<PAGE>
 
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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                          ___________________________

                                   FORM 10-K

[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
     ACT OF 1934

     For the fiscal year ended December 31, 1998


[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

     For the transition period from __________ to _____________

                        Commission file number: 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 Number)

               500 Dallas
             Houston, Texas                                    77002
   (Address of principal executive offices)                 (Zip Code)


      Registrant's telephone number, including area code:  (713) 654-1414

Securities registered pursuant to Section 12(b) of the Act:

        Title of each class:          Name of each exchange on which registered:
        --------------------          ----------------------------------------  
   Common Stock, par value $.10                 American Stock Exchange
           per share                      


Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to the filing
requirements for the past 90 days.

Yes x    No 
   ---     --- 

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
$234,602,780 on March 26, 1999 (based on $14.25 per share, the last sale price
of the Common Stock as reported on the American Stock Exchange Composite Tape on
such date).

     16,891,617 shares of the registrant's Common Stock were outstanding 
                             as of March 26, 1999.

DOCUMENTS INCORPORATED BY REFERENCE. The information required in Part III of
this 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. [X]
--------------------------------------------------------------------------------
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                          1998 FORM 10-K ANNUAL REPORT
                               Table of Contents

<TABLE>
<CAPTION>
                                                                                                                Page
                                                                                                              ---------
                                                               PART I
<S>         <C>                                                                                                    <C>
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 Units and Related Unitholder Matters                                    34
Item 6.     Selected Financial Data                                                                                35
Item 7.     Management's Discussion and Analysis of Financial Condition and Results of Operations                  36
Item 7A.    Qualitative and Quantitative Disclosures About Market Risk                                             46
Item 8.     Financial Statements and Supplementary Data                                                            47
Item 9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                   47
 
                                                             PART III

Item 10.    Directors and Executive Officers                                                                       47
Item 11.    Executive Compensation                                                                                 48
Item 12.    Security Ownership of Certain Beneficial Owners and Management                                         48
Item 13.    Certain Relationships and Related Transactions                                                         48
 
                                                               PART IV
Item 14.    Exhibits, Financial Statement Schedules and Reports on Form 8-K                                        48
</TABLE>

                           FORWARD-LOOKING STATEMENTS

     This Annual Report on Form 10-K contains forward-looking statements and
information that are based on the beliefs of Plains Resources Inc. and
subsidiaries, as well as assumptions made by, and information currently
available to, the Company. 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 the Company's business strategy, plans and
objectives of management of the Company for future operations. Such statements
reflect the current views of the Company with respect to future events, based on
what they believe are reasonable assumptions. These statements, however, are
subject to certain risks, uncertainties and assumptions, including, but not
limited to (i) uncertainties inherent in the exploration for and development and
production of oil and gas and in estimating reserves, (ii) unexpected future
capital expenditures (including the amount and nature thereof), (iii) impact of
crude oil price fluctuations, (iv) the effects of competition, (v) the success
of the Company's risk management activities, (vi) the availability (or lack
thereof) of acquisition or combination opportunities, (vii) the availability of
adequate supplies of and demand for crude oil in areas of midstream operations,
(viii) the impact of current and future laws and governmental regulations, (ix)
environmental liabilities that are not covered by an indemnity or insurance and
(x) general economic, market or business conditions and (xi) inherent
uncertainties associated with the Year 2000 issues. 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 laws, the Company does
not intend to update these forward-looking statements and information.

                              CERTAIN DEFINITIONS

     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 "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 the
Company's 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 reduced by estimated future
operating expenses, development expenditures and abandonment costs (net of
salvage value) associated therewith (before income taxes), calculated using
product prices in effect on the date of determination, and "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
<PAGE>
 
                                     PART I

ITEM 1.  BUSINESS

     Plains Resources Inc. is an independent energy company engaged in the
acquisition, exploitation, development, exploration and production of crude oil
and natural gas. Through its majority ownership in Plains All American Pipeline,
L.P. ("PAA"), the Company is engaged in the midstream activities of marketing,
transportation, terminalling and storage of crude oil. The Company's upstream
oil and natural gas activities are focused in California in the Los Angeles
Basin (the "LA Basin"), the Arroyo Grande Field and the Mt. Poso Field
(collectively the "California Properties"), the Sunniland Trend of South Florida
(the "Sunniland Trend") and the Illinois Basin in southern Illinois (the
"Illinois Basin"). The Company's midstream activities are concentrated in
California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. The Company's
upstream operations contributed approximately 58% of the Company's earnings
before interest, taxes, depreciation, depletion and amortization ("EBITDA") for
the fiscal year ending December 31, 1998, while the Company's midstream
activities accounted for 42%. The Company conducts its upstream operations in
each of its three core areas through wholly owned subsidiaries. The California
Properties are operated by Stocker Resources, Inc. ("Stocker"), the Sunniland
Trend properties are operated by Calumet Florida, Inc. ("Calumet") and the
Illinois Basin Properties are operated by Plains Illinois Inc. ("Plains
Illinois").

     A wholly-owned subsidiary of the Company, Plains All American Inc. ("PAAI"
or the "General Partner"), is both the general partner and majority owner of
PAA. As a result of its general partner interest and ownership of approximately
17 million common and subordinated units, PAAI holds a 57% interest in PAA. For
financial statement purposes, the assets, liabilities and earnings of PAA are
included in the Company's consolidated financial statements, with the public
unitholders' interest reflected as a minority interest. References to the
Company in this Annual Report on Form 10-K (the "Report") include Plains
Resources Inc. and its subsidiaries, including PAA, except as the context may
otherwise require. The following chart sets forth the organization relationship
of the Company's upstream and midstream subsidiaries:



                             [GRAPH APPEARS HERE]



Upstream Activities

     The Company's upstream business strategy is to increase its proved reserves
and cash flow by exploiting and producing crude oil and associated natural gas
from its existing properties, acquiring additional underdeveloped crude oil
properties and exploring for significant new sources of reserves. The Company
concentrates its acquisition and exploitation efforts on mature but
underdeveloped crude oil producing properties that meet the Company's targeted
criteria. Generally, such properties were previously owned by major integrated
or large independent oil and natural gas companies, have produced significant
volumes 

                                       3
<PAGE>
 
since initial discovery and have significant estimated remaining reserves in
place. Management believes that it has developed a proven record in acquiring
and exploiting underdeveloped crude oil properties where it believes substantial
reserve additions and cash flow increases can be made through improved
production practices and recovery techniques and relatively low risk development
drilling. An integral component of the Company's exploitation effort is to
increase unit operating margins, and therefore cash flow, by reducing unit
production expenses and increasing wellhead price realizations. The Company
seeks to complement these exploitation efforts by pursuing certain higher risk
exploration opportunities that offer potentially higher rewards. As part of its
business strategy, the Company periodically evaluates, and from time to time has
elected to sell, certain of its mature producing properties that it considers to
be nonstrategic or fully valued. Such sales enable the Company to focus on its
core properties, maintain financial flexibility, control overhead and redeploy
the sales proceeds to activities that have potentially higher financial returns.
The Company's marketing of its own crude oil production takes advantage of the
marketing expertise developed through its midstream activities. See "--Midstream
Activities".

     During the five-year period ended December 31, 1998, the Company incurred
aggregate acquisition, exploitation, development, and exploration costs of
approximately $404.4 million, resulting in proved oil and natural gas reserve
additions (including revisions of estimates but excluding production) of
approximately 124.4 million BOE, or $3.25 per BOE, through implementation of its
business strategy. See "Item 2, Properties -- Oil and Natural Gas Reserves".
Approximately 97% of these expenditures were directed toward the acquisition,
exploitation and development of proved reserves while approximately 3% were
incurred on exploration activities.

     To manage its exposure to commodity price risk, the Company's upstream
business routinely hedges a portion of its crude oil production. For 1999, the
Company has entered into various fixed price arrangements that generally provide
the Company with downside price protection on approximately 9,000 barrels of oil
per day at a NYMEX crude oil spot price ("NYMEX Crude Oil Price") of
approximately $18.25 per barrel. Thus, based on the Company's average fourth
quarter 1998 crude oil production rate, these arrangements generally provide the
Company with downside price protection for approximately 45% of its crude oil
production. In addition, the Company also has fixed price arrangements on 2,000
barrels per day in 2000 at a NYMEX Crude Oil Price of $15.30 per barrel, or
approximately 10% of fourth quarter 1998 crude oil production levels.

     The following table sets forth certain information with respect to the
Company's reserves over the last five years. Such reserve volumes and values
were determined under the method prescribed by the Securities and Exchange
Commission (the "SEC"), which requires the application of year-end oil and
natural gas prices for each year, held constant throughout the projected reserve
life. The benchmark NYMEX oil price of $12.05 per barrel used in preparing year-
end 1998 reserve estimates represented the lowest year-end oil price since oil
was deregulated in 1980 and was approximately 34% below the price used in
preparing reserve estimates at the end of 1997. See "Item 2, Properties -- Oil
and Natural Gas Reserves" and "Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations".

