily involving
lower margin wellhead and bulk purchases, certain of its purchase contracts were
terminated.
F-10
<PAGE>
The summarized restated results for the periods ended and financial position
as of March 31, June 30, September 30, 1999 and December 31, 1998 are as
follows (in thousands, except per shared data) (unaudited):
<TABLE>
<CAPTION>
RESTATED
--------------------------------------------------------------------------------
THREE PERIOD ENDED PERIOD ENDED
MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999 YEAR
ENDED ---------------------- ----------------------- ENDED
MARCH 31, THREE SIX THREE NINE DECEMBER 31,
1999 MONTHS MONTHS MONTHS MONTHS 1998
------------ -------- ---------- ---------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
OPERATIONS STATEMENT DATA:
Revenues $476,971 $887,277 $1,364,248 $1,133,519 $2,497,767 $1,294,092
Operating profit (loss) 7,638 17,966 25,604 (21,624) 3,980 144,837
Net income (loss) (5,161) (3,116) (8,277) (20,047) (28,324) (62,346)
Basic and diluted EPS (0.45) (0.33) (0.78) (1.30) (2.09) (3.99)
BALANCE SHEET DATA:
Current assets $193,752 $ 425,119 $ 539,296 $ 179,466
Current liabilities 215,879 474,017 642,767 200,507
Minority interest 166,647 162,276 132,869 172,438
Non-redeemable preferred stock, common stock
and other stockholders' equity 65,908 60,983 46,050 69,170
CASH FLOW DATA:
Net cash provided by operating activities $ 4,017 $ 25,742 $ 7,868 $ -
</TABLE>
The summarized previously reported results for the periods ended and financial
position as of March 31, June 30, September 30, 1999 and December 31, 1998 are
as follows (in thousands, except per share data) (unaudited):
<TABLE>
<CAPTION>
PREVIOUSLY REPORTED
--------------------------------------------------------------------------------
THREE PERIOD ENDED PERIOD ENDED
MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999 YEAR
ENDED ---------------------- ----------------------- ENDED
MARCH 31, THREE SIX THREE NINE DECEMBER 31,
1999 MONTHS MONTHS MONTHS MONTHS 1998
------------ -------- ---------- ---------- -------- ------------
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues $476,971 $887,277 $1,364,248 $1,266,519 $2,630,767 $1,294,092
Operating profit 29,012 39,193 68,205 50,602 118,807 151,937
Net income 2,566 4,565 7,131 7,050 14,181 (58,554)
Basic EPS 0.01 0.12 0.14 0.26 0.40 (3.77)
Diluted EPS 0.01 0.11 0.13 0.24 0.37 (3.77)
BALANCE SHEET DATA:
Current assets $193,921 $ 425,045 $ 539,198 $ 179,466
Current liabilities 194,674 431,342 527,842 193,407
Minority interest 175,756 180,340 179,659 173,461
Non-redeemable preferred stock, common stock
and other stockholders' equity 73,635 76,391 88,555 72,962
CASH FLOW DATA:
Net cash provided by operating activities $ 3,848 $ 25,816 $ 7,966 $ -
</TABLE>
Below is the summarized restated and previously reported results for the three
and nine months ending September 30, 1998.
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 1998 SEPTEMBER 30, 1998
---------------------- ---------------------
PREVIOUSLY PREVIOUSLY
RESTATED REPORTED RESTATED REPORTED
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues $393,719 $393,719 $776,732 $776,732
Operating profit 20,111 27,111 55,968 62,968
Net income (loss) (1,442) 3,625 1,407 6,474
Basis EPS (0.19) 0.11 (0.06) 0.24
Diluted EPS (0.19) 0.10 (0.05) 0.22
</TABLE>
NOTE 4 -- PLAINS ALL AMERICAN PIPELINE, L.P. - FORMATION AND OFFERINGS
Our midstream activities are conducted through PAA. PAA was formed in
September of 1998 to acquire and operate the business and assets of our wholly-
owned midstream subsidiaries.
On November 23, 1998, PAA completed an initial public offering of 13,085,000
common units at $20.00 per unit, representing limited partner interests and
received proceeds of approximately $244.7 million. Concurrently with the closing
F-11
<PAGE>
of the initial public offering, we were merged with certain of our midstream
subsidiaries, and then sold the assets of these subsidiaries to PAA in exchange
for $64.1 million and the assumption of $11.0 million of related indebtedness.
At the same time, the general partner conveyed all of its interest in the All
American Pipeline and the SJV Gathering System to PAA in exchange for:
. 6,974,239 common units, 10,029,619 subordinated units and an aggregate 2%
general partner interest;
. the right to receive incentive distributions as defined in the partnership
agreement; and
. PAA's assumption of $175.0 million of indebtedness incurred by the general
partner in connection with the acquisition of the All American Pipeline
and the SJV Gathering System.
In addition to the $64.1 million paid to us, PAA distributed approximately
$177.6 million to the general partner and used approximately $3.0 million of the
remaining proceeds to pay expenses incurred in connection with the offering. The
general partner used $121.0 million of the cash distributed to it to retire the
remaining indebtedness incurred in connection with the acquisition of the All
American Pipeline and the SJV Gathering System and to pay other costs associated
with the transactions. The general partner distributed the remaining $56.6
million to us, which we used to repay indebtedness and for other general
corporate purposes.
During 1998, we recognized a pre-tax gain of approximately $60.8 million
(approximately $37.1 million after-tax) in connection with the formation of PAA.
The gain is the result of an increase in the book value of our equity in PAA to
reflect our proportionate share of the underlying net assets of PAA due to the
sale of units in the initial public offering. The formation related expenses
consist primarily of amounts due to certain key employees in connection with the
successful formation of PAA, debt prepayment penalties and legal fees.
In May 1999, PAA sold to the general partner 1.3 million Class B common units
of PAA for a total cash consideration of $25.0 million, or $19.25 per unit, the
price equal to the market value of PAA's common units on May 12, 1999, in
connection with the Scurlock acquisition (see Note 6).
In October 1999, PAA completed a public offering of an additional 2,990,000
common units representing limited partner interests, at $18.00 per unit. Net
proceeds to PAA from the offering, including our general partner contribution of
$0.5 million, were approximately $51.3 million after deducting underwriters'
discounts and commissions and offering expenses of approximately $3.1 million.
These proceeds were used to reduce outstanding debt. We recognized a pre-tax
gain of $9.8 million ($6.0 million after-tax) in connection with the offering as
a result of an increase in the book value of our equity in PAA, as discussed
above. We held approximate interests of 59% and 54% before and after PAA's
secondary offering, respectively.
NOTE 5 -- UPSTREAM ACQUISITIONS AND DISPOSITIONS
On July 1, 1999, Arguello Inc., our wholly owned subsidiary, acquired
Chevron's interests in Point Arguello. The interests acquired include Chevron's
26% working interest in the Point Arguello Unit, its 26% interest in various
partnerships owning the associated transportation, processing and marketing
infrastructure, and Chevron's right to participate in surrounding leases and
certain fee acreage onshore. We assumed its 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. 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. Arguello Inc. is the operator of record for the Point Arguello Unit
and has entered into an outsourcing agreement with a unit of Torch Energy
Advisors, Inc. for the conduct of certain field operations and other
professional services.
During 1998, we acquired the Mt. Poso field from Aera Energy LLC for
approximately $7.7 million. The field is located approximately 27 miles north of
Bakersfield, California, in Kern County. The field added approximately 8 million
barrels of oil equivalent to our proved reserves at the acquisition date.
In March 1997, we completed the acquisition of Chevron's interest in the
Montebello field for $25.0 million, effective February 1, 1997. The assets
acquired consist of a 100% working interest and a 99.2% net revenue interest in
55 producing oil wells and related facilities and also include approximately 450
acres of surface fee land. At the acquisition date, the Montebello Field, which
is located approximately 15 miles from our existing California operations, was
producing approximately 800 barrels of crude oil and 800 Mcf of natural gas per
day and added approximately 23 million barrels of oil equivalent to our proved
reserves. The acquisition was funded with proceeds from our revolving credit
facility.
In November 1997, we acquired a 100% working interest and a 97% net revenue
interest in the Arroyo Grande Field in San Luis Obispo County, California, from
subsidiaries of Shell Oil Company ("Shell"). The assets acquired include surface
F-12
<PAGE>
and development rights to approximately 1,000 acres included in the 1,500 acre
unit. At the acquisition date, the Arroyo Grande Field was producing
approximately 1,600 barrels of 14 degrees API gravity crude oil per day from 70
wells and added approximately 20 million barrels of oil equivalent to our proved
reserves.
The aggregate purchase price of $22.1 million for the Arroyo Grande field
consisted of rights to a non-producing property interest conveyed to Shell, the
issuance of 46,600 shares of Series D Preferred Stock with an aggregate stated
value of $23.3 million and a 5-year warrant to purchase 150,000 shares of Common
Stock at $25.00 per share. No proved reserves had been assigned to the rights to
the property interest conveyed.
During 1997, we sold certain non-strategic crude oil and natural gas
properties located primarily in Louisiana for net proceeds of approximately $2.7
million.
NOTE 6 -- MIDSTREAM ACQUISITIONS AND DISPOSITIONS
Scurlock Acquisition
On May 12, 1999, PAA completed the acquisition of Scurlock Permian LLC 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.
Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum,
is engaged in crude oil transportation, gathering and marketing, and owns
approximately 2,300 miles of active pipelines, numerous storage terminals and a
fleet of more than 250 trucks. Its largest asset is an 800-mile pipeline and
gathering system located in the Spraberry Trend in West Texas that extends into
Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets
we acquired also included approximately one million barrels of crude oil
pipeline linefill.
Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under Plains Scurlock's limited
recourse bank facility with BankBoston, N.A.;
. 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
. 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 purchase price allocation was based on preliminary estimates of fair value
and is subject to adjustment as additional information becomes available and is
evaluated. The purchase accounting entries include a $1.0 million accrual for
estimated environmental remediation costs. Under the agreement for the sale of
Scurlock by Marathon Ashland Petroleum to Plains Scurlock, Marathon Ashland
Petroleum has agreed to indemnify and hold harmless Scurlock and Plains Scurlock
for claims, liabilities and losses resulting from any act or omission
attributable to Scurlock's business or properties occurring prior to the date of
the closing of such sale to the extent the aggregate amount of such losses
exceed $1.0 million; provided, however, that claims for such losses must
individually exceed $25,000 and must be asserted by Scurlock against Marathon
Ashland Petroleum on or before May 15, 2003.
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-13
<PAGE>
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 as if the Scurlock
acquisition, which was effective May 1, 1999, had occurred on January 1, 1998
(in thousands, except per share data):
YEAR ENDED DECEMBER 31,
----------------------
1999 1998
--------- ----------
(RESTATED)
Revenues $5,153,046 $2,529,558
========== ==========
Net loss $ (27,147) $ (69,682)
========== ==========
Net loss per share available
to common stockholders:
Basic and diluted $ (2.15) $ (4.43)
========== ==========
West Texas Gathering System Acquisition
On July 15, 1999, Plains Scurlock Permian, L.P. completed the acquisition of a
West Texas crude oil pipeline and gathering system from Chevron Pipe Line
Company for approximately $36.0 million, including transaction costs. Our total
acquisition cost was approximately $38.9 million including costs to address
certain issues identified in the due diligence process. The principal assets
acquired include approximately 450 miles of crude oil transmission mainlines,
approximately 400 miles of associated gathering and lateral lines and
approximately 2.9 million barrels of crude oil storage and terminalling capacity
in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for
the amounts paid at closing was provided by a draw under the term loan portion
of the Plains Scurlock credit facility.
Venice Terminal Acquisition
On September 3, 1999, PAA completed the acquisition of a Louisiana crude oil
terminal facility and associated pipeline system from Marathon Ashland Petroleum
LLC for approximately $1.5 million. The principal assets acquired include
approximately 300,000 barrels of crude oil storage and terminalling capacity and
a six-mile crude oil transmission system near Venice, Louisiana.
All American Pipeline Acquisition
On July 30, 1998, Plains All American Inc., acquired all of the outstanding
capital stock of the All American Pipeline Company, Celeron Gathering
Corporation and Celeron Trading & Transportation Company (collectively the
"Celeron Companies") from Wingfoot, a wholly-owned subsidiary of the Goodyear
Tire and Rubber Company ("Goodyear") for approximately $400.0 million, including
transaction costs. The principal assets of the entities acquired include the All
American Pipeline and the SJV Gathering System, as well as other assets related
to such operations. The acquisition was accounted for utilizing the purchase
method of accounting with the assets, liabilities and results of operations
included in our consolidated financial statements effective July 30, 1998.
The acquisition was accounted for utilizing the purchase method of accounting
and the purchase price was allocated in accordance with APB 16 as follows (in
thousands):
<TABLE>
<CAPTION>
<S> <C>
Crude oil pipeline, gathering and terminal assets $392,528
Other assets (debt issue costs) 6,138
Net working capital items (excluding cash received of $7,481) 1,498
--------
Cash paid $400,164
========
</TABLE>
Financing for the acquisition was provided through a $325.0 million, limited
recourse bank facility and an approximate $114.0 million capital contribution by
us. Actual borrowings at closing were $300.0 million.
All American Pipeline Linefill Sale and Asset Disposition
We initiated the sale of approximately 5.2 million barrels of crude oil
linefill from the All American Pipeline in November 1999. This sale was
substantially completed in February 2000. The linefill was located in the
segment of the All American Pipeline that extends from Emidio, California, to
McCamey, Texas. Except for minor third party volumes, Plains Marketing, L.P.,
one of
F-14
<PAGE>
PAA's subsidiaries has been the sole shipper on this segment of the pipeline
since its predecessor acquired the line from Goodyear in July 1998. Proceeds
from the sale of the linefill were approximately $100.0 million, net of
associated costs, and were used for working capital purposes. We estimate that
we will recognize a total gain of approximately $44.6 million in connection with
the sale of linefill. As of December 31, 1999, we had delivered approximately
1.8 million barrels of linefill and recognized a gain of $16.5 million. The
amount of crude oil linefill for sale at December 31, 1999 was $37.9 million and
is included in assets held for sale on the consolidated balance sheet.
On March 24, 2000, we completed the sale of the above referenced segment of
the All American Pipeline to a unit of El Paso Energy Corporation for total
proceeds of $129.0 million. The proceeds from the sale were used to reduce PAA's
outstanding debt. Our net proceeds are expected to be approximately $124.0
million, net of associated transaction costs and estimated costs to remove
certain equipment. We estimate that we will recognize a gain of approximately
$20.0 million in connection with the sale. During 1999, we reported gross margin
of approximately $5.0 million from volumes transported on the segment of the
line that was sold. The cost of the pipeline segment is included in assets held
for sale on the consolidated balance sheet at December 31, 1999.
NOTE 7 -- LONG-TERM DEBT AND CREDIT FACILITIES
Short-term debt and current portion of long-term debt consists of the
following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1999 1998
--------- --------
<S> <C> <C>
PAA letter of credit and borrowing facility, bearing interest at
weighted average interest rates of 8.7% and 6.8%
at December 31, 1999 and 1998, respectively $ 13,719 $ 9,750
PAA secured term credit facility, bearing interest at
a weighted average interest rate of 8.8%
at December 31, 1999 45,000 -
--------- --------
58,719 9,750
Current portion of long-term debt 51,161 511
--------- --------
$ 109,880 $ 10,261
========= ========
</TABLE>
Long-term debt consists of the following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1999 1998
--------- --------
<S> <C> <C>
Revolving credit facility, bearing interest at 7.6%
and 6.9%, at December 31, 1999 and 1998, respectively $137,300 $ 52,000
PAA bank credit agreement, bearing interest at 8.3%
and 6.8% at December 31, 1999 and 1998, respectively 225,000 175,000
Plains Scurlock bank credit agreement, bearing interest
at 9.1% at December 31, 1999 85,100 -
10.25% Senior Subordinated Notes, due 2006, net of
unamortized premium of $2.9 million and $2.4 million
at December 31, 1999 and 1998, respectively 277,909 202,427
Other long-term debt 2,555 3,067
--------- --------
Total long-term debt 727,864 432,494
Less current maturities (51,161) (511)
--------- --------
$ 676,703 $431,983
========= ========
</TABLE>
PLAINS RESOURCES 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 upstream subsidiaries. The
borrowing base under the revolving credit facility at December 31, 1999, 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
F-15
<PAGE>
time by the performance of our crude oil and natural gas properties and changes
in crude oil and natural gas prices. We incur a commintment fee of 3/8% per
annum on the unused portion of the borrowing base. The revolving credit
facility, as amended, matures on July 1, 2001, at which time the remaining
outstanding balance converts to a term loan which is repayable in sixteen equal
quarterly installments commencing October 1, 2001, 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 Base Rate (as defined therein). At December 31, 1999,
letters of credit of $0.6 million and borrowings of approximately $137.3 million
were outstanding under the revolving credit facility.
The revolving credit facility contains covenants which, among other things,
restrict the payment of cash dividends, 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.
10.25% Senior Subordinated Notes Due 2006
We have $275 million principal amount of 10.25% Senior Subordinated Notes Due
2006 outstanding which bear a coupon rate of 10.25% which at December 31, 1999
consists of (in thousands):
Series A $ 500
Series B 149,500
Series C 50
Series D 49,950
Series E 75,000
--------
$275,000
========
The Series A & B 10.25% Notes were issued in 1996 at 99.38% of par to yield
10.35%. The Series C & D 10.25% Notes were issued in 1997 at approximately 107%
of par. Proceeds from the sale of the Series C & D 10.25% Notes, net of offering
costs, were approximately $53.0 million and were used to reduce the balance on
our revolving credit facility.
The Series E 10.25% Notes were issued in September 1999 pursuant to a Rule
144A private placement at approximately 101% of par. Proceeds from the sale of
the Series E 10.25% Notes, net of offering costs, were approximately $74.6
million and were used to reduce the balance on our revolving credit
facility.
In connection with the sale of the Series E Notes, we agreed to offer to
exchange 10.25% Senior Subordinated Notes due 2006, Series F for all of the
Series E Notes. The Series F Notes will be substantially identical (including
principal amount, interest rate, maturity and redemption rights) to the Series E
Notes except for certain transfer restrictions relating to the Series E Notes.
We also agreed to file a registration statement with the SEC with respect to
this exchange offer and to use our best efforts to cause such registration
statement to be declared effective by January 20, 2000. If such registration
statement is not declared effective by such date, with respect to the first 90-
day period thereafter, the interest rate on the Series E Notes increases by
0.50% per annum and will increase by an additional 0.50% per annum with respect
to each subsequent 90-day period until the registration statement has been
declared effective, up to a maximum increase of 2% per annum. While the
registration statement has been filed, we will not request the SEC to declare it
effective until after the filing of our 1999 Form 10-K. As a result, the
interest rate on the Series E Notes has increased to 10.75% for the 90-day
period following January 20, 2000. At such time as the registration statement is
declared effective by the SEC, the interest rate will revert to 10.25% per
annum.
The 10.25% Notes are redeemable, at our option, on or after March 15, 2001 at
105.13% of the principal amount thereof, at decreasing prices thereafter prior
to March 15, 2004, and thereafter at 100% of the principal amount thereof 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.
F-16
<PAGE>
The Series A-E Notes are unsecured general obligations and are subordinated in
right of payment to all our existing and future senior indebtedness and are
guaranteed by all of our upstream subsidiaries on a full, unconditional, joint
and several basis. The Series A-E Notes are not guaranteed by PAA or any of our
other midstream subsidiaries.
PLAINS ALL AMERICAN PIPELINE L.P. CREDIT FACILITIES
The discussion below relates to credit facilities of PAA, which are
nonrecourse to us, but are included in our consolidated financial statements. In
addition, our indirect ownership in PAA does not collateralize any of our credit
facilities.
PAA has a letter of credit and borrowing facility, the purpose of which is to
provide standby letters of credit to support the purchase and exchange of crude
oil for resale and borrowings primarily to finance crude oil inventory which has
been hedged against future price risk or designated as working inventory. As a
result of the unauthorized trading losses discovered in November 1999, the
facility was in default of certain covenants, with those defaults being
subsequently waived and the facility amended in December. As amended, the letter
of credit facility has a sublimit for cash borrowings of $40.0 million at
December 31, 1999, with decreasing amounts thereafter through April 30, 2000, at
which time the sublimit is eliminated. The letter of credit and borrowing
facility provides for an aggregate letter of credit availability of $295.0
million in December 1999, $315.0 million in January 2000, and thereafter
decreasing to $239.0 million in February through April 2000, to $225.0 million
in May and June 2000, and to $200.0 million in July 2000 through July 2001.
Aggregate availability under the letter of credit facility for direct borrowings
and letters of credit is limited to a borrowing base which is determined monthly
based on certain of PAA's current assets and current liabilities, primarily
accounts receivable and accounts payable related to the purchase and sale of
crude oil. This facility is secured by a lien on substantially all of PAA's
assets except the assets which secure the Plains Scurlock credit facility. At
December 31, 1999, there were letters of credit of approximately $292.0 million
and borrowings of $13.7 million outstanding under this facility.
On December 30, 1999, PAA entered into a $65.0 million senior secured term
credit facility to fund short-term working capital requirements resulting from
the unauthorized trading losses. The facility was secured by a portion of the
5.2 million barrels of linefill that was sold and receivables from certain sales
contracts applicable to the linefill. The facility had a maturity date of March
24, 2000 and was repaid with the proceeds from the sale of the linefill securing
the facility. At December 31, 1999, there were borrowings of $45.0 million
outstanding.
Concurrently with the closing of PAA's initial public offering in November
1998, PAA entered into a $225.0 million bank credit agreement that includes a
$175.0 million term loan facility and a $50.0 million revolving credit facility.
As a result of the unauthorized trading losses discovered in November 1999, the
facility was in default of certain covenants, with those defaults being
subsequently waived and the facility amended in December. The bank credit
agreement is secured by a lien on substantially all of PAA's assets except the
assets which secure the Plains Scurlock credit facility. PAA may borrow up to
$50.0 million under the revolving credit facility for acquisitions, capital
improvements, working capital and general business purposes. At December 31,
1999, PAA had $175.0 million outstanding under the term loan facility, and $50.0
million outstanding under the revolving credit facility. The term loan facility
matures in 2005, and no principal is scheduled for payment prior to maturity.