<TABLE>
<CAPTION>
                                                                     AS OF OR FOR THE YEAR ENDED DECEMBER 31,
                                                      ----------------------------------------------------------------------  
                                                         1998             1997            1996         1995           1994
                                                      ---------        --------        --------      -------      ----------
                                                                 (IN THOUSANDS, EXCEPT RATIOS AND PER UNIT AMOUNTS)
<S>                                                    <C>              <C>            <C>           <C>        <C>   

Present Value of Proved Reserves                        $226,943 (1)   $510,993        $764,774      $366,780      $ 229,371
 
Proved Reserves
    Crude oil and natural gas liquids (Bbls)             120,208        151,627         115,996        94,408         61,459
    Natural gas (Mcf)                                     86,781         60,350          37,273        43,110         51,009
    Oil equivalent (BOE)                                 134,672 (1)    161,685         122,208       101,593         69,960
 
Reserve Replacement Ratio (2)                                 NM (3)        603% (4)        454%          647% (5)       619%
 
Reserve Replacement Cost per BOE(6)                           NM (3)   $   2.71        $   1.76      $   2.14      $    1.49
 
Total upstream capital costs incurred                   $100,935       $127,378        $ 51,255      $ 84,012      $  40,849
Percentage of total upstream capital
costs attributable to:
    Acquisition                                               10%            34%              7%           71%            48%
    Development                                               88%            65%             88%           27%            38%
    Exploration                                                2%             1%              5%            2%            14%
Year-end NYMEX Crude Oil Price                            $12.05       $  18.34        $  25.92      $  19.55      $   17.76
 
</TABLE>
(footnotes on following page)

                                       4
<PAGE>
 
_______________________
     (1) A large portion of the Company's reserve base (approximately 90% of
         year-end 1998 reserve volumes) is comprised of long-life oil properties
         that are sensitive to crude oil price volatility. By comparison,
         calculating these amounts using a price of $18.34 per barrel, which was
         the NYMEX Crude Oil Price at December 31, 1997, results in a Present
         Value of Proved Reserves of $705 million and estimated net proved
         reserves of 219 million BOE. Such information is based upon reserve
         reports prepared by independent petroleum engineers, in accordance with
         the rules and regulations of the SEC, except that it uses the same
         crude oil price used in preparing year-end 1997 reserve information.
         See "Item 7, Management's Discussion and Analysis of Financial
         Condition and Results of Operations -- Capital Resources, Liquidity and
         Financial Condition -- Changing Oil and Natural Gas Prices".
     (2) 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 ("Reserve Additions"), by (b) each
         respective years' production.
     (3) NM -- Due to negative volume revision related solely to price, such
         information is not meaningful. Based upon a NYMEX Crude Oil Price of
         $18.34 per barrel, the 1998 Reserve Replacement Ratio and Reserve
         Replacement Cost per BOE were 819% and $1.53, respectively.
     (4) 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.
     (5) 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.
     (6) 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

     The Company is continually engaged in the exploitation and development of
its existing property base and the evaluation and pursuit of additional
underdeveloped properties for acquisition. The Company focuses on mature but
underdeveloped producing crude oil properties in areas where the Company
believes 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, the Company seeks to
increase production rates and improve a property's operating margin by reducing
unit production costs and enhancing the marketing arrangements of the oil
production.

     Once the Company identifies a prospective property for acquisition, it
conducts a technical review of existing production and operating practices to
identify any previously unrecognized 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
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 the
Company's offer to purchase.

     The Company typically seeks to acquire a majority interest in the
properties it has identified and to act as operator of those properties. The
Company has 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 the Company
successfully purchases such properties, it then implements its 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, the Company may also seek
to increase its interest in the properties through acquisitions of offsetting
acreage, farmout drilling arrangements and the purchase of minority interests in
the properties.

     By implementing its exploitation plan, the Company seeks to increase
volumes and expand its reserve base. The results of such activities are
reflected in additions and revisions to proved reserves. During the five-year
period ending December 31, 1998, net additions and revisions to proved reserves
totaled 50.3 million BOE or approximately 162% of cumulative net production for
such period. Such reserves were added at an aggregate average cost of $5.33 per
BOE. Such unit cost reflects the 

                                       5
<PAGE>
 
negative impact of a downward volume revision in 1998 related solely to lower
oil prices at December 31, 1998. This activity excludes reserves added as a
result of the Company's acquisition activities. Reserve additions related solely
to the Company's acquisition activities totaled 74.1 million BOE and were added
at an aggregate average cost of $1.84 per BOE.

     The Company's properties in its three core areas represent 100% of total
proved reserves at December 31, 1998. Such properties were previously owned and
operated by major integrated oil and natural gas companies and are comprised of
underdeveloped crude oil properties believed by the Company to have significant
upside potential that can be evaluated through development and exploitation
activities. During 1999, the Company estimates it will spend approximately $64
million on the development and exploitation of its California, Sunniland Trend
and Illinois Basin Properties. Set forth below is a discussion of such
properties.

  Current Exploitation Projects

     California Properties. Before the Company acquired it in May 1992, Stocker
was a sole purpose company formed in 1990 to acquire substantially all of
Chevron USA's ("Chevron") producing oil properties in the LA Basin. Following
the initial acquisition, the Company expanded its 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. All of
the Company's properties in the LA Basin acquired prior to 1997 are collectively
referred to herein as the "LA Basin Properties". The LA Basin Properties consist
of long-life reserves discovered at various times between 1924 and 1966, and
through December 31, 1998, the LA Basin Properties have produced over 426 MMBbls
of oil and 364 Bcf of natural gas. The Company has 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, average daily production from this area, net to the
Company's interest, has increased from approximately 6,700 BOE per day in 1992
to an average of 11,100 BOE per day during the fourth quarter of 1998.

     The Company has expended approximately $156.5 million in direct
acquisition, development and exploitation capital on the LA Basin Properties.
From the effective dates of acquisition through December 31, 1998, net
production from such properties totaled 22.2 million BOE, generating cumulative
net margin (oil and natural gas revenue less production expenses) and proceeds
from minor property sales of approximately $170.6 million. Total estimated
proved reserves attributable to the LA Basin Properties have increased from 17.7
million BOE at initial acquisition to approximately 63 million BOE at December
31, 1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel.
Based on $18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end
1997 reserve information, total estimated proved reserves were 81.1 million BOE
at December 31, 1998. As a result, The Company's aggregate reserve addition cost
to date for the LA Basin Properties is approximately $1.83 per BOE based on a
NYMEX Crude Oil Price of $12.05 per barrel, and $1.51 per BOE based on $18.34
per barrel. During 1998, the unit gross margin for this area averaged $7.14 per
BOE. Estimated future net revenues and the Present Value of Proved Reserves at
December 31, 1998, were estimated at $326.5 million and $161.1 million,
respectively, based on a NYMEX Crude Oil price of $12.05 per barrel, and $733.6
million and $354.6 million, respectively, based on $18.34 per barrel. The
Company estimates it will spend approximately $27 million during 1999 on the
further development and exploitation of the LA Basin Properties.

     The Company expanded its operations in the LA Basin with the acquisition of
the Montebello Field (the "Montebello Acquisition"), and expanded into other
California areas with the acquisition of the Arroyo Grande Field (the "Arroyo
Grande Acquisition") and the Mt. Poso Field (the "Mt. Poso Acquisition").
Combined, these three fields added approximately 51 million BOE to the Company's
proved reserves at the acquisition dates.

     In March 1997, the Company completed the acquisition of Chevron's interest
in the Montebello Field for approximately $25 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
includes approximately 450 acres of surface fee land. The Montebello Field,
which is located approximately 15 miles from the Company's existing LA Basin
operations, has produced approximately 108 MMBbls of oil and 100 Bcf of natural
gas since its discovery in 1917 and added approximately 23 MMBbls of oil
equivalent to the Company's proved reserves at the acquisition date. Average
daily production from this field, net to the Company's interest, has increased
from approximately 930 BOE at the acquisition date to an average of
approximately 1,520 BOE per day during the fourth quarter of 1998. Estimated
total proved reserves and the Present Value of Proved Reserves at December 31,
1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel were
8.3 MMBbls and $11 million, respectively. Based on $18.34 per barrel, the NYMEX
Crude Oil Price used in preparing year-end 1997 reserve information, proved
reserves and the Present Value of Proved Reserves were 23.3 MMBbls and $58
million, respectively, at 

                                       6
<PAGE>
 
December 31, 1998. The Company estimates that it will spend approximately $11
million during 1999 on the development and exploitation of the Montebello Field.