The term loan facility may be prepaid at any time without penalty. The revolving
credit facility expires in November 2000. The term loan and revolving credit
facility bear interest at PAA's option at either the base rate, as defined, plus
an applicable margin, or reserve adjusted LIBOR plus an applicable margin. PAA
incurs a commitment fee on the unused portion of the revolving credit facility.
Plains Scurlock, an operating partnership which is a subsidiary of PAA, has a
bank credit agreement which consists of a five-year $82.6 million term loan
facility and a three-year $35.0 million revolving credit facility. The Plains
Scurlock bank credit agreement is nonrecourse to PAA, Plains Marketing, L.P. and
All American Pipeline, L.P. and is secured by substantially all of the assets of
Plains Scurlock Permian, L.P. and its subsidiaries, including the Scurlock
assets and the West Texas gathering system. Borrowings under the term loan and
under the revolving credit facility bear interest at LIBOR plus the applicable
margin. A commitment fee equal to 0.5% per year is charged on the unused portion
of the revolving credit facility. The revolving credit facility, which may be
used for borrowings or letters of credit to support crude oil purchases, matures
in May 2002. The term loan provides for principal amortization of $0.7 million
annually beginning May 2000, with a final maturity in May 2004. As of December
31, 1999, letters of credit of approximately $29.5 million were outstanding
under the revolver and borrowings of $82.6 million and $2.5 million were
outstanding under the term loan and revolver, respectively. The term loan was
reduced to $82.6 million from $126.6 million with proceeds from PAA's October
1999 public offering.
F-17
<PAGE>
All of PAA's credit facilities contain prohibitions on distributions on, or
purchases or redemptions of, units if any default or event of default is
continuing. In addition, PAA's facilities contain various covenants limiting its
ability to:
. incur indebtedness;
. grant liens;
. sell assets in excess of certain limitations;
. engage in transactions with affiliates;
. make investments;
. enter into hedging contracts; and
. enter into a merger, consolidation or sale of assets.
Each of PAA's facilities treats a change of control as an event of default. In
addition, the terms of PAA's letter of credit and borrowing facility and its
bank credit agreement require lenders' consent prior to the payment of
distributions to unitholders and require it to maintain:
. a current ratio of 1.0 to 1.0, as defined in PAA's credit agreement;
. a debt coverage ratio which is not greater than 5.0 to 1.0;
. an interest coverage ratio which is not less than 3.0 to 1.0;
. a fixed charge coverage ratio which is not less than 1.25 to 1.0; and
. a debt to capital ratio of not greater than 0.60 to 1.0.
The terms of the Plains Scurlock bank credit agreement require Plains Scurlock
to maintain at the end of each quarter:
. a debt coverage ratio of 6.0 to 1.0 from October 1, 1999 through June 30,
2000; 5.0 to 1.0 from July 1, 2000 through June 30, 2001; and 4.0 to 1.0
thereafter; and
. an interest coverage ratio of 2.0 to 1.0 from October 1, 1999 through
June 30, 2000 and 2.5 to 1.0 thereafter.
In addition, the Plains Scurlock bank credit agreement contains limitations on
the Plains Scurlock operating partnership's ability to make distributions to PAA
if its indebtedness and current liabilities exceed certain levels as well as the
amount of expansion capital it may expend.
Maturities
The aggregate amount of maturities of all long-term indebtedness for the next
five years is: 2000 - $51.1 million, 2001 - $9.7 million, 2002 - $38.0 million,
2003 - $35.5 million and 2004 - $114.8 million.
NOTE 8 - REDEEMABLE PREFERRED STOCK
Liquidation Preference
All series of our cumulative convertible preferred stock are stated at
liquidation preference on the consolidated balance sheet. Liquidation preference
represents the number of shares outstanding, which includes cumulative noncash
dividends, 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. We have no current intention of redeeming the
cumulative preferred stock before its mandatory redemption date. However, we
review our capital structure regularly and may redeem shares of our preferred
stock if future conditions warrant.
Series E and Series G Cumulative Convertible Preferred Stock
On July 29, 1998, we sold in a private placement 170,000 shares of our Series
E Cumulative Convertible Preferred Stock (the "Series E Preferred Stock") for
$85.0 million. Each share of the Series E Preferred Stock has a stated value of
$500 per share and bears a dividend of 9.5% per annum. Dividends are payable
semi-annually in either cash or additional shares of Series E Preferred Stock at
our option and are cumulative from the date of issue. Each share of Series E
Preferred Stock is convertible into 27.78 shares of common stock (an initial
effective conversion price of $18.00 per share) and in certain circumstances may
be converted at our option into common stock if the average trading price for
any thirty-day trading period is equal to or greater than $21.60 per share. The
Series E Preferred Stock is redeemable at our option at 105% of stated value
through December 31, 2003 and at par thereafter. If not previously redeemed or
converted, the Series E Preferred Stock is required to be redeemed in 2012.
Proceeds from the Series E preferred Stock were used to fund a portion of our
capital contribution to Plains All American Inc. to acquire the Celeron
Companies (see Note 6). At December 31, 1999, these were 177,626 shares
outstanding.
On April 1, 1999, we paid a dividend on the Series E Preferred Stock for the
period from October 1, 1998 through March 31, 1999. The dividend amount of
approximately $4.1 million was paid by issuing 8,209 additional shares of the
Series E Preferred Stock. On September 9, 1999, 3,408 shares of Series E
Preferred Stock, including accrued dividends, were converted into 98,613 shares
of common stock at a conversion price of $18.00 per share. On October 1, 1999,
we paid a cash dividend of approximately $4.2 million on the Series E Preferred
Stock for the period April 1, 1999 through September 30, 1999.
F-18
<PAGE>
In connection with the sale of the Series F Preferred Stock described below,
we agreed with the purchasers of the Series F Preferred Stock (who were also
holders of the Series E Preferred Stock), to reduce the conversion price of the
Series E Preferred Stock from $18.00 to $15.00. This reduction of the conversion
price of the Series E Preferred Stock was effected through an exchange of each
outstanding share of Series E Preferred Stock for a share of a new Series G
Preferred Stock. Other than the reduction of the conversion price, the terms of
the Series G Preferred Stock are substantially identical to those of the Series
E Preferred Stock.
On March 22, 2000, our Board of Directors declared a cash dividend on our
Series G Preferred Stock, which is payable on April 3, 2000 to holders of record
on March 23, 2000. The dividend amount of $4,219,000 is for the period of
October 1, 1999 through March 31, 2000.
Series F Cumulative Convertible Preferred Stock
On December 14, 1999, we sold in a private placement 50,000 shares of our
Series F Cumulative Convertible Preferred Stock (the "Series F Preferred Stock")
for $50.0 million. Each share of the Series F Preferred Stock has a stated value
of $1,000 per share and bears a dividend of 10% per annum. Dividends are payable
semi-annually in either cash or additional shares of Series F Preferred Stock at
our option and are cumulative from the date of issue. Dividends paid in
additional shares of Series F Preferred Stock are limited to an aggregate of six
dividend periods. Each share of Series F Preferred Stock is convertible into
81.63 shares of common stock (an initial effective conversion price of $12.25
per share) and in certain circumstances may be converted at our option into
common stock if the average trading price for any sixty-day trading period is
equal to or greater than $21.60 per share. After December 15, 2003, the Series F
Preferred Stock is redeemable at our option at 110% of stated value through
December 15, 2004 and at declining amounts thereafter. If not previously
redeemed or converted, the Series F Preferred Stock is required to be redeemed
in 2007. At December 31, 1999, there were 50,000 shares outstanding.
Proceeds from the Series F Preferred Stock were advanced to PAA in connection
with the unauthorized trading losses through the issuance of $114.0 million of
subordinated debt, due not later than November 30, 2005 (see Note 3). On March
22, our Board of Directors declared a cash dividend on our Series F Preferred
Stock, which is payable on April 3, 2000 to holders of record on March 23, 2000.
The dividend amount of approximately $1.5 million is for the period December 15,
1999 (the date of original issuance) through March 31, 2000.
NOTE 9 -- CAPITAL STOCK
Common and Preferred Stock
We have authorized capital stock consisting of 50 million shares of common
stock, $0.10 par value, and 2 million shares of preferred stock, $1.00 par
value. At December 31, 1999, there were 17.9 million shares of common stock
issued and outstanding and 274,226 shares of preferred stock outstanding.
Stock Warrants and Options
At December 31, 1999, we had warrants outstanding which entitle the holders
thereof to purchase an aggregate 251,350 shares of common stock. Per share
exercise prices and expiration dates for the warrants are as follows: 101,350
shares at $7.50 expiring in 2000 and 150,000 shares at $25.00 expiring in 2002.
We have various stock option plans for our employees and directors (see Note
15).
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 was
initially recorded at $20.5 million, a discount of $2.8 million from the stated
value of $23.3 million. Commencing January 1, 2000, the Series D Preferred Stock
will bear an annual dividend of $30.00 per share. Prior to this date, no
dividends were accrued and the discount was amortized to retained earnings
through December 31, 1999.
On March 22, 2000, our Board of Directors declared a cash dividend on our
Series D Preferred stock, which is payable on April 3, 2000 to holders of record
on March 23, 2000. The dividend amount of $350,000 is for the period January 1,
2000 through March 31, 2000.
F-19
<PAGE>
NOTE 10 -- 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 item for the years ended December 31,
1999, 1998 and 1997 (in thousands, except per share amounts):
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------------------------------
1999 1998 (RESTATED) 1997
---------------------------------- ------------------------------- ------------------------------
INCOME SHARES PER INCOME SHARES PER INCOME SHARES PER
(NUMERA- (DENOMI- SHARE (NUMERA- (DENOMI- SHARE (NUMERA- (DENOMI- SHARE
TOR) NATOR) AMOUNT TOR) NATOR) AMOUNT TOR) NATOR) AMOUNT
------------- --------- -------- --------- --------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Income (loss) before
extraordinary item $(24,787) $(62,346) $14,259
Less: preferred
stock dividends (10,026) (4,762) (163)
-------- -------- -------
Income (loss)
available
to common
stockholders (34,813) 17,262 $(2.02) (67,108) 16,816 $(3.99) 14,096 16,603 $0.85
====== ====== =====
Effect of dilutive
securities:
Employee stock
options - - - - - 1,085
Warrants - - - - - 516
--------- ------ -------- ------ ------- ------
Income (loss)
available
to common
stockholders
assuming
dilution $(34,813) 17,262 $(2.02) $(67,108) 16,816 $(3.99) $14,096 18,204 $0.77
======== ====== ====== ======== ====== ====== ======= ====== =====
</TABLE>
In 1999 and 1998, we recorded net losses and our options and warrants were
not included in the computations of diluted earnings per share because their
assumed conversion was antidilutive. In 1997 certain options and warrants to
purchase shares of our common stock were not included in the computations of
diluted earnings per share because the exercise prices were greater than the
average market price of the common stock during the period of the calculations,
resulting in antidilution. In addition, our preferred stock is convertible into
common stock but was not included in the computation of diluted earnings per
share in 1999, 1998 and 1997 because the effect was antidilutive. See Notes 9
and 15 for additional information concerning outstanding options and warrants.