     In November 1997, the Company 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 oil in place.
The assets acquired include surface and development rights to approximately
1,000 acres included in the 1,500 acre unit. The field is under continuous steam
injection and as of the acquisition date was producing approximately
1,600 barrels (approximately 1,500 barrels net to the Company's interest) of
approximately 14 (degrees) API gravity oil per day from 70 wells and added
approximately 20 MMBbls to the Company's proved reserves. The aggregate
consideration for the Arroyo Grande Acquisition consisted of (i) rights to a
non-producing property interest conveyed to Shell, (ii) the issuance of
46,600 shares of Series D Cumulative Convertible Preferred Stock (the "Series D
Preferred Stock") with an aggregate stated value of $23.3 million, and (iii) a
five-year warrant to purchase 150,000 shares of the Company's common stock
("Common Stock") at $25 per share. No proved reserves had been assigned to the
rights to the property interest conveyed. Due to low crude oil prices throughout
1998, the Company delayed certain of its exploitation activities on the Arroyo
Grande Field and focused on reducing operating expenses. Unit production
expenses for the Arroyo Grande Field, which averaged $9.36 per BOE at the
acquisition date, averaged $5.82 per BOE during the fourth quarter of 1998.
Estimated total proved reserves and the Present Value of Proved Reserves at
December 31, 1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05
per barrel were 34 MMBbls and $3 million, respectively. Based on $18.34 per
barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve
information, proved reserves and the Present Value of Proved Reserves were
63 MMBbls and $118 million, respectively, at December 31, 1998. The Company
estimates that it will spend approximately $5 million during 1999 on the
development and exploitation of the Arroyo Grande Field.

     During 1998, the Company 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. Since its discovery in 1926,
the Mt. Poso Field has produced approximately 200 MMBbls of oil. At acquisition,
the field was producing 1,200 barrels of oil per day of 15-17 degree API gravity
crude. Estimated total proved reserves and the Present Value of Proved Reserves
at December 31, 1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05
per barrel were 8 MMBbls and $14 million, respectively. Based on $18.34 per
barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve
information, proved reserves and the Present Value of Proved Reserves were 8
MMBbls and $46 million, respectively, at December 31, 1998. The Company
estimates that it will spend approximately $8 million during 1999 on the
development and exploitation of the Mt. Poso Field.

     As with its other California properties, the Company intends to
aggressively exploit the properties it acquired in 1997 and 1998 to evaluate
additional reserve potential identified during its acquisition analyses. In
addition, the Company's exploitation plans for these properties target improving
the unit gross margin by decreasing unit production expenses and increasing
production volumes through production enhancement activities similar to those
employed in its other California properties.

     Sunniland Trend Properties. During the first quarter of 1993, the Company
acquired all of the capital stock of Calumet for approximately $5 million.
Calumet was organized in February 1993 to purchase and operate a 50% working
interest in six producing fields in South Florida located in the Sunniland Trend
and previously owned and operated by Exxon Corporation ("Exxon"). During 1994,
Calumet acquired the remaining 50% working interest in the Sunniland Trend
Properties, increasing its working interest to approximately 100% and adding
approximately five million barrels of oil to its proved reserve base at the
acquisition date. The Company's aggregate interest in such properties is
referred to as the "Sunniland Trend Properties". The aggregate purchase price
for the additional 50% interest was approximately $13.6 million, including the
issuance of a five-year warrant valued at $2 million to purchase 750,000 shares
of Common Stock at an exercise price of $6.00 per share. The Sunniland Trend was
discovered by Exxon in 1943, and the properties have produced approximately 94
MMBbls of oil through December 31, 1998. At the time of acquisition, production
from the properties was about 900 barrels of oil per day net to the Company. As
a result of development drilling on the property, the implementation of
exploitation activities designed primarily to repair failed wells and to
increase the fluid lift capacity of certain wells and the acquisition of the
remaining 50% working interest, the Company's net production increased to an
average of 4,200 barrels of oil per day during the fourth quarter of 1998.

     The Company has expended approximately $75.6 million in direct acquisition,
development and exploitation capital on the Sunniland Trend Properties. From the
effective dates of acquisition through December 31, 1998, net production from
such properties totaled 8.1 MMBbls, generating cumulative net margin of
approximately $55.8 million. Total estimated proved reserves attributable to the
Sunniland Trend Properties have increased from approximately 5.0 MMBbls at
initial acquisition to approximately 9.3 MMBbls based on the year-end 1998 NYMEX
Crude Oil Price of $12.05 per barrel. Based on $18.34 per barrel, the NYMEX
Crude Oil Price used in preparing year-end 1997 reserve information, total
estimated proved reserves were 

                                       7
<PAGE>
 
20.4 MMBbls at December 31, 1998. As a result, the Company's aggregate reserve
addition cost to date for the Sunniland Trend Properties is approximately $4.36
per BOE based on a NYMEX Crude Oil Price of $12.05 per barrel, and $2.65 per BOE
based on $18.34 per barrel. During 1998, the unit gross margin for this area
averaged $5.22 per BOE. At December 31, 1998, the Present Value of Proved
Reserves was estimated at $1.6 million and $60.3 million, respectively, based on
a NYMEX Crude Oil Price of $12.05 per barrel and $18.34 per barrel,
respectively. During 1999, the Company estimates it will spend approximately $8
million on the further development and exploitation of the Sunniland Trend
Properties. In addition, the Company intends to conduct exploration activities
in this trend during 1999. See "-- Exploration-- Current Exploration Projects --
Sunniland Trend".

     Illinois Basin Properties. In December 1995, the Company acquired all of
Marathon Oil Company's ("Marathon") producing and nonproducing upstream oil and
natural gas assets in the Illinois Basin (the "Illinois Basin Properties"). This
acquisition was effective as of November 1, 1995. At the acquisition date, the
Company added approximately 17.3 MMBbls of oil to its proved reserve base. The
aggregate purchase price, including associated closing costs, was $51.5 million,
comprised of 798,143 shares of Common Stock valued at $6.5 million and $45.0
million cash. The majority of the cash portion was funded with the proceeds of a
$42 million bank facility. The Illinois Basin Properties consist of long-life
oil reserves. The largest field included in the Illinois Basin Properties was
discovered in 1905 and has produced over 411 MMBbls of oil through December 31,
1998.

     The Company has expended approximately $76.1 million in direct acquisition,
development and exploitation capital on the Illinois Basin Properties. From the
effective date of acquisition through December 31, 1998, net production from
such properties totaled 4.1 MMBbls, generating cumulative net margin of
approximately $40.7 million. The Company's 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 $8.60 per BOE during 1998. Total
estimated proved reserves attributable to the Illinois Basin Properties were
17.3 MMBbls at initial acquisition as compared to approximately 12.0 MMBbls
based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel. Based on
$18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end 1997
reserve information, total estimated proved reserves were 22 MMBbls at December
31, 1998. As a result, the Company's aggregate reserve addition cost to date for
the Illinois Basin Properties is approximately $4.73 per BOE based on a NYMEX
Crude Oil Price of $12.05 per barrel, and $2.87 per BOE based on $18.34 per
barrel. Estimated future net revenues and the Present Value of Proved Reserves
at December 31, 1998, were estimated at $27.9 million and $16.9 million,
respectively, based on a NYMEX Crude Oil Price of $12.05 per barrel, and $143.0
million and $66.5 million, respectively, based on $18.34 per barrel. During
1999, the Company estimates it will spend approximately $5 million implementing
its exploitation plan on the Illinois Basin Properties. The primary focus of
such development and exploitation program during 1999 will be directed towards
aggressively implementing projects to evaluate alternative waterflood
realignment patterns and injection methods.

     General. The Company believes that its properties in its three core areas
hold potential for additional increases in production, reserves and cash flow.
However, the ability of the Company to achieve such increases could be adversely
affected by future decreases in the demand for oil and natural gas, impediments
in marketing production, operating risks, unavailability of capital, adverse
changes in governmental regulations or other currently unforeseen developments.
Accordingly, there can be no assurance that such increases will be achieved.

     The Company believes that attractive acquisition opportunities which fit
the Company's criteria will continue to be made available by both major and
independent oil companies. In addition to more typical acquisitions, the Company
also intends to pursue joint ventures and strategic alliances that provide the
Company the opportunity to use its exploitation and operating skillsets and its
capital without acquiring the entire property interest. While the Company is
continually evaluating such opportunities, there can be no assurance that any of
these efforts will be successful. The Company's 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 the Company has historically acquired producing
properties located only in the continental United States, it from time to time
evaluates, and may in the future seek to acquire, properties located outside the
continental United States.

                                       8
<PAGE>
 
Exploration

  Exploration Strategy

     The Company seeks to complement its strategy of acquiring and exploiting
mature but underdeveloped crude oil properties by dedicating a substantially
smaller portion of its annual capital expenditures to higher risk but
potentially higher reward exploration opportunities. The Company focuses on
exploration opportunities that, if successful, could have a substantial positive
impact on production, cash flow and ultimately proved reserves. However, there
can be no assurance that any of its exploration projects will be successful.

  Current Exploration Projects

     Sunniland Trend. The focus of the Company's exploration effort in the
Sunniland Trend is to identify and evaluate prospects that are analogous to the
existing producing fields in this trend. Although this trend was discovered in
1943, the Company is attempting to integrate historical exploration methods with
recent advancements in seismic technology to evaluate the exploration potential
of the Sunniland Trend.

     In February 1998, the Company and Collier Resources Company ("Collier")
executed an exploration agreement (the "Exploration Agreement") covering
approximately 800,000 mineral acres which are located onshore South Florida in
Collier, Lee and Hendry Counties. Approximately 50% of such acreage is located
under federally owned surface land. Terms of the Exploration Agreement provide
for a minimum term of two years with extensions at the Company's option for up
to eight years. Subject to certain elections, work commitments of the
Exploration Agreement provide for the Company to spend up to $20 million on
exploration activities involving Collier's mineral holdings over the next
several years.

     During the first half of 1999, the Company intends to acquire a 14-square
mile 3D seismic survey over portions of its largest producing field in the
Sunniland Trend and prospective areas adjacent thereto. Also during 1999, the
Company will be required to make certain elections and associated capital
commitments to maintain its control over the entire acreage position covered by
the Exploration Agreement. The Company cannot at this time predict whether or
not it will elect to maintain control over all or a portion of this acreage.
Such elections will be influenced by the results of the 3D seismic survey.

     General. During 1999, the Company estimates it will spend approximately $3
million on exploration activities, principally in the Sunniland Trend. While all
drilling activities are subject to numerous risks, the risks associated with
exploration activities are significantly greater than those associated with the
Company's other exploitation and development activities. There can be no
assurance that any of the Company's current exploration or higher risk
exploitation projects will result in the discovery of proved reserves or the
establishment of commercially viable oil or natural gas production.

     The Company has historically conducted a portion of its exploration
activities with outside partners. When deemed appropriate, the Company will
continue to solicit industry and financial partners to participate in
exploration projects on negotiated terms. The level of the Company's capital
expenditures for these projects, and its working and revenue interests, will
vary depending on the amount and terms of such outside participation.

Disposition of Properties

     The Company periodically evaluates, and from time to time has elected to
sell, certain of its mature producing properties that it considers to be
nonstrategic or fully valued. Such sales enable the Company to focus on its core
properties, maintain financial flexibility, reduce overhead and redeploy the
proceeds therefrom to activities that the Company believes have a higher
potential financial return. During 1997 and 1996, the Company sold nonstrategic
oil and natural gas properties located primarily in Louisiana and Utah for
proceeds of $2.7 million and $3.1 million, respectively. As a result, 100% of
the Company's 1998 year-end proved reserve volumes and proved reserve value were
associated with its properties in California, the Sunniland Trend and the
Illinois Basin.

Midstream Activities

     The Company's midstream activities are conducted through PAA. PAA was
formed in 1998 to acquire and operate the business and assets of the Company's
wholly owned midstream subsidiaries (the "Plains Midstream Subsidiaries"). PAAI,
a wholly owned subsidiary of the Company, is the general partner of PAA. PAA is
engaged in interstate and intrastate crude oil pipeline transportation and crude
oil terminalling and storage activities and gathering and marketing activities.
PAA's operations are concentrated in California, Texas, Oklahoma, Louisiana and
the Gulf of Mexico.

                                       9
<PAGE>
 
  Formation of PAA, Initial Public Offering and Concurrent Transactions

     On November 23, 1998, PAA completed an initial public offering (the "IPO")
of 13,085,000 common units representing limited partner interests (the "Common
Units") in PAA and received therefrom net proceeds of approximately $244.7
million. Concurrently with the closing of the IPO, certain transactions
described in the following paragraphs were consummated in connection with the
formation of PAA. Such transactions and the transactions which occurred in
conjunction with the IPO are referred to in this Report as the "Transactions".
For presentation efficiency, certain capitalized terms are defined under "--
Midstream Activities -- General".

     Certain of the Plains Midstream Subsidiaries were merged into the Company,
which sold the assets of these subsidiaries to PAA in exchange for $64.1 million
and the assumption of $11.0 million of related of indebtedness. At the same
time, the General Partner conveyed all of its interest in the All American
Pipeline and the SJV Gathering System, which it acquired in July 1998 for
approximately $400 million (the "All American Pipeline Acquisition"), to PAA in
exchange for (i) 6,974,239 Common Units, 10,029,619 Subordinated Units and an
aggregate 2% general partner interest in PAA, (ii) the right to receive
Incentive Distributions; and (iii) the assumption by PAA of $175 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 the Company, PAA distributed
approximately $177.6 million to the General Partner and used approximately $3
million of the remaining proceeds to pay expenses incurred in connection with
the Transactions. 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 establish new credit facilities for PAA. The balance, $56.6 million, was
distributed to the Company, which used the cash to repay indebtedness and for
other general corporate purposes.

     In addition, concurrently with the closing of the IPO, PAA entered into a
$225 million bank credit agreement (the "Bank Credit Agreement") that includes
a $175 million term loan facility (the "Term Loan Facility") and a $50 million
revolving credit facility (the "PAA Revolving Credit Facility"). PAA may
borrow up to $50 million under the PAA Revolving Credit Facility for
acquisitions, capital improvements, working capital and general business
purposes. At closing, PAA had $175 million outstanding under the Term Loan
Facility, representing indebtedness assumed from the General Partner.

     In conjunction with the IPO, the Company entered into various agreements
with PAA, including (i) the Omnibus Agreement, providing for the resolution of
certain conflicts arising from the conduct of PAA and the Company of related
businesses and for the General Partner's indemnification of PAA for certain
matters and (ii) the Crude Oil Marketing Agreement (the "Crude Oil Marketing
Agreement") which provides for the marketing by PAA of the Company's crude oil
production.

  Business Activities

     PAA owns and operates a 1,233-mile seasonally heated, 30-inch, common
carrier crude oil pipeline extending from California to West Texas (the "All
American Pipeline") and a 45-mile, 16-inch, crude oil gathering system in the
San Joaquin Valley of California (the "SJV Gathering System"), both of which
the General Partner purchased from The Goodyear Tire and Rubber Company
("Goodyear") in July 1998 for approximately $400 million. PAA also owns and
operates a two million barrel, above-ground crude oil terminalling and storage
facility in Cushing, Oklahoma, (the "Cushing Terminal") that has an estimated
daily throughput capacity of approximately 800,000 barrels per day.

     The All American Pipeline is one of the newest interstate crude oil
pipelines in the United States, having been constructed by Goodyear between 1985
and 1987 at a cost of approximately $1.6 billion, and is the largest capacity
crude oil pipeline connecting California and Texas, with a design capacity of
300,000 barrels per day of heavy crude oil. In West Texas, the All American
Pipeline interconnects with other crude oil pipelines that serve the Gulf Coast
and Cushing, Oklahoma, the largest crude oil trading hub in the United States
and the designated delivery point for NYMEX crude oil futures contracts (the
"Cushing Interchange").

     Production currently transported on the All American Pipeline originates
from the Santa Ynez field operated by Exxon and the Point Arguello field
operated by Chevron, both offshore California, and from the San Joaquin Valley.
Exxon and Chevron, as well as Texaco and Sun Operating L.P., which are other
working interest owners, are contractually obligated to ship all of their
production from these offshore fields on the All American Pipeline through
August 2007. The SJV Gathering System is used primarily to transport crude oil
from fields in the San Joaquin Valley to the All American Pipeline and to
intrastate pipelines owned by third parties. The capacity of the SJV Gathering
System is approximately 140,000 barrels per day. In addition to transporting
third-party volumes for a tariff, PAA is engaged in merchant activities designed
to capture price 

                                       10
<PAGE>
 
differentials between the cost to purchase and transport crude oil to a sales
point and the price received for such crude oil at the sales point.

     The Cushing Terminal was completed in 1993, making it the most modern
facility in the area, and includes state-of-the-art design features. PAA has
initiated an expansion project that will add one million barrels of storage
capacity at an aggregate cost of approximately $10 million. The expansion
project is expected to be completed by the second quarter of 1999. Upon
completion of the expansion project, management believes the Cushing Terminal
will be the third largest facility at the Cushing Interchange (and the largest
not owned by a major oil company) with an estimated 12% of that area's storage
capacity. PAA also owns 586,000 barrels of tank capacity along the SJV Gathering
System, 955,000 barrels of tank capacity along the All American Pipeline and
360,000 barrels of tank capacity at Ingleside, Texas, on the Gulf Coast (the
"Ingleside Terminal").

     PAA's terminalling and storage operations generate revenue from the Cushing
Terminal through a combination of storage and throughput fees from (i) refiners
and gatherers seeking to segregate or custom blend crude oil for refining
feedstocks, (ii) pipelines, refiners and traders requiring segregated tankage
for foreign crude oil, (iii) traders who make or take delivery under NYMEX
contracts and (iv) producers seeking to increase their marketing alternatives.
The Cushing Terminal and PAA's other storage facilities also facilitate PAA's
merchant activities by enabling PAA to buy and store crude oil when the price of
crude oil in a given month is less than the price of crude oil in a subsequent
month (a "contango" market) and to simultaneously sell crude oil futures
contracts for delivery of the crude oil in such subsequent month at the higher
futures price, thereby locking in a profit.