F-20
<PAGE>
NOTE 11 -- INCOME TAXES
Our deferred income tax assets and liabilities at December 31, 1999 and 1998,
consist of the tax effect of income tax carryforwards and differences related to
the timing of recognition of certain types of costs incurred in both our
upstream and midstream activities as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------
1999 1998
---------------- ----------------
(restated)
<S> <C> <C>
U.S. Federal
------------
Deferred tax assets:
Net operating losses $ 80,267 $48,911
Percentage depletion 2,450 2,450
Tax credit carryforwards 1,780 1,614
Excess outside tax basis over outside book basis 15,377 10,556
Other 627 1,268
-------- -------
100,501 64,799
Deferred tax liabilities:
Net oil & gas acquisition, exploration and
development costs (28,788) (12,186)
-------- -------
Net deferred tax asset 71,713 52,613
Valuation allowance (2,555) (2,786)
-------- -------
69,158 49,827
-------- -------
States
------
Deferred tax liability (1,792) (3,471)
-------- -------
Net deferred tax assets $ 67,366 $46,356
======== =======
</TABLE>
At December 31, 1999, we have a net deferred tax asset of $69.0 million,
primarily attributable to net operating loss ("NOL") carryforwards. The minimum
amount of future taxable income necessary to utilize the NOL carryforwards is
$229.3 million. Based on current levels of pre-tax income, excluding
nonrecurring items, management believes that it is more likely than not that we
will generate taxable income from operations sufficient to realize the deferred
tax asset.
At December 31, 1999, we have carryforwards of approximately $229.3 million
of regular tax NOLs, $7.0 million of statutory depletion, $1.4 million of
alternative minimum tax credits and $0.3 million of enhanced oil recovery
credits. At December 31, 1999, we had approximately $209.8 million of
alternative minimum tax NOL carryforwards available as a deduction against
future alternative minimum tax income. The NOL carryforwards expire from 2005
through 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 per the accompanying Consolidated
Statements of Operations (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1999 1998 1997
---------------- ---------------- ----------------
(restated)
<S> <C> <C> <C>
U.S. federal income tax provision at statutory rate $(15,842) $(37,573) $7,905
State income taxes (1,298) (5,252) 376
Valuation allowance adjustment - (4,987) -
Full cost ceiling test limitation (3,617) 2,903 -
Other 278 (96) 46
-------- -------- ------
Income tax (benefit) on income before extraordinary item (20,479) (45,005) 8,327
Income tax benefit allocated to extraordinary item (293) - -
-------- -------- ------
Income tax (benefit) provision $(20,772) $(45,005) $8,327
======== ======== ======
</TABLE>
F-21
<PAGE>
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, 1999.
NOTE 12 -- EXTRAORDINARY ITEM
For the year ended December 31, 1999, we recognized a $1.5 million
extraordinary loss ($0.5 million net of minority interest of $0.7 million and
deferred tax benefit of $0.3 million) related to the early extinguishment of
debt. The loss is related to the reduction of the Plains Scurlock term loan
facility with proceeds from PAA's 1999 public offering and the restructuring of
PAA's letter of credit and borrowing facility as a result of the unauthorized
trading losses (see Note 3 and 7).
NOTE 13 -- RELATED PARTY TRANSACTIONS
Reimbursement of Expenses of the General Partner and Its Affiliates
As the general partner for PAA, we have sole responsibility for conducting
its business and managing its operations and we own all of the incentive
distribution rights. Some of our senior executives who currently operate our
business also manage the business of PAA. We do not receive any management fee
or other compensation in connection with the management of their business, but
we are reimbursed for all direct and indirect expenses incurred on their behalf.
For the years ended December 31, 1999 and 1998, we were reimbursed approximately
$44.7 million and $0.5 million, respectively, for direct and indirect expenses
on their behalf. The reimbursed costs consist primarily of employee salaries and
benefits. PAA does not employ any persons to manage its business. These
functions are provided by the employees of the general partner and us.
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 they charge a
fee of $0.20 per barrel. For the year ended December 31, 1999 and the period
from November 23, 1998 to December 31, 1998, we were paid approximately $131.5
million and $4.1 million, respectively, for the purchase of crude oil under the
agreement. Prior to the marketing agreement, PAA's predecessor marketed our
crude oil production and that of our subsidiaries and our royalty owners. We
were paid approximately $83.4 million and $101.2 million for the purchase of
these products for the period from January 1, 1998 to November 22, 1998 and the
year ended December 31, 1997, respectively. In management's opinion, such
purchases were made at prevailing market prices. PAA's predecessor did not
recognize a profit on the sale of the crude oil purchased from us.
Financing
In December 1999, we loaned to PAA $114.0 million. This subordinated debt is
due not later than November 30, 2005 (see Note 3).
To finance a portion of the purchase price of the Scurlock acquisition, we
purchased 1.3 million Class B common units from PAA at $19.125 per unit, the
market value of the common units on May 12, 1999 (see Note 6).
Long-Term Incentive Plans
We have adopted the Plains All American Inc. 1998 Long-Term Incentive Plan
for employees and directors of the general partner and its affiliates who
perform services for PAA. The Long-Term Incentive Plan consists of two
components, a restricted unit plan and a unit option plan. The Long-Term
Incentive Plan currently permits the grant of restricted units and unit options
covering an aggregate of 975,000 common units. The plan is administered by the
Compensation Committee of the general partner's board of directors.
Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the
grantee to receive a common unit upon the vesting of the phantom unit. As of
March 15, 2000, an aggregate of approximately 500,000 restricted units have been
authorized for grants to employees of the general partner, 170,000 of which have
been granted with the remaining 330,000 to be granted in the near future. The
Compensation Committee may, in the future, make additional grants under the plan
to employees and directors containing such terms as the Compensation Committee
shall determine. In general, restricted units granted to employees during the
subordination period will vest only upon, and in the same proportions as, the
conversion of
F-22
<PAGE>
the subordinated units to common units. Grants made to non-employee directors of
the general partner will be eligible to vest prior to termination of the
subordination period.
Unit Option Plan. The Unit Option Plan currently permits the grant of options
covering common units. No grants have been made under the Unit Option Plan to
date. However, the Compensation Committee may, in the future, make grants under
the plan to employees and directors containing such terms as the committee shall
determine, provided that unit options have an exercise price equal to the fair
market value of the units on the date of grant. Unit options granted during the
subordination period will become exercisable automatically upon, and in the same
proportions as, the conversion of the subordinated units to common units, unless
a later vesting date is provided.
Transaction Grant Agreements In addition to the grants made under the
Restricted Unit Plan described above, the general partner, at no cost to PAA,
agreed to transfer approximately 400,000 of its affiliates' common units
(including distribution equivalent rights attributable to such units) to certain
key employees of the general partner. A grant covering 50,000 of such common
units was terminated in 1999. Generally, approximately 69,444 of the remaining
common units vest in each of the years ending December 31, 1999, 2000 and 2001
if the operating surplus generated in such year equals or exceeds the amount
necessary to pay the minimum quarterly distribution on all outstanding common
units and the related distribution on the general partner interest. If a tranche
of common units does not vest in a particular year, such common units will vest
at the time the common unit arrearages for such year have been paid. In
addition, approximately 47,224 of the remaining common units vest in each of the
years ending December 31, 1999, 2000 and 2001 if the operating surplus generated
in such year exceeds the amount necessary to pay the minimum quarterly
distribution on all outstanding common units and subordinated units and the
related distribution on the general partner interest. In 1999, approximately
69,444 of such common units vested and 47,224 of such common units remain
unvested as no distribution on the subordinated units was made for the fourth
quarter of 1999. Any common units remaining unvested shall vest upon, and in the
same proportion as, the conversion of subordinated units to common units.
Distribution equivalent rights are paid in cash at the time of the vesting of
the associated common units. Notwithstanding the foregoing, all common units
become vested if Plains All American Inc. is removed as general partner prior to
January 1, 2002.
We recognized noncash compensation expense of approximately $1.0 million for
the year ended December 31, 1999 related to the transaction grants which vested
in 1999. This amount is included in general and administrative expense on the
Consolidated Statements of Operations.
NOTE 14 -- BENEFIT PLANS
Effective June 1, 1996, our board of directors adopted 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, 1999, 1998 and 1997, is
comprised of the following components (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1999 1998 1997
---------------- ---------------- ----------------
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 109 $ 97 $ 82
Interest on projected benefit obligation 83 74 60
Amortization of prior service cost 37 37 37
Unrecognized loss 6 3 -
---------------- ---------------- ----------------
Net pension expense $ 235 $ 211 $ 179
================ ================ ================
</TABLE>
F-23
<PAGE>
Summarized information of our retirement plan for the periods indicated is as
follows (in thousands):
<TABLE>
<CAPTION>
December 31,
----------------------------
1999 1998
----------- ------------
<S> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year $ 1,280 $ 1,041
Service cost 109 97
Interest cost 83 74
Actuarial (gains) losses (239) 68
-------- --------
Benefit obligation at end of year $ 1,233 $ 1,280
======== ========
Amounts recognized in the consolidated balance sheets:
Projected benefit obligation for service rendered to date $ 1,233 $ 1,280
Plan assets at fair value - -
-------- --------
Fair value of plan assets in excess of benefit obligation (1,233) (1,280)
Unrecognized (gain) loss (34) 211
Unrecognized prior service costs 545 582
Adjustment to recognize minimum liability (512) (582)
-------- --------
Net amount recognized $ (1,234) $ (1,069)
======== ========
</TABLE>
The weighted-average discount rate used in determining the projected benefit
obligation was 7.8% and 6.5% for the years ended December 31, 1999 and 1998.
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), with
matching contribution being made 50% in cash and 50% in common stock (the number
of shares for the stock match being based on the market value of the common
stock at the time the shares are granted). For the years ended December 31,
1999, 1998 and 1997, defined contribution plan expense was $1.0 million, $0.5
million and $0.4 million, respectively.
NOTE 15 -- STOCK COMPENSATION PLANS
Historically, we have used stock options as a long-term incentive for our
employees, officers and directors under various stock option plans. The exercise
price of options granted to employees is equal to or greater than the market
price of the underlying stock on the date of grant. Accordingly, consistent with
the provisions of APB 25, no compensation expense has been recognized in the
accompanying financial statements.
We have options outstanding under our 1996, 1992 and 1991 plans, under which a
maximum of 3.5 million shares of common stock were reserved for issuance.
Generally, terms of the options provide for an exercise price of not less than
the market price of our stock on the date of the grant, a pro rata vesting
period of two to four years and an exercise period of five to ten years.
We have outstanding performance options to purchase a total of 500,000 shares
of common stock which were granted to two executive officers. Terms of the
options provide for an exercise price of $13.50, the market price on the date of
grant, and an exercise period ending in August 2001. The performance options
vest when the price of our common stock trades at or above $24.00 per share for
any 20 trading days in any 30 consecutive trading day period or upon a change in
control if certain conditions are met.