     PAA's gathering and marketing operations include the purchase of crude oil
at the wellhead and the bulk purchase of crude oil at pipeline and terminal
facilities, the transportation of crude oil on trucks, barges or pipelines, and
the subsequent resale or exchange of crude oil at various points along the crude
oil distribution chain. The crude oil distribution chain extends from the
wellhead where crude oil moves by truck and gathering systems to terminal and
pipeline injection stations and major pipelines and is transported to major
crude oil trading locations for ultimate consumption by refineries. In many
cases, PAA matches supply and demand needs by performing a merchant function--
generating gathering and marketing margins by buying crude oil at competitive
prices, efficiently transporting or exchanging the crude oil along the
distribution chain and marketing the crude oil to refineries or other customers.
When there is a higher demand than supply of crude oil in the near term, the
price of crude oil in a given month exceeds the price of crude oil in a
subsequent month (a "backward" market). A backward market has a positive impact
on marketing margins because crude oil gatherers can capture a premium for
prompt deliveries. Likewise, since a premium is paid for prompt deliveries,
storage opportunities are generally not profitable.

     For the year ended December 31, 1998, PAA's pro forma gross margin, EBITDA
and net income totaled $74.1 million, $68.2 million and $43.9 million,
respectively. On a pro forma basis, the All American Pipeline and the SJV
Gathering System accounted for approximately 68% of PAA's gross margin for the
year ended December 31, 1998, while the terminalling and storage activities and
gathering and marketing activities accounted for approximately 32%. Pro forma
information assumes the All American Pipeline Acquisition as well as the IPO
occurred on January 1, 1998.

  Pending Acquisition

     On March 17, 1999, PAA signed a definitive agreement with Marathon Ashland
Petroleum LLC to acquire Scurlock Permian LLC and certain other pipeline assets.
The cash purchase price for the acquisition is approximately $138 million, plus
associated closing and financing costs. The purchase price is subject to
adjustment at closing for working capital on April 1, 1999, the effective date
of the acquisition. Closing of the transaction is subject to regulatory review
and approval, consents from third parties, and customary due diligence. Subject
to satisfaction of the foregoing conditions, the transaction is expected to
close in the second quarter of 1999. PAA has received a financing commitment
from one of its existing lenders, which in addition to other financial resources
currently available to PAA, will provide the funds necessary to complete the
transaction. The definitive agreement provides that if either party fails to
perform its obligations thereunder through no fault of the other party, such
defaulting party shall pay the nondefaulting party $7.5 million as liquidated
damages.

     Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland
Petroleum LLC, is engaged in crude oil transportation, trading and marketing,
operating in 14 states with more than 2,400 miles of active pipelines, numerous
storage terminals and a fleet of more than 225 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, Howard, Martin, Midland, Regan,
Upton and Irion Counties, Texas. The assets to be acquired also include
approximately one million barrels of crude oil used for linefill requirements.

                                       11
<PAGE>
 
  Crude Oil Pipeline Operations

  All American Pipeline

     The All American Pipeline is a common carrier crude oil pipeline system
that transports crude oil produced from fields offshore and onshore California
to locations in California and West Texas pursuant to tariff rates regulated by
the Federal Energy Regulatory Commission ("FERC"). 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 PAA.

     The American Pipeline is comprised of a heated pipeline system which
extends approximately 10 miles from Exxon's onshore facilities at Las Flores on
the California coast to Chevron's onshore facilities at Gaviota, California (24-
inch diameter pipe) and continues from Gaviota approximately 1,223 miles through
Arizona and New Mexico to West Texas (30-inch diameter pipe) where it
interconnects with other pipelines. These interconnecting common carrier
pipelines transport crude oil to the refineries located along the Gulf Coast and
to the Cushing Interchange. At the Cushing Interchange, these pipelines connect
with other pipelines that deliver crude oil to Midwest refiners. The All
American Pipeline also includes various pumping and heating stations, as well as
approximately one million barrels of crude oil storage tank capacity, to
facilitate the transportation of crude oil. The tank capacity is located at
stations in Sisquoc, Pentland and Cadiz, California, and at the station in Wink,
Texas. Unlike many common carrier pipelines, PAA owns approximately 5.0 million
barrels of crude oil that is used to maintain the All American Pipeline's
linefill requirements.

     The All American Pipeline has a designed throughput capacity of 300,000
barrels per day of heavy crude oil and larger volumes of lighter crude oils. As
currently configured, the pipeline's daily throughput capacity is approximately
216,000 barrels of heavy oil. In order to achieve designed capacity, certain
nominal capital expenditures would be required. The All American Pipeline is
operated from a control room in Bakersfield, California with a supervisory
control and data acquisitions ("SCADA") computer system designed to continuously
monitor quantities of crude oil injected in and delivered through the All
American Pipeline as well as pressure and temperature variations. This
technology also allows for the batching of several different types of crude oil
with varying gravities. The SCADA system is designed to enhance leak detection
capabilities and provides for remote-controlled shut-down at every pump station
on the All American Pipeline. Pumping stations are linked by telephone and
microwave communication systems for remote-control operation of the All American
Pipeline which allows most of the pump stations to operate without full time
site personnel.

     PAA performs scheduled maintenance on the pipeline and makes repairs and
replacements when necessary or appropriate. As one of the most recently
constructed major crude oil pipeline systems in the United States, the All
American Pipeline requires a relatively low level of maintenance capital
expenditures. PAA attempts to control corrosion of the pipeline through the use
of corrosion inhibiting chemicals injected into the crude stream, external pipe
coatings and an anode bed based cathodic protection system. PAA monitors the
structural integrity of the All American Pipeline through a program of periodic
internal inspections using electronic "smart pig" instruments. PAA conducts a
weekly aerial surveillance of the entire pipeline and right-of-way to monitor
activities or encroachments on rights-of-way. Maintenance facilities containing
equipment for pipe repair, digging and light equipment maintenance are
strategically located along the pipeline. PAA believes that the All American
Pipeline has been constructed and is 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 standards
of industry practice.

  System Supply

     The All American Pipeline transports several different types of crude oil,
including (i) Outer Continental Shelf ("OCS") 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, (ii) Elk
Hills crude oil, received at Pentland, California from a connection with the SJV
Gathering System and (iii) various crude oil blends received at Pentland from
the SJV Gathering System, including West Coast Heavy and Mojave Blend.

     OCS Supply. Exxon, which owns all of the Santa Ynez production, and
Chevron, Texaco and Sun Operating L.P., which own approximately one-half of the
Point Arguello production, have entered into transportation agreements
committing to transport all of their production from these fields on the All
American Pipeline. These agreements, which expire in August 2007, provide for a
minimum tariff with annual escalations. At December 31, 1998, the tariffs
averaged $1.41 per barrel for deliveries to connecting pipelines in California
and $2.96 per barrel for deliveries to connecting pipelines in West Texas. 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 PAA have
no other means of transporting their production and, therefore, ship their
volumes on the All American Pipeline 

                                       12
<PAGE>
 
at the posted tariffs. During 1998, approximately $33.6 million, or 45%, of
PAA's pro forma gross margin was attributable to volumes received from the Santa
Ynez field and approximately $12.9 million, or 17%, was attributable to volumes
received from 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,
                                                        --------------------------------------------------------------
                                                         1998    1997    1996    1995    1994    1993    1992    1991
                                                        ------  ------  ------  ------  ------  ------  ------  ------  
                                                                             (barrels in thousands)
<S>                                                      <C>    <C>     <C>     <C>     <C>     <C>     <C>     <C> 

        Average daily volumes received from:
          Point Arguello (at Gaviota)                       26      30      41      60      73      63      47      29
          Santa Ynez (at Las Flores)                        68      85      95      92      34      --      --      --        
                                                        ------  ------  ------  ------  ------  ------  ------  ------  
              Total                                         94     115     136     152     107      63      47      29      
                                                        ======  ======  ======  ======  ======  ======  ======  ======  
</TABLE> 

     Absent operational or economic disruptions, PAA anticipates that production
from Point Arguello will continue to decline at percentage rates which
approximate historical decline rates, but that average production received from
the Santa Ynez field for 1999 will generally approximate 60,000 to 65,000
barrels per day. In connection with a proposed transfer of its ownership in
Point Arguello to a private independent oil company, Chevron provided notice to
the other working interest owners of its resignation as operator of the Point
Arguello field. PAA is unable to determine at this time if the proposed transfer
will occur or the consequences any such transfer or the absence of any such
transfer will have on Point Arguello production and the resulting pipeline
transportation.

     According to information published by the Minerals Management Service
("MMS"), significant additional proved, undeveloped reserves have been
identified offshore California which have the potential to be delivered on the
All American Pipeline. Future volumes of crude deliveries on the All American
Pipeline will depend on a number of factors that are beyond PAA's control,
including (i) the economic feasibility of developing the reserves, (ii) the
economic feasibility of connecting such reserves to the All American Pipeline
and (iii) the ability of the owners of such reserves to obtain the necessary
governmental approvals to develop such reserves. The owners of these reserves
are currently participating in a study (California Offshore Oil and Gas Energy
Resources, "COOGER") with various private organizations and regulatory
agencies to determine the best sites to locate onshore facilities that will be
required to handle and process potential production from these undeveloped
fields as well as the best methods of controlling potential environmental
dangers associated with offshore drilling and production. These owners have also
agreed to suspend drilling on the undeveloped leases until the COOGER study is
completed. The COOGER study is anticipated to be completed by June 30, 1999, at
which time owners of these undeveloped reserves must submit their development
plans to the MMS. There can be no assurance that the owners will develop such
reserves, that the MMS will approve development plans or that future regulations
or litigation will not prevent or retard their ultimate development and
production. There also can be no assurance that, if such reserves were
developed, a competing pipeline might not be built to transport the production.
In addition, a June 12, 1998 Executive Order of the President of the United
States extends until the year 2012 a statutory moratorium on new leasing of
offshore California fields. Existing fields are authorized to continue
production, but federal, state and local agencies may restrict permits and
authorizations for their development, and may restrict new onshore facilities
designed to serve offshore production of crude oil. San Luis Obispo and Santa
Barbara counties have adopted zoning ordinances that prohibit development,
construction, installation or expansion of any onshore support facility for
offshore oil and gas activity in the area, unless approved by a majority of the
votes cast by the voters of either county in an authorized election. Any such
restrictions, should they be imposed, could adversely affect the future delivery
of crude oil to the All American Pipeline.

     San Joaquin Valley Supply. In addition to OCS production, crude oil from
fields in the San Joaquin Valley is delivered into the All American Pipeline at
Pentland through connections with the SJV Gathering System and pipelines
operated by EOTT, L.P. and ARCO. The San Joaquin Valley is one of the most
prolific oil producing regions in the continental United States, producing
approximately 591,000 barrels per day of crude oil during the first nine months
of 1998 which accounted for approximately 65% 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.

                                       13
<PAGE>
 
<TABLE> 
<CAPTION> 

                                                                             Year Ended December 31,
                                              ------------------------------------------------------------------------------
                                              1998(1)  1997    1996    1995    1994    1993    1992    1991    1990    1989
                                              ------  ------  ------  ------  ------  ------  ------  ------  ------  ------  
                                                                             (barrels in thousands)
<S>                                           <C>    <C>     <C>     <C>     <C>     <C>     <C>     <C>      <C>     <C>      
        Average daily volumes:
        San Joaquin Valley production            591     584     579    569      578     588     609     634     629     646
        Total California production              780     781     772    764      784     803     835     875     879     907
                (excluding OCS volumes) 

</TABLE> 
__________________________
      (1) Reflects information through September 1998.

     Drilling and exploitation activities have increased in the San Joaquin
Valley over the last few years, primarily due to the change in ownership of
several large fields and technological advances in horizontal drilling and steam
assisted recovery methods that have improved the overall economics of field
development and reductions in the operating costs of these fields. The near term
outlook for any potential production increases has been adversely affected by
the depressed price of oil and related reductions in capital spending plans
announced by several California producers.

     Alaskan North Slope Supply. Historically, the All American Pipeline had
also transported volumes of Alaskan North Slope crude oil. In 1996, the U.S.
government repealed the export ban on crude oil produced from the Alaskan North
Slope which had effectively prohibited the sale of Alaskan North Slope crude oil
to sources outside the U.S. Prior to its repeal, this ban had the impact of
increasing volumes of Alaskan crude oil delivered into the California market.
Shipments of Alaskan North Slope crude oil on the All American Pipeline ceased
in February 1997, shortly after the repeal of the export ban. In addition, ARCO
has sold the only pipeline that could bring Alaskan North Slope crude oil to the
All American Pipeline. This pipeline will be converted to natural gas service
thereby eliminating the physical capability to ship Alaskan North Slope Crude
Oil on the All American Pipeline.

  System Demand

     Deliveries from the All American Pipeline are made to refineries within
California, along the Gulf Coast or in the Midwest through connecting pipelines
of other companies. Demand for crude oil shipped on the All American Pipeline in
each of these markets is affected by numerous factors, including refinery
utilization and crude oil slate requirements, regional crude oil production,
foreign imports, intra-U.S. transfers of crude oil and the price differential
(net of transportation cost) between the California and Midwest markets.

     Deliveries are made to California refineries through connections with
third-party pipelines at Sisquoc, Pentland and Mojave. The deliveries at Sisquoc
and Pentland are OCS crude oil while the deliveries at Mojave are primarily
Mojave Blend. Crude oil transported to West Texas is primarily West Coast Heavy
and is delivered to third-party pipelines at Wink and McCamey, Texas. At Wink,
West Coast Heavy crude is blended with Domestic Sweet Crude to increase the
gravity (the blend is commonly referred to as West Coast Sour), permitting
delivery into third party pipelines that can transport the crude to the Cushing
Interchange. At McCamey, West Coast Heavy and OCS crude oil are delivered to a
third-party pipeline that supplies refiners on the Gulf Coast.

     The following table sets forth All American Pipeline average deliveries per
day within and outside California for each of the years in the five-year period
ended December 31, 1998.

<TABLE> 
<CAPTION> 
                                                        Year Ended December 31,
                                                --------------------------------------
                                                 1998    1997    1996    1995    1994
                                                ------  ------  ------  ------  ------
                                                         (barrels in thousands)
<S>                                             <C>     <C>     <C>     <C>     <C> 
     Average daily volumes delivered to:
        California
          Sisquoc                                   24      21      17      11      21            
          Pentland                                  69      74      71      65      56                
          Mojave                                    22      32       6       -       -             
                                                ------  ------  ------  ------  ------
            Total California                       115     127      94      76      77    
        Texas                                       59      68     113     141     108           
                                                ------  ------  ------  ------  ------
           Total                                   174     195     207     217     185
                                                ======  ======  ======  ======  ======
</TABLE> 

  SJV Gathering System

     The SJV Gathering System is a proprietary pipeline system that only
transports crude oil purchased by entities owned by PAA. As a proprietary
pipeline, the SJV Gathering System is not subject to common carrier regulations
and does not transport 

                                       14
<PAGE>
 
crude oil for third parties. The primary purpose of the pipeline is to gather
crude oil from various sources in the San Joaquin Valley and to blend such crude
oil along the pipeline system in order to deliver either West Coast Heavy or
Mojave Blend into the All American Pipeline. Certain crude streams are
segregated and delivered into either the All American Pipeline or to third party
pipelines connected to the SJV Gathering System.

     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. The SJV Gathering System also includes approximately
586,000 barrels of tank capacity, which has historically been used to facilitate
movements along the pipeline system.

     The SJV Gathering System is operated in conjunction with, and with the same
SCADA system used in the operations of the All American Pipeline. PAA also takes
measures to protect the pipeline from corrosion and routinely inspects the
pipeline using the same procedures and practices employed in the operation of
the All American Pipeline. Like the All American Pipeline, the SJV Gathering
System was constructed and is maintained in all material respects in accordance
with applicable federal, state and local laws and regulations, standards
recommended by the American Petroleum Institute and accepted industry standards
of practice.

     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 and Elk Hills fields. The table below sets forth the
historical volumes received into the SJV Gathering System.

                                               Year Ended December 31,
                                     --------------------------------------
                                      1998    1997    1996    1995    1994
                                     ------  ------  ------  ------  ------
                                              (barrels in thousands)

   Total average daily volumes           85      91      67      50      54

        
     To increase utilization and margins relating to the SJV Gathering System,
PAA has initiated a wellhead gathering, transportation and marketing program in
the San Joaquin Valley. The new program is similar to a program to purchase
crude oil from independent producers successfully implemented by the Plains
Midstream Subsidiaries in Texas, Oklahoma, Kansas and Louisiana under which
volumes increased from 1,300 barrels per day in 1990 to 88,000 barrels per day
in 1998. PAA has committed resources to its new gathering program by hiring an
additional lease buyer, activating an existing truck unloading station and
arranging to make additional connections with other pipeline systems in the San
Joaquin Valley, including access into the Pacific Pipeline. In addition, PAA has
entered into an arrangement with various parties whereby PAA has reserved up to
40,000 barrels per day of capacity for movements into the Pacific Pipeline, and
all crude oil sourced by one such party from the Midway Sunset field will be
delivered by PAA into the Pacific Pipeline via the SJV Gathering System.
Construction of the Pacific Pipeline, a pipeline system that will service the LA
Basin, was completed in early 1999. See "-- Competition".

  Terminalling and Storage Activities and Gathering and Marketing Activities

  Terminalling and Storage

     The Cushing Terminal was constructed in 1993 to capitalize on the crude oil
supply and demand imbalance in the Midwest 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 PAA's merchant activities relating to its
lease gathering and bulk trading activities. The Ingleside Terminal was
constructed in 1979 and purchased by the Plains Midstream Subsidiaries in 1996
to enhance its lease gathering activities in South Texas.

     The Cushing Terminal has a total storage capacity of two million barrels,
comprised of fourteen 100,000 barrel tanks and four 150,000 barrel tanks 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 up to 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. A one million barrel expansion project to add four 250,000 barrel
tanks is currently underway at the Cushing Terminal with completion targeted for
the second quarter of 1999.