F-24
<PAGE>
A summary of the status of our stock options as of December 31, 1999, 1998,
and 1997, and changes during the years ending on those dates are presented
below:
<TABLE>
<CAPTION>
1999 1998 1997
------------------------- ------------------------- -------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
SHARES EXERCISE SHARES EXERCISE SHARES EXERCISE
Fixed Options (000) PRICE (000) PRICE (000) PRICE
------------- ---------- ------------ ----------- ----------- --------- --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year 2,749 $10.53 2,614 $ 9.50 2,435 $ 8.56
Granted 237 15.09 333 16.62 384 14.33
Exercised (158) 7.94 (179) 6.71 (163) 6.80
Forfeited (17) 9.93 (19) 11.36 (42) 9.82
------- ------ ------
Outstanding at end of year 2,811 $11.06 2,749 $10.53 2,614 $ 9.50
======= ====== ======
Options exercisable at
year-end 1,836 $ 9.50 1,646 $ 8.53 1,494 $ 7.24
======= ======= ======
Weighted-average fair
value of options granted
during the year $ 5.40 $ 4.93 $ 4.53
</TABLE>
In October 1995, the Financial Accounting Standards Board issued SFAS 123
which established financial accounting and reporting standards for stock-based
employee compensation. The pronouncement 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. We will recognize compensation expense under APB 25 in the future
for the performance options described above, if certain conditions are met and
the options vest.
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 1999, 1998 and 1997: risk-free interest rates of 5.1% for 1999, 5.6% for 1998
and 6.1% for 1997; a volatility factor of the expected market price of our
common stock of .50 for 1999, .38 for 1998 and .42 for 1997; no expected
dividends; and weighted-average expected option lives of 2.7 years in 1999, 2.7
years in 1998 and 2.6 years in 1997.
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.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The pro forma
information is not meant to be representative of the effects on reported net
income (loss) for future years, because as provided by SFAS 123, the effects of
awards granted before December 31, 1994, are not considered in the pro forma
calculations. 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).
F-25
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
1999 1998 1997
----------------- ----------------- -----------------
(RESTATED)
<S> <C> <C> <C>
AS REPORTED:
Net income (loss) before extraordinary item $(25,331) $(62,346) $14,259
Net income (loss) per common share, basic (2.02) (3.99) 0.85
Net income (loss) per common share, diluted (2.02) (3.99) 0.77
PRO FORMA:
Net income (loss) before extraordinary item $(25,669) $(63,054) $13,665
Net income (loss) per common share, basic (2.07) (4.03) 0.81
Net income (loss) per common share, diluted (2.07) (4.03) 0.74
</TABLE>
The following table summarizes information about stock options outstanding at
December 31, 1999 (share amounts in thousands):
<TABLE>
<CAPTION>
WEIGHTED
AVERAGE WEIGHTED WEIGHTED
NUMBER REMAINING AVERAGE NUMBER AVERAGE
RANGE OF OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICE AT 12/31/99 LIFE PRICE AT 12/31/99 PRICE
-------------------- -------------- -------------- ------------- -------------- ---------
<S> <C> <C> <C> <C> <C>
$ 5.25 to $ 6.75 871 2.8 years $ 6.14 871 $ 6.14
7.50 to 7.81 345 3.4 years 7.64 336 7.64
10.50 to 15.63 1,420 2.3 years 14.02 454 13.95
17.00 to 19.19 175 3.8 years 18.31 175 18.31
------ ------
$ 5.25 to $19.19 2,811 2.7 years $11.06 1,836 $ 9.50
====== ======
</TABLE>
NOTE 16 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION
Commitments and Contingencies
We lease certain real property, equipment and operating facilities under
various operating leases. We also incur costs associated with leased land,
rights-of-way, permits and regulatory fees whose contracts generally extend
beyond one year but can be canceled at any time should they not be required for
operations. Future non-cancelable commitments related to these items at
December 31, 1999, are summarized below (in thousands):
2000 $8,093
2001 5,759
2002 2,257
2003 1,595
2004 1,506
Later years 2,245
Total expenses related to these commitments for the years ended December 31,
1999, 1998 and 1997 were $9.3 million, $1.6 million and $1.1 million,
respectively.
In connection with its crude oil marketing, PAA provides certain purchasers
and transporters with irrevocable standby letters of credit to secure their
obligation for the purchase of crude oil. Generally, these letters of credit are
issued for up to seventy day periods and are terminated upon completion of each
transaction. At December 31, 1999, PAA had outstanding letters of credit of
approximately $321.5 million. Such letters of credit are secured by PAA's crude
oil inventory and accounts receivable. (see Note 7).
Under the amended terms of an asset purchase agreement between us and
Chevron, 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 233. 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. As of
December 31, 1999, we have not been required to make contributions to an escrow
account.
F-26
<PAGE>
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 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 California properties, we
received a limited indemnity from Chevron 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
from Chevron, other than our obligation to plug existing wells and those
normally associated with customary oil field operations of similarly situated
properties, there can be no assurance that current or future local, state or
federal rules and regulations will not require us to spend material amounts to
comply with such rules and regulations or that any portion of such amounts will
be recoverable under the Chevron 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 $13.4 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 1999, 1998 and 1997 include $0.5 million, $0.8 million and $0.6 million,
respectively, of expense associated with these estimated future costs. For
valuation and realization purposes of the affected crude oil and natural gas
properties, these estimated future costs are also deducted from estimated future
gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in Note 20.
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 trade receivables. Our accounts receivable are
primarily from purchasers of crude oil and natural gas products and shippers of
crude oil. This industry concentration has the potential to impact our overall
exposure to credit risk, either positively or negatively, in that the customers
may be similarly affected by changes in economic, industry or other conditions.
We generally require letters of credit for receivables from customers which are
not considered investment grade, unless the credit risk can otherwise be
reduced. The loss of an individual customer would not have a material adverse
effect.
There are a limited number of alternative methods of transportation for our
production. Substantially all of our California crude oil and natural gas
production and our Sunniland Trend crude oil 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 crude oil and natural gas production which could have a negative
impact on future results of operations or cash flows.
NOTE 17 -- LITIGATION
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, et al. The suit alleged
that Plains All American Pipeline, L.P. and certain of the general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
have been filed in the Southern District of Texas, some of which name the
general partner and us as additional defendants. Plaintiffs allege that the
defendants are liable for securities fraud violations under Rule 10b-5 and
Section 20(a) of the Securities Exchange Act of 1934 and for making false
registration statements under Sections 11 and 15 of the Securities Act of 1933.
The court has consolidated all subsequently filed cases under the first filed
action described above. Two unopposed motions are currently pending to appoint
lead plaintiffs. These motions ask the court to appoint two distinct lead
plaintiffs to represent two different plaintiff classes: (1) purchasers of our
common stock and options and (2) purchasers of PAA's common units. Once lead
plaintiffs have been appointed, the plaintiffs will file their consolidated
amended complaints. No answer or responsive pleading is due until thirty days
after a consolidated amended complaint is filed.
F-27
<PAGE>
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits
were filed in the Delaware Chancery Court, New Castle County, entitled Susser v.
Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et
al. These suits, and three others which were filed in Delaware subsequently,
named the general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to Plains All American Pipeline, L.P. and its unitholders by failing
to monitor properly the activities of its employees. The derivative complaints
allege, among other things, that Plains All American Pipeline has been harmed
due to the negligence or breach of loyalty of the officers and directors that
are named in the lawsuits. These cases are currently in the process of being
consolidated. No answer or responsive pleading is due until these cases have
been consolidated and a consolidated complaint has been filed.
We intend to vigorously defend the claims made in the Texas securities
litigation and the Delaware derivative litigation. However, there can be no
assurance that we will be successful in our defense or that these lawsuits will
not have a material adverse effect on our financial position or results of
operation.
On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in
the United States District Court for the Middle District of Florida, Exxon
Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action
was filed by Exxon to interplead royalty funds as a result of a title
controversy between certain mineral owners in a field in Florida. One group of
mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a
counterclaim against Exxon alleging fraud, conspiracy, conversion of funds,
declaratory relief, federal and Florida RICO, breach of contract and accounting,
as well as challenging the validity of certain oil and natural gas leases owned
by Exxon, and seeking exemplary and treble damages. In March 1993, but effective
November 1, 1992, Calumet Florida, Inc. ("Calumet"), our wholly owned
subsidiary, acquired all of Exxon's leases in the field affected by this
lawsuit. In order to address those counterclaims challenging the validity of
certain oil and natural gas leases, which constitute approximately 10% of the
land underlying this unitized field, Calumet filed a motion to join Exxon as
plaintiff in the subject lawsuit, which was granted July 29, 1994. In August
1994, the Hughes Group amended its counterclaim to add Calumet as a counter-
defendant. Exxon and Calumet filed a motion to dismiss the counterclaims. On
March 22, 1996, the Court granted Exxon's and Calumet's motion to dismiss the
counterclaims alleging fraud, conspiracy, and federal and Florida RICO
violations and challenging the validity of certain of our oil and natural gas
leases but denied such motion as to the counterclaim alleging conversion of
funds. We have reached an agreement in principle to settle with the Hughes
Group. In consideration for full and final settlement, and dismissal with
prejudice, we have agreed to pay to the Hughes Group the total sum of $100,000.
We and Exxon have filed motions for summary judgment with respect to the claims
of the remaining defendants. The court has not yet set a date for hearing of
these motions. The trial date is currently scheduled in June 2000.
We are a defendant, in the ordinary course of business, in various other legal
proceedings in which our exposure, individually and in the aggregate, is not
considered material to the accompanying financial statements.
NOTE 18 -- FINANCIAL INSTRUMENTS
Derivatives
We utilize derivative financial instruments, as defined in Statement of
Financial Accounting Standards No. 119, "Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments" to hedge our exposure to
price volatility on crude oil and do not use such instruments for speculative
trading purposes. These arrangements expose us to credit risk (as to
counterparties) and to risk of adverse price movements in certain cases where
our purchases are less than expected. In the event of non-performance of a
counterparty, we might be forced to acquire alternative hedging arrangements or
be required to honor the underlying commitment at then-current market prices. In
order to minimize credit risk relating to the non-performance of a counterparty,
we enter into such contracts with counterparties that are considered investment
grade, periodically review the financial condition of such counterparties and
continually monitor the effectiveness of derivative financial instruments in
achieving our objectives. In view of our criteria for selecting counterparties,
our process for monitoring the financial strength of these counterparties and
our experience to date in successfully completing these transactions, we believe
that the risk of incurring significant financial statement loss due to the non-
performance of counterparties to these transactions is minimal.
We have entered into various arrangements to fix the NYMEX crude oil spot
price for a significant portion of our crude oil production. On December 31,
1999, these arrangements provided for a NYMEX crude oil price for 18,500 barrels
per day from January 1, 2000, through December 31, 2000, at an average floor
price of approximately $16.00 per barrel. Approximately 10,000 barrels per day
of the volumes hedged in 2000 will participate in price increases above the
$16.00 per barrel floor price, subject to a ceiling limitation of $19.75 per
barrel. Location and quality differentials attributable to our properties are
not included in the foregoing prices. The agreements provide for monthly
settlement based on the differential
F-28
<PAGE>
between the agreement price and the actual NYMEX crude oil price. Gains or
losses are recognized in the month of related production and are included in
crude oil and natural gas sales.