                                       15
<PAGE>
 
     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, certain attributes were
incorporated into the design of the Cushing Terminal including (i) multiple,
smaller tanks to facilitate simultaneous handling of multiple crude varieties in
accordance with normal pipeline batch sizes, (ii) dual header systems connecting
each tank to the main manifold system to facilitate efficient switching between
crude grades with minimal contamination, (iii) bottom drawn sump pumps that
enable each tank to be efficiently drained down to minimal remaining volumes to
minimize crude contamination and maintain crude integrity, (iv) a mixer on each
tank to facilitate blending crude grades to refinery specifications, and (v) 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, PAA believes it is favorably
positioned to serve the needs of Midwest refiners to handle increasing varieties
of crude transported through the Cushing Interchange.

     The Cushing Terminal also incorporates numerous environmental and
operational safeguards. PAA believes that its terminal is the only one at the
Cushing Interchange for 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 above
ground pipelines. Like the All American Pipeline and the SJV Gathering System,
the Cushing Terminal is operated by a SCADA system 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 floating roof that minimizes air
emissions and prevents the possible accumulation of potentially flammable gases
between fluid levels and the roof of the tank; and a foam line that, in the
event of a fire, is connected to the automated fire water distribution system.

     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 a NYMEX delivery point and a cash market hub, the Cushing
Interchange serves as the 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 Ingleside Terminal was constructed in 1979 and purchased by the Plains
Midstream Subsidiaries in 1996 to enhance its lease gathering activities in
South Texas. The Ingleside Terminal is located near the Gulf Coast port of
Corpus Christi, Texas. The Ingleside Terminal is comprised of 11 tanks ranging
in size from a minimum of 15,000 barrels to a maximum of 50,000 barrels. Three
of these tanks are heated, which allows for storage of heavier products. The
terminal has access to the receipt of crude oil and refined petroleum products
from trucks and barges. Likewise, the terminal can deliver crude oil and refined
petroleum products to barges and trucks. PAA leases a barge dock approximately
one mile from the Ingleside Terminal and is connected to the dock by four
pipelines ranging in size from 8 inches to 12 inches in diameter. The dock lease
can be extended in five-year intervals through 2021.

     PAA's terminalling and storage operations generate revenue through
terminalling and storage fees paid by third parties as well as by utilizing the
tankage in conjunction with its merchant activities. Storage fees are generated
when PAA leases tank capacity to third parties. Terminalling fees, also referred
to as throughput fees, are generated when PAA receives crude oil from one
connecting pipeline (generally received in batch sizes of 25,000 to 400,000
barrels) and redelivers 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 (which is generally three to ten days). Both terminalling and
storage fees are generally earned from (i) refiners and gatherers that segregate
or custom blend crudes for refining feedstocks, (ii) pipeline operators,
refiners or traders that need segregated tankage for foreign cargoes, (iii)
traders who make or take delivery under NYMEX contracts and (iv) producers and
resellers that seek to increase their marketing alternatives. The tankage that
is used to support PAA's arbitrage activities position PAA to capture margins in
a contango market or when the market switches from contango to backwardation.

                                       16
<PAGE>
 
     The following table sets forth the daily throughput volumes for PAA's
terminalling and storage operations, and quantity of tankage leased to third
parties from 1994 through 1998.

<TABLE> 
<CAPTION> 
                                                                              Year Ended December 31,
                                                                      ---------------------------------------
                                                                       1998    1997    1996    1995    1994
                                                                      ------  ------  ------  ------  -------
                                                                               (barrels in thousands)
 <S>                                                                 <C>     <C>     <C>     <C>     <C>        
        Throughput volumes (average daily volumes):
          Cushing Terminal                                               69      69      56      43       29 
          Ingleside Terminal                                             11       8       3       -        -           
                                                                     ------  ------  ------  ------  -------
                Total                                                    80      77      59      43       29     
                                                                     ======  ======  ======  ======  =======

          Storage leased to third parties (monthly aveage volumes):
            Cushing Terminal                                            890     414     203     208      464 
            Ingleside Terminal                                          260     254     211       -        -
                                                                     ------  ------  ------  ------  -------
                  Total                                               1,150     668     414     208      464    
                                                                     ======  ======  ======  ======  =======
</TABLE> 


     PAA has committed 1.5 million barrels of its capacity at the Cushing
Terminal to storage arrangements with third parties through mid-1999.

  Gathering and Marketing Activities

     PAA's gathering and marketing activities are primarily conducted in
Louisiana, Texas, Oklahoma and Kansas and include (i) purchasing crude oil from
producers at the wellhead and in bulk from aggregators at major pipeline
interconnects and trading locations, (ii) transporting such crude oil on its own
proprietary gathering assets or assets owned and operated by third parties when
necessary or cost effective, (iii) exchanging such 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 (iv) marketing crude
oil to refiners or other resellers. For the year ended December 31, 1998, PAA
purchased approximately 88,000 barrels per day of crude oil directly at the
wellhead. PAA purchases crude oil from producers under contracts that range in
term from a thirty-day evergreen to two years. Gathering and marketing
activities are characterized by large volumes of transactions with lower margins
relative to pipeline and terminalling and storage operations.

     The following table shows the average daily volume of PAA's lease gathering
and bulk purchases from 1995 through 1998.

                                                 Year Ended December 31,
                                             ------------------------------
                                              1998    1997    1996    1995
                                             ------  ------  ------  ------ 
                                                  (barrels in thousands)  

                Lease gathering                  88      71      59      46
                Bulk purchases                   95      49      32      10 
                                             ------  ------  ------  ------ 
                    Total volumes               183     120      91      56
                                             ======  ======  ======  ====== 

     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 PAA's field personnel to purchase and
transport the crude oil to market. PAA utilizes pipelines, trucks and barges
owned and operated by third parties and PAA's truck fleet and gathering
pipelines to transport the crude oil to market. PAA owns approximately 29
trucks, 30 tractor-trailers and 22 injection stations.

     Pursuant to the Crude Oil Marketing Agreement, PAA is the exclusive
marketer/purchaser for all of the Company's equity crude oil production. The
Crude Oil Marketing Agreement provides that PAA will purchase for resale at
market prices all of the Company's crude oil production for which it will charge
a fee of $0.20 per barrel. This fee will be adjusted every three years based
upon then existing market conditions. The Crude Oil Marketing Agreement will
terminate upon a "change of control" of the Company or the General Partner.

     Bulk Purchases. In addition to purchasing crude oil at the wellhead from
producers, PAA purchases 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. PAA purchases crude oil in bulk when it believes 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 PAA's
bulk purchases 

                                       17
<PAGE>
 
fluctuate from period to period. PAA's 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. PAA sells its crude oil to
major integrated oil companies and independent refiners in various types of sale
and exchange transactions, generally at market-responsive prices for terms
ranging from one month to three years.

     As PAA purchases crude oil, it establishes 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, PAA seeks
to maintain a position that is substantially balanced between crude oil
purchases and sales and future delivery obligations. PAA from time to time
enters into fixed price delivery contracts, floating price collar arrangements,
financial swaps and oil futures contracts as hedging devices. To ensure a fixed
price for future production, PAA may sell a futures contract and thereafter
either (i) make physical delivery of its crude oil to comply with such contract
or (ii) buy a matching futures contract to unwind its futures position and sell
its crude oil to a customer. PAA's policy is generally to purchase only crude
oil for which it has a market and to structure its sales contracts so that crude
oil price fluctuations do not materially affect the gross margin which it
receives. PAA does 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 PAA to indeterminable 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. PAA's management monitors crude oil
volumes, grades, locations and delivery schedules and coordinates marketing and
exchange opportunities, as well as NYMEX hedging positions. This coordination
ensures that PAA's NYMEX hedging activities are successfully implemented.

     Crude Oil Exchanges. PAA pursues exchange opportunities to enhance margins
throughout the gathering and marketing process. When opportunities arise to
increase its margin or to acquire a grade of crude oil that more nearly matches
its delivery requirement or the preferences of its refinery customers, PAA
exchanges physical crude oil with third parties. These exchanges are effected
through contracts called exchange or buy-sell agreements. Through an exchange
agreement, PAA agrees to buy crude oil that differs in terms of geographic
location, grade of crude oil or delivery schedule from crude oil it has
available for sale. Generally, PAA enters into exchanges to acquire crude oil at
locations that are closer to its end markets, thereby reducing transportation
costs and increasing its margin. PAA also exchanges its 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 enters 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 its delivery contracts.

     Producer Services. Crude oil purchasers who buy from producers compete on
the basis of competitive prices and highly responsive services. PAA believes
that its ability to offer high-quality field and administrative services to
producers is a key factor in maintaining volumes of purchased crude oil and
obtaining 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 PAA), 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, PAA 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. PAA's merchant activities involve the purchase of crude oil for
resale and require significant extensions of credit by PAA's suppliers of crude
oil. In order to assure PAA's ability to perform its obligations under crude
purchase agreements, various credit arrangements are negotiated with PAA's crude
oil suppliers. Such arrangements include open lines of credit directly with PAA
and standby letters of credit issued under the Letter of Credit Facility. See
"Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations--Capital Resources, Liquidity and Financial Condition."