At December 31, 1999, our hedging activities included crude oil futures
contracts maturing in 2000 through 2002, covering approximately 7.4 million
barrels of crude oil, including the portion of the linefill sold in January and
February 2000. Since such contracts are designated as hedges and correlate to
price movements of crude oil, any gains or losses resulting from market changes
will be largely offset by losses or gains on our hedged inventory or anticipated
purchases of crude oil.
In addition, we have entered into swap agreements with various financial
institutions to hedge the interest rate on an aggregate of $240 million of bank
debt. These swaps are scheduled to terminate in 2001 and thereafter.
Fair Value of 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
judgement 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.
Crude oil futures contracts permit settlement by delivery of the crude oil and,
therefore, are not financial instruments, as defined. The carrying amounts and
fair values of our other financial instruments are as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------------
1999 1998
-------------------------------- ---------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------------- ------------- ------------ ------------
Long-Term Debt:
<S> <C> <C> <C> <C>
Bank debt $396,750 $396,750 $227,000 $227,000
Subordinated debt 277,909 268,125 202,427 202,000
Other long-term debt 2,044 2,044 2,556 2,556
Redeemable Preferred Stock 138,813 138,813 88,487 88,487
OFF BALANCE SHEET FINANCIAL INFORMATION:
Unrealized gain (loss) on crude oil swap and collar agreements (1) - (22,048) - 16,870
Unrealized gain (loss) on interest rate swap and collar agreements - 1,048 - (3,253)
</TABLE>
(1) These amounts represent the calculated difference between the NYMEX crude
oil price and the hedge arrangements for future production from our
properties as of December 31, 1999 and 1998. These hedges, and therefore
the unrealized gains or losses, have been included in estimated future
gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in Note 20.
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 was based on quoted market prices based on trades of subordinated debt.
Other long-term debt was valued by discounting the future payments using our
incremental borrowing rate. The fair value of the redeemable preferred stock is
estimated to be its liquidation value at December 31, 1999 and 1998. The fair
value of the interest rate swap and collar agreements is based on current
termination values or quoted market prices of comparable contracts at December
31, 1999 and 1998.
F-29
<PAGE>
NOTE 19 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Selected cash payments and noncash activities were as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Cash paid for interest (net of amount capitalized) $ 44,329 $ 34,546 $ 20,486
=========== =========== ===========
Noncash sources and (uses) of investing and financing activities:
Series D Preferred Stock dividends $ ( 1,354) $ (1,275) $ (163)
=========== =========== ===========
Exchange of preferred stock for common stock $ 71 $ - $ -
=========== =========== ===========
Series E Preferred Stock dividends $ (2,030) $ (3,487) $ -
=========== =========== ===========
Tax benefit from exercise of employee stock options $ 440 $ 653 $ 513
=========== =========== ===========
Detail of properties acquired for other than cash:
Fair value of acquired assets $ - $ - $ 22,140
Debt issued and liabilities assumed - - -
Property exchanged - - (1,619)
Capital stock and warrants issued - - (21,408)
----------- ----------- -----------
Cash (received) paid $ - $ - $ (887)
=========== =========== ===========
</TABLE>
NOTE 20 -- CRUDE OIL AND NATURAL GAS ACTIVITIES
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).
Costs Incurred
YEAR ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
------- -------- --------
Property acquisitions costs:
Unproved properties $ 879 $ 6,266 $ 15,249
Proved properties 2,880 3,851 28,182
Exploration costs 4,101 1,657 1,730
Exploitation and development costs 65,119 89,161 82,217
------- -------- --------
$72,979 $100,935 $127,378
======= ======== ========
Capitalized Costs
Under full cost accounting rules as prescribed by the Securities and Exchange
Commission ("SEC"), unamortized costs of proved crude oil and natural gas
properties are subject to a ceiling, which limits such costs to the Standardized
Measure (as described below). At December 31, 1998, the capitalized costs of our
proved crude oil and natural gas properties exceeded the Standardized Measure
and we recorded a noncash, after tax charge to expense of $109.0 million ($173.9
million pre-tax). 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
DD&A (in thousands).
DECEMBER 31,
--------------------
1999 1998
--------- ---------
Proved properties $ 671,928 $ 596,203
Accumulated DD&A (387,437) (369,260)
--------- ---------
$ 284,491 $ 226,943
========= =========
The DD&A rate per equivalent unit of production excluding the writedown in
1998 was $2.13, $3.00 and $2.83 for the years ended December 31, 1999, 1998 and
1997, respectively.
F-30
<PAGE>
Costs Not Subject to Amortization
The following table summarizes the categories of costs which comprise the
amount of unproved properties not subject to amortization (in thousands).
December 31,
---------------------------------
1999 1998 1997
---------- ---------- ----------
Acquisition costs $ 42,261 $ 47,657 $ 41,652
Exploration costs 4,842 2,467 2,573
Capitalized interest 4,928 4,421 7,799
---------- ---------- ----------
$ 52,031 $ 54,545 $ 52,024
========== ========== ==========
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 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 16%, 19% and 31% of the balance in unproved
properties at December 31, 1999, related to additions made in 1999, 1998 and
1997, respectively.
During 1999, 1998 and 1997, we capitalized $4.4 million, $3.7 million and $3.3
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, 1999. The following
reserve information is based upon reports of the independent petroleum
consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc.,
and Ryder Scott Company in 1999, 1998 and 1997 and in addition, in 1997 by
System Technology Associates, Inc. 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 1999 reserve volumes) is comprised of crude oil
properties that are sensitive to crude oil price volatility.
Estimated Quantities of Crude Oil and Natural Gas Reserves (Unaudited)
F-31
<PAGE>
The following table sets forth certain data pertaining to our proved and
proved developed reserves for the three years ended December 31, 1999 (in
thousands).
<TABLE>
<CAPTION>
As of or for the Year Ended December 31,
----------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- ------------------------
Oil Gas Oil Gas Oil Gas
(Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf)
------------ ------------ ------------ ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Proved Reserves
Beginning balance 120,208 86,781 151,627 60,350 115,996 37,273
Revision of previous estimates 62,895 (8,234) (46,282) 2,925 (16,091) 3,805
Extensions, discoveries, improved
recovery and other additions 37,393 15,488 14,729 29,306 17,884 8,126
Sale of reserves in-place - - - (2,799) (26) (547)
Purchase of reserves in-place 6,442 - 7,709 - 40,764 14,566
Production (8,016) (3,162) (7,575) (3,001) (6,900) (2,873)
------------ ------------ ------------ ------------ ----------- -----------
Ending balance 218,922 90,873 120,208 86,781 151,627 60,350
============ ============ ============ ============ =========== ===========
Proved Developed Reserves
Beginning balance 73,264 58,445 99,193 38,233 86,515 25,629
============ ============ ============ ============ =========== ===========
Ending balance 120,141 49,255 73,264 58,445 99,193 38,233
============ ============ ============ ============ =========== ===========
</TABLE>
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,
--------------------------------------
1999 1998 1997
----------- ---------- -----------
Future cash inflows $ 4,837,010 $1,102,863 $ 2,237,876
Future development costs (231,914) (117,924) (157,877)
Future production expense (1,758,572) (546,091) (1,019,254)
Future income tax expense (845,133) - (261,130)
----------- ---------- -----------
Future net cash flows 2,001,391 438,848 799,615
Discounted at 10% per year (1,073,591) (211,905) (387,792)
----------- ---------- -----------
Standardized measure of
discounted future net
cash flows $ 927,800 $ 226,943 $ 411,823
=========== ========== ===========
The Standardized Measure of discounted future net cash flows (discounted at
10%) from production of proved reserves was developed as follows:
1. An estimate was made of the quantity of proved reserves and the future
periods in which they are expected to be produced based on year-end
economic conditions.
2. In accordance with SEC guidelines, the engineers' estimates of future net
revenues from our proved properties and the present value thereof are made
using crude oil and natural gas sales prices in effect as of the dates of
such estimates and are held constant throughout the life of the properties,
except where such guidelines permit alternate treatment, including the use
of fixed and determinable contractual price escalations. We have entered
into various fixed price and floating price collar 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, 1999 are reflected in
the reserve reports through the term of the arrangements (see Note 18). The
overall average prices used in the reserve reports as of December 31, 1999,
were $20.94 per barrel of crude oil, condensate and natural gas liquids and
$2.77 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 $1.2
billion, $226.9 million and $511.0 million at December 31, 1999, 1998 and
1997, 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
F-32
<PAGE>
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.
The principal sources of changes in the Standardized Measure of the future net
cash flows for the three years ended December 31, 1999, are as follows (in
thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 1998 1997
----------- ---------- ----------
<S> <C> <C> <C>
Balance, beginning of year $ 226,943 $ 411,823 $ 578,581
Sales, net of production expenses (60,578) (51,927) (63,917)
Net change in sales and transfer prices, net of production expenses 580,890 (288,320) (359,138)
Changes in estimated future development costs (52,951) 42,858 9,927
Extensions, discoveries and improved recovery, net of costs 112,573 21,095 84,676
Previously estimated development costs incurred during the year 22,842 25,501 23,449
Purchase of reserves in-place 53,724 14,173 74,278
Sales of reserves in-place - (1,151) (1,501)
Revision of quantity estimates 404,705 (91,942) (57,597)
Accretion of discount 22,694 51,099 76,477
Net change in income taxes (318,249) 99,170 87,024
Changes in estimated timing of production and other (64,793) (5,436) (40,436)
----------- ---------- ----------
Balance, end of year $ 927,800 $ 226,943 $ 411,823
=========== ========== =========
</TABLE>
Results of Operations for Oil and Gas Producing Activities
The results of operations from oil and gas producing activities excludes
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.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------
1999 1998 1997
-------------- --------------- -------------
<S> <C> <C> <C>
Revenues from oil and gas producing activities $ 116,223 $ 102,754 $ 109,403
Production costs (55,645) (50,827) (45,486)
Depreciation, depletion and amortization (36,998) (31,020) (23,778)
Reduction in carrying cost of oil and natural gas properties - (173,874) -
Income tax (expense) benefit (9,196) 59,657 (15,654)
---------- ---------- ----------
Results of operations from producing activities
(excluding corporate overhead and interest costs) $ 14,384 $ (93,310) $ 24,485
========== ========== ==========
</TABLE>
NOTE 21--QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table shows summary financial data for 1999 and 1998 (in
thousands, except per share data):
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
--------------- -------------- -------------- ------------- ---------------
1999(1)
------
<S> <C> <C> <C> <C> <C>
Revenues $476,971 $887,277 $1,133,519 $2,262,617 $4,760,384 (2)
Operating profit (loss) 7,638 17,966 (21,624) 15,542 19,522 (2)
Net income (loss) (5,161) (3,116) (20,047) 2,993 (25,331)
Basic and diluted EPS (0.45) (0.33) (1.30) 0.02 (2.05)
1998(1)
--------
Revenues $193,572 $189,441 $ 393,719 $ 456,545 (2) $1,233,277 (2)
Operating profit 17,534 18,323 20,111 28,054 (2) 84,022 (2)
Net income (loss) 1,431 1,418 (1,442) (63,753) (62,346)
Basic EPS 0.07 0.07 (0.19) (3.92) (3.99)
Diluted EPS 0.06 0.06 (0.19) (3.92) (3.99)
</TABLE>
-----------------
(1) As indicated in Note 3, quarterly results for 1999 and the fourth quarter
of 1998 have been restated from amounts previously reported due to the
unauthorized trading losses.
(2) Excludes net gains of $9.8 million and $60.8 million related to PAA's unit
offerings in 1999 and 1998, respectively, recorded upon the formation of
PAA.
F-33
<PAGE>
NOTE 22--OPERATING SEGMENTS
Our operations consist of three 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 and (3) Corporate - reflects certain amounts that are not directly
attributable to Upstream or Midstream Operations. The accounting policies of the
segments are the same as those described in the summary of significant
accounting policies (see Note 1). We evaluate segment performance based on gross
margin, gross profit and income before income taxes and extraordinary items.
<TABLE>
<CAPTION>
(IN THOUSANDS) UPSTREAM MIDSTREAM CORPORATE TOTAL
----------------------------------------------------------------------------------------------------------------------------
(RESTATED) (RESTATED)
1999
Revenues:
<S> <C> <C> <C> <C>
External customers $ 116,223 $4,626,467 $ - $4,742,690
Intersegment (a) - 75,454 - 75,454
Linefill gain - 16,457 - 16,457
Interest and other income 241 10,783 - 11,024
----------- ------------- ---------- ------------
Total revenues of reportable segments $ 116,464 $4,729,161 $ - $4,845,625
=========== ============ ========= ============
Segment gross margin(b) $ 60,578 $ (58,750) $ - $ 1,828
Segment gross profit(c) 53,275 (82,349) (500) (29,574)
Segment income (loss) before income taxes
and extraordinary item 9,738 (93,601) (1,606) (85,469)
Interest expense 23,586 21,686 1,106 46,378
Depreciation, depletion and amortization 19,586 17,412 - 36,998
Income tax expense (benefit) 1,635 18,844 - 20,479
Capital expenditures 77,899 189,286 - 267,185
Assets 445,921 1,243,639 - 1,689,560
----------------------------------------------------------------------------------------------------------------------------
1998
Revenues:
External customers $ 102,754 $1,129,689 $ - $1,232,443
Intersegment (a) - 119 - 119
Interest and other income 250 584 - 834
----------- ------------- ---------- ------------
Total revenues of reportable segments $ 103,004 $1,130,392 $ - $1,233,396
=========== ============ ========= ============
Segment gross margin(b) (d) $ 51,927 $ 31,261 $ - $ 83,188
Segment gross profit(c) (d) 46,446 25,964 - 72,410
Segment income(loss) before income taxes
and extraordinary item(d) (175,926) 8,546 - (167,380)
Interest expense 23,099 12,631 - 35,730
Depreciation, depletion and amortization 199,523 5,371 - 204,894
Income tax expense (benefit) (33,732) (11,273) - (45,005)
Capital expenditures 100,935 405,508 - 506,443
Assets 365,652 607,186 - 972,838
----------------------------------------------------------------------------------------------------------------------------
1997
Revenues:
External customers $ 109,403 $ 752,522 $ - $ 861,925
Intersegment (a) - - - -
Interest and other income 181 138 - 319
----------- ------------- ---------- ------------
Total revenues of reportable segments $ 109,584 $ 752,660 $ - $ 862,244
=========== ============ ========= ============
Segment gross margin(b) $ 63,917 $ 12,480 $ - $ 76,397
Segment gross profit(c) 59,106 8,951 - 68,057
Segment income before income taxes and
extraordinary item 19,178 3,408 - 22,586
Interest expense 17,496 4,516 - 22,012
Depreciation, depletion and amortization 22,613 1,165 - 23,778
Income tax expense (benefit) 7,059 1,268 - 8,327
Capital expenditures 127,378 5,381 - 132,759
Assets 407,200 149,619 - 556,819
----------------------------------------------------------------------------------------------------------------------------
</TABLE>
(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.
(d) Differences between segment totals and company totals represent the net
gain of $60.8 million recorded upon the formation of PAA, which was not
allocated to segments.
F-34
<PAGE>
The following table reconciles segment revenues to amounts reported in our
financial statements:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Revenues of reportable segments $ 4,845,625 $ 1,233,396 $ 862,244
Intersegment (75,454) (119) -
Net gain recorded upon the formation of PAA
not allocated to reportable segments - 60,815 -
----------- ----------- ----------
Total company revenues $ 4,770,171 $ 1,294,092 $ 862,244
=========== =========== ==========
</TABLE>
Customers accounting for more than 10% of total sales for the periods
indicated are as follows:
PERCENTAGE OF TOTAL SALES
YEAR ENDED DECEMBER 31,
------------------------
CUSTOMER 1999 1998 1997
------- ------ -------
Sempra Energy Trading Corporation 22% 27% 11%
Koch Oil Company 18% 15% 27%
PERCENTAGE OF OIL AND GAS SALES
--------------------------------
Chevron 43% - -
Tosco Refining Company 21% 50% -
Conoco Inc. 12%
Scurlock Permian LLC - 17% -
Unocal Energy Trading, Inc. - - 52%
Marathon Oil Company 17% - 23%
Exxon Company U.S.A. - - 10%
NOTE 23 -- 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 Series A-E Notes discussed in
Note 7 are not guaranteed by PAA and our consolidated financial statements
include the accounts of PAA.
F-35
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (in thousands)
DECEMBER 31, 1999
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------ --------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 9,241 $ 5,134 $ 53,853 $ - $ 68,228
Accounts receivable and other 1,808 11,221 508,919 - 521,948
Inventory - 5,652 34,826 - 40,478
Assets held for sale - - 141,486 - 141,486
----------- ------------ --------------- --------------- --------------
Total current assets 11,049 22,007 739,084 - 772,140
----------- ------------ --------------- --------------- --------------
PROPERTY AND EQUIPMENT 235,158 494,279 460,730 - 1,190,167
Less allowance for depreciation,
depletion and amortization (215,463) (120,016) (11,649) (55,386) (402,514)
----------- ------------ --------------- --------------- --------------
19,695 374,263 449,081 (55,386) 787,653
----------- ------------ --------------- --------------- --------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES 440,115 (224,598) (45,683) (169,834) -
OTHER ASSETS 40,337 14,752 74,678 - 129,767
----------- ------------ --------------- --------------- --------------
$ 511,196 $ 186,424 $ 1,217,160 $ (225,220) $ 1,689,560
=========== ============ =============== =============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 23,700 $ 35,457 $ 487,212 $ 24 $ 546,393
Notes payable and other current obligations - 511 109,369 - 109,880
----------- ------------ --------------- --------------- --------------
Total current liabilities 23,700 35,968 596,581 24 656,273
BANK DEBT 137,300 - - - 137,300
BANK DEBT OF A SUBSIDIARY - - 259,450 - 259,450
SUBORDINATED DEBT 277,909 - - - 277,909
OTHER LONG-TERM DEBT - 2,044 105,000 (105,000) 2,044
OTHER LONG-TERM LIABILITIES 1,954 - 19,153 - 21,107
----------- ------------ --------------- --------------- --------------
440,863 38,012 980,184 (104,976) 1,354,083
----------- ------------ --------------- --------------- --------------
MINORITY INTEREST (70,037) - 226,082 - 156,045
----------- ------------ --------------- --------------- --------------
SERIES E, F AND G CUMULATIVE
CONVERTIBLE PREFERRED STOCK,
STATED AT LIQUIDATION PREFERENCE 138,813 - - - 138,813
----------- ------------ --------------- --------------- --------------
NON-REDEEMABLE PREFERRED STOCK,
COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock 23,300 - - - 23,300
Common Stock 1,792 78 - (78) 1,792
Additional paid-in capital 130,027 3,952 43,261 (47,213) 130,027
Retained earnings (accumulated deficit) (153,562) 144,382 (32,367) (72,953) (114,500)
----------- ------------ --------------- --------------- --------------
1,557 148,412 10,894 (120,244) 40,619
----------- ------------ --------------- --------------- --------------
$ 511,196 $ 186,424 $ 1,217,160 $ (225,220) $ 1,689,560
=========== ============ =============== =============== ==============
</TABLE>
F-36
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (restated) (in thousands)
DECEMBER 31, 1998
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
------------- ------------- --------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 142 $ 194 $ 6,408 $ (200) $ 6,544
Accounts receivable and other 838 8,909 120,655 - 130,402
Inventory - 4,809 37,711 - 42,520
------------- ------------- --------------- --------------- --------------
Total current assets 980 13,912 164,774 (200) 179,466
------------- ------------- --------------- --------------- --------------
PROPERTY AND EQUIPMENT 234,127 424,646 378,835 - 1,037,608
Less allowance for depreciation,
depletion and amortization (228,579) (91,118) (799) (55,386) (375,882)
------------- ------------- --------------- --------------- --------------
5,548 333,528 378,036 (55,386) 661,726
------------- ------------- --------------- --------------- --------------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES 246,581 (179,716) (2,847) (64,018) -
OTHER ASSETS 47,435 8,177 76,034 - 131,646
------------- ------------- --------------- --------------- --------------
$ 300,544 $ 175,901 $ 615,997 $ (119,604) $ 972,838
============= ============= =============== =============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 18,425 $ 26,207 $ 145,814 $ (200) $ 190,246
Notes payable and other current obligations - 511 9,750 - 10,261
------------- ------------- --------------- --------------- --------------
Total current liabilities 18,425 26,718 155,564 (200) 200,507
BANK DEBT 52,000 - - - 52,000
BANK DEBT OF A SUBSIDIARY - - 175,000 - 175,000
SUBORDINATED DEBT 202,427 - - - 202,427
OTHER LONG-TERM DEBT - 2,556 - - 2,556
OTHER LONG-TERM LIABILITIES 2,029 8,179 45 - 10,253
------------- ------------- --------------- --------------- --------------
274,881 37,453 330,609 (200) 642,743
------------- ------------- --------------- --------------- --------------
MINORITY INTEREST (70,037) - 242,475 - 172,438
------------- ------------- --------------- --------------- --------------
SERIES E CUMULATIVE CONVERTIBLE
PREFERRED STOCK, STATED AT
LIQUIDATION PREFERENCE 88,487 - - - 88,487
------------- ------------- --------------- --------------- --------------
NON-REDEEMABLE PREFERRED STOCK,
COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock 21,946 - - - 21,946
Common Stock 1,688 77 - (77) 1,688
Additional paid-in capital 124,679 3,954 38,727 (42,681) 124,679
Retained earnings (accumulated deficit) (141,100) 134,417 4,186 (76,646) (79,143)
------------- ------------- --------------- --------------- --------------
7,213 138,448 46,671 (119,404) 69,170
------------- ------------- --------------- --------------- --------------
$ 300,544 $ 175,901 $ 615,997 $ (119,604) $ 972,838
============= ============= =============== =============== ==============
</TABLE>
F-37
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
------------ ------------ ------------- ------------- --------------
(RESTATED) (RESTATED)
<S> <C> <C> <C> <C> <C>
REVENUES
Crude oil and natural gas sales $ - $ 114,736 $ - $ 1,487 $ 116,223
Marketing, transportation, storage and terminalling - - 4,701,921 (75,454) 4,626,467
Gain on PAA unit offering - - 9,787 - 9,787
Gain on sale of linefill - 16,457 - 16,457
Interest and other income 699 89 996 (547) 1,237
------------ ------------ ------------- ------------- --------------
699 114,825 4,729,161 (74,514) 4,770,171
------------ ------------ ------------- ------------- --------------
EXPENSES
Production expenses - 55,645 - - 55,645
Marketing, transportation, storage and terminalling - - 4,592,744 (73,967) 4,518,777
Unauthorized trading loss and related expenses - - 166,440 166,440
General and administrative 2,311 5,492 23,599 - 31,402
Depreciation, depletion and amortization 2,096 17,490 17,412 - 36,998
Interest expense 6,994 18,851 21,080 (547) 46,378
------------ ------------ ------------- ------------- --------------
11,401 97,478 4,821,275 (74,514) 4,855,640
------------ ------------ ------------- ------------- --------------
Income (loss) before income taxes, minority interest
minority interest and extraordinary item (10,702) 17,347 (92,114) - (85,469)
Minority interest - - (40,203) - (40,203)
------------ ------------ ------------- ------------- --------------
Income (loss) before income taxes (10,702) 17,347 (51,911) - (45,266)
Income tax expense (benefit):
Current (338) - 331 - (7)
Deferred 3,457 (4,754) (19,175) - (20,472)
------------ ------------ ------------- ------------- --------------
Income (loss) before extraordinary item (13,821) 22,101 (33,067) - (24,787)
Extraordinary item, net of tax benefit
and minority interest - - (544) - (544)
------------ ------------ ------------- ------------- --------------
NET INCOME (LOSS) (13,821) 22,101 (33,611) - (25,331)
Less: cumulative preferred stock dividends 10,026 - - - 10,026
------------ ------------ ------------- ------------- --------------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $ (23,847) $ 22,101 $ (33,611) $ - $ (35,357)
============ ============ ============= ============= ==============
</TABLE>
F-38
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (restated) (in thousands)
YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
------------ ------------ ------------- ------------- --------------
<S> <C> <C> <C> <C> <C>
REVENUES
Crude oil and natural gas sales $ - $ 102,634 $ - $ 120 $ 102,754
Marketing, transportation, storage and terminalling - - 1,129,809 (120) 1,129,689
Gain on formation of PAA 60,815 - - - 60,815
Interest and other income 40 76 718 - 834
------------ ------------ ------------- ------------- --------------
60,855 102,710 1,130,527 - 1,294,092
------------ ------------ ------------- ------------- --------------
EXPENSES
Production expenses - 50,827 - - 50,827
Marketing, transportation, storage and terminalling - - 1,091,328 - 1,091,328
Unauthorized trading losses and related expenses - - 7,100 - 7,100
General and administrative 1,536 3,946 5,296 - 10,778
Depreciation, depletion and amortization 5,521 20,127 5,372 - 31,020
Reduction in carrying cost of oil and natural gas properties 9,267 25,738 - 138,869 173,874
Interest expense 11,389 11,710 12,631 - 35,730
------------ ------------ ------------- ------------- --------------
27,713 112,348 1,121,727 138,869 1,400,657
------------ ------------ ------------- ------------- --------------
Income (loss) before income taxes and minority interest 33,142 (9,638) 8,800 (138,869) (106,565)
Minority interest - - 786 - 786
------------ ------------ ------------- ------------- --------------
Income (loss) before income taxes 33,142 (9,638) 8,014 (138,869) (107,351)
Income tax expense (benefit):
Current (3,637) (3) 4,502 - 862
Deferred (24,613) (9,237) (12,017) - (45,867)
------------ ------------ ------------- ------------- --------------
NET INCOME (LOSS) 61,392 (398) 15,529 (138,869) (62,346)
Less: cumulative preferred stock dividends 4,762 - - - 4,762
------------ ------------- ------------ ------------- --------------
NET INCOME (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS $ 56,630 $ (398) $ 15,529 $ (138,869) $ (67,108)
============ ============= ============ ============= ==============
</TABLE>
F-39
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (in thousands)
YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------- -------------- ------------ --------------
<S> <C> <C> <C> <C> <C>
REVENUES
Crude oil and natural gas sales $ 867 $ 108,536 $ - $ - $ 109,403
Marketing, transportation, storage and terminalling - - 752,522 - 752,522
Interest and other income 90 91 138 - 319
----------- ------------ -------------- ------------ --------------
957 108,627 752,660 - 862,244
----------- ------------ -------------- ------------ --------------
EXPENSES
Production expenses 282 45,204 - - 45,486
Marketing, transportation, storage and terminalling - 9 740,033 - 740,042
General and administrative 1,294 3,517 3,529 - 8,340
Depreciation, depletion and amortization 5,887 16,741 1,150 - 23,778
Interest expense 10,111 7,384 4,517 - 22,012
----------- ------------ -------------- ------------ --------------
17,574 72,855 749,229 - 839,658
----------- ------------ -------------- ------------ --------------
Income (loss) before income taxes (16,617) 35,772 3,431 - 22,586
Income tax expense (benefit):
Current (507) 792 67 - 352
Deferred 5,328 1,450 1,197 - 7,975
----------- ------------ -------------- ------------ --------------
NET INCOME (LOSS) (21,438) 33,530 2,167 - 14,259
Less: cumulative preferred stock dividends 163 - - - 163
----------- ------------ -------------- ------------ --------------
NET INCOME (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS $ (21,601) $ 33,530 $ 2,167 $ - $ 14,096
=========== ============ ============== ============ ==============
</TABLE>
F-40
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------- -------------- ------------- --------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $(13,821) $ 22,101 $ (33,611) $ - $ (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)
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 FLOWS 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 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
=========== ============= ============== ============= ==============
</TABLE>
F-41
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (restated) (in thousands)
YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------ ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 61,392 $ (398) $ 15,529 $ (138,869) $ (62,346)
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 5,521 20,127 5,372 - 31,020
Reduction in carrying costs of oil and
natural gas properties 9,267 25,738 - 138,869 173,874
Noncash gain (Note 4 and 6) (70,037) - - - (70,037)
Minority interest in income of a subsidiary - - 786 - 786
Deferred income tax (24,613) (9,237) (12,017) - (45,867)
Other noncash items 90 - - - 90
Change in assets and liabilities resulting from
operating activities:
Accounts receivable and other 275 (3,444) 27,253 - 24,084
Inventory 8 (924) (18,141) - (19,057)
Pipeline linefill - - (3,904) - (3,904)
Accounts payable and other current liabilities 6,232 (10,782) 10,825 2,712 8,987
----------- ------------ ------------- ------------- -------------
NET CASH FLOWS PROVIDED BY
(USED IN) OPERATING ACTIVITIES (11,865) 21,080 25,703 2,712 37,630
----------- ------------ ------------- ------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for midstream acquisitions (Note 6) - - (394,026) - (394,026)
Payments for crude oil pipeline, gathering and terminal assets - - (8,131) - (8,131)
Proceeds from the sale of oil and natural gas properties - 131 - - 131
Payments for acquisition, exploration,
and development costs - (80,318) - - (80,318)
Payments for additions to other property and other assets (510) (309) (259) - (1,078)
----------- ------------ ------------- ------------- -------------
NET CASH USED IN INVESTING ACTIVITIES (510) (80,496) (402,416) - (483,422)
----------- ------------ ------------- ------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates (54,060) 59,347 (5,287) - -
Proceeds from long-term debt 239,260 - 331,300 - 570,560
Proceeds from short-term debt - - 31,750 - 31,750
Proceeds from sale of capital stock, options and warrants 828 - - - 828
Proceeds from issuance of preferred stock 85,000 - - - 85,000
Proceeds from issuance of common units - - 241,690 - 241,690
Distributions upon formation 241,690 - (241,690) - -
Principal payments of long-term debt (384,260) - (39,300) - (423,560)
Principal payments of short-term debt - - (40,000) - (40,000)
Capital contribution from Parent (113,700) - 113,700 - -
Dividend to Parent 3,557 - (3,557) - -
Costs incurred in connection with financing arrangements (6,138) - (6,937) - (13,075)
Other (4,571) - - - (4,571)
----------- ------------ ------------- ------------- -------------
NET CASH PROVIDED BY FINANCING ACTIVITIES 7,606 59,347 381,669 - 448,622
----------- ------------ ------------- ------------- -------------
Net increase (decrease) in cash and cash equivalents (4,769) (69) 4,956 2,712 2,830
Cash and cash equivalents, beginning of period 4,911 263 1,452 (2,912) 3,714
----------- ------------ ------------- ------------- -------------
Cash and cash equivalents, end of period $ 142 $ 194 $ 6,408 $ (200) $ 6,544
=========== ============ ============= ============= =============
</TABLE>
F-42
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (unaudited) (in thousands)
YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
Guarantor Nonguarantor Intercompany
Parent Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------ ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $(21,438) $ 33,530 $ 2,167 $ - $ 14,259
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 5,887 16,741 1,150 - 23,778
Deferred income tax 5,328 1,450 1,197 - 7,975
Other noncash items - 221 - - 221
Change in assets and liabilities resulting from
operating activities:
Accounts receivable and other 3,305 (3,242) (9,453) - (9,390)
Inventory (3) (1,786) (16,450) - (18,239)
Accounts payable and other current liabilities (4,116) 6,051 9,343 425 11,703
--------- ---------- ----------- ----------- -----------
NET CASH FLOWS PROVIDED BY
(USED IN) OPERATING ACTIVITIES (11,037) 52,965 (12,046) 425 30,307
----------- ------------ ----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for acquisition, exploration,
and development costs (6,772) (98,874) - - (105,646)
Payments for crude oil pipeline, gathering terminal assets - - (923) - (923)
Proceeds from the sale of oil and natural gas properties 2,667 - - - 2,667
Payments for additions to other property and other assets (430) (3,184) (118) - (3,732)
----------- ------------ ------------- ----------- -----------
NET CASH USED IN INVESTING ACTIVITIES (4,535) (102,058) (1,041) - (107,634)
----------- ------------ ------------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates (45,228) 49,638 (4,410) - -
Proceeds from long-term debt 266,905 - - - 266,905
Proceeds from short-term debt - - 39,000 - 39,000
Proceeds from sale of capital stock, options and warrants 1,104 - - - 1,104
Principal payments of long-term debt (206,500) (511) - - (207,011)
Principal payments of short-term debt - - (21,000) - (21,000)
Other (474) - - - (474)
----------- ------------ ------------- ----------- -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES 15,807 49,127 13,590 - 78,524
----------- ------------ ------------- ----------- -----------
Net increase in cash and cash equivalents 235 34 503 425 1,197
Cash and cash equivalents, beginning of period 4,676 229 949 (3,337) 2,517
----------- ------------ ------------- ----------- -----------
Cash and cash equivalents, end of period $ 4,911 $ 263 $ 1,452 $ (2,912) $ 3,714
=========== ============ ============= =========== ===========
</TABLE>
F-43