                                       18
<PAGE>
 
     When PAA markets crude oil, it must determine the amount, if any, of the
line of credit to be extended to any given customer. If PAA determines that a
customer should receive a credit line, it must then decide on the amount of
credit that should be extended. Since 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 PAA's business. PAA
believes its sales are made to creditworthy entities or entities with adequate
credit support.

     Credit review and analysis are also integral to PAA's 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, PAA must determine whether the
operator has sufficient financial resources to make such payments and
distributions and to indemnify and defend PAA 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

     The following table presents certain information with respect to the
Company's upstream oil and natural gas producing activities and its midstream
marketing, transportation, terminalling and storage activities during the three
years ended December 31, 1998, 1997 and 1996:
<TABLE> 
<CAPTION> 

                                                                      Years Ended December 31,
                                                             ------------------------------------------   
                                                                1998            1997            1996
                                                             ---------        ----------     ----------       
                                                                            (in thousands)
        <S>                                                  <C>              <C>            <C>         
        Sales to unaffiliated customers:
          Oil and natural gas                               $  102,754        $  109,403     $   97,601      
          Marketing, transportation and storage              1,129,689           752,522        531,698        
        Operating margins:
          Oil and natural gas(1)                            $   51,927        $   63,917     $   58,866        
          Marketing, transportation and storage(2)              38,361            12,480          9,531
        Identifiable assets:
          Oil and natural gas                               $  364,059        $  407,200     $  307,692          
          Marketing, transportation and storage                610,208           149,619        122,557
  
</TABLE> 
____________________
        (1) Consists primarily of oil and natural gas sales less production
            expenses.
        (2) Consists primarily of marketing, transportation and storage sales
            less purchases, transportation and storage expenses. Includes
            approximately $2.5 million of operating profit attributable to
            contango market transactions in 1998 and in 1997.

     Operating profits as a percentage of sales are significantly lower for the
Company's marketing, transportation and storage activities than for its oil and
natural gas producing activities because the cost of crude oil purchased for
resale is higher, as a percentage of sales price, than the Company's cost to
produce oil and natural gas. See "-- Midstream Activities".

General

     The Company was incorporated under the laws of the State of Delaware in
1976. The Company's executive offices are located at 500 Dallas, Suite 700,
Houston, Texas 77002, and its telephone number is (713) 654-1414.

Product Markets and Major Customers

     The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and natural gas. Historically, the
markets for oil and natural gas have been volatile and are likely to continue to
be volatile in the future. The prices received by the Company for its oil and
natural gas production and the levels of such production are subject to wide
fluctuations and depend on numerous factors beyond the Company's control,
including seasonality, the condition of the United States economy (particularly
the manufacturing sector), foreign imports, political conditions in other 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 oil and natural gas have had, and could
have in the future, an adverse effect on the carrying value of the Company's
proved reserves and the Company's revenues, profitability and cash flow. The
Company's 1998 earnings were adversely affected by low crude oil prices
throughout 1998. See "Item 7, Management's 

                                       19
<PAGE>
 
Discussion and Analysis of Financial Condition and Results of Operations --
Capital Resources, Liquidity and Financial Condition -- Changing Oil and Natural
Gas Prices".

     In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company from time to time enters into fixed price delivery
contracts, floating price collar arrangements, financial swaps and oil and
natural gas futures contracts as hedging devices. To ensure a fixed price for
future production, the Company may sell a futures contract and thereafter either
(i) make physical delivery of its product to comply with such contract or (ii)
buy a matching futures contract to unwind its futures position and sell its
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 the Company to the risk of financial loss in certain
circumstances, including instances where production is less than expected, the
Company's customers fail to purchase or deliver the contracted quantities of oil
or natural gas, or a sudden, unexpected event materially impacts oil or natural
gas prices. Such contracts may also restrict the ability of the Company to
benefit from unexpected increases in oil and natural gas prices. See "Item 2,
Properties -- Oil and Natural Gas Reserves".

     Substantially all of the Company's California crude oil and natural gas
production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could result in the Company having to find
transportation alternatives, increased transportation costs to the Company or
involuntary curtailment of a significant portion of its crude oil and natural
gas production.

     Certain of the Company's 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 the Company's natural gas, may in the future adversely affect the
Company's ability to sell its natural gas production.

     All of the Company's natural gas production in California is produced as a
by-product of the Company's crude oil production. As a result of high inert
content, the Company's gas production in the Montebello Field is difficult to
market and currently is delivered for no value. To ensure that the Company is
able to develop and produce its oil reserves without restriction due to lack of
markets, the Company has made arrangements with the former owner of the
Montebello Field to take its natural gas production volumes at no incremental
value when the Company is unable to find a market for the gas. The Company has
improved the quality of the gas through upgrading and refining the existing gas
collection system, as well as adding additional processing capacity. The Company
believes that this will enable it to obtain an alternate market for the gas
production in 1999, although such market cannot be assured.

     Before 1985, substantially all of the Company's natural gas production was
sold directly to pipeline companies which were responsible for resale and
transportation of the natural gas to end-users. Since that time, however, with
the adoption of various orders by the FERC (See "-- Regulation -- Transportation
and Sale of Natural Gas") and the deregulation of natural gas pursuant to the
Natural Gas Policy Act of 1978 ("NGPA") and the Natural Gas Wellhead Decontrol
Act of 1989 (the "Decontrol Act"), the FERC has actively promoted competition in
the nationwide market for natural gas and has encouraged pipelines to
significantly reduce their role as merchants of natural gas and to make
transportation services available on an "open-access", nondiscriminatory basis.
Since these regulatory initiatives were begun, natural gas producers such as the
Company have been able to sell their natural gas supplies directly to utilities
and other end-users.

     In addition to the regulatory changes discussed above, deregulation of
natural gas prices under the NGPA and the Decontrol Act has increased
competition and volatility of natural gas prices. Since demand for natural gas
is generally highest during winter months, prices received for the Company's
natural gas are subject to seasonal variations and other fluctuations. All of
the Company's natural gas production is currently sold under various
arrangements at spot indexed prices. In certain instances, the Company enters
into financial arrangements to hedge its exposure to spot price fluctuations.
See "Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Capital Resources, Liquidity and Financial Condition --
Changing Oil and Natural Gas Prices" and "Item 2, Properties -- Production and
Sales".

     Sales to Sempra Energy Trading Corporation ("Sempra") (formerly AIG Trading
Corporation) and Koch Oil Company ("Koch") accounted for 27% and 15%,
respectively, of the Company's total revenue (exclusive of interest and other
income) during 1998. Customers accounting for more than 10% of total revenue for
1997 and 1996 were as follows:  1997 -- Koch -27% and Sempra - 11%, 1996 -- Koch
- 16% and Basis Petroleum, Inc. (formerly Phibro Energy USA, Inc.) - 11%. No
other single customer accounted for as much as 10% of total sales during 1998,
1997 or 1996. Additionally during 1998, Tosco Refining Company and Scurlock
Permian LLC accounted for approximately 50% and 17%, respectively, of the
Company's oil and gas sales. See "Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations".

                                       20
<PAGE>
 
Competition

  Oil and Natural Gas Producing Activities

     The Company's 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 the Company's larger competitors
possess and employ financial and personnel resources substantially greater than
those available to the Company. Such companies are able to pay more for
productive oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than the Company's financial or human resources permit. The Company's
ability to acquire additional properties and to discover reserves in the future
will depend on its 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

     The All American Pipeline encounters competition from foreign oil imports
and other pipelines that serve the California market and the refining centers in
the Midwest and on the Gulf Coast.

     Construction of the Pacific Pipeline, a  new pipeline connecting the San
Joaquin Valley to refinery markets in the LA Basin area, was completed in the
first quarter of 1999. The Pacific Pipeline is expected to compete with PAA for
transportation volumes. PAA expects that certain volumes currently transported
on the All American Pipeline may be redirected to Los Angeles on such pipeline.

     Competition among common carrier pipelines is based primarily on
transportation charges, access to producing areas and demand for the crude oil
by end users. PAA believes that high capital requirements, environmental
considerations and the difficulty in acquiring rights of way and related permits
make it unlikely that a competing pipeline system comparable in size and scope
to the All American Pipeline will be built in the foreseeable future.

     The Company faces intense competition in its terminalling and storage
activities and gathering and marketing activities. Its 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 PAA's and control substantially
greater supplies of crude oil.

Regulation

     The Company's operations are subject to extensive and continually changing
regulation, as legislation affecting the oil and natural gas industry is
constantly reviewed for amendment and expansion. Many departments and agencies,
both federal and state, are authorized by statute to issue and have issued rules
and regulations binding on the oil and natural gas industry and its individual
participants. The failure to comply with such rules and regulations can result
in substantial penalties. The regulatory burden on the oil and natural gas
industry increases the Company's cost of doing business and, consequently,
affects its profitability. However, the Company does not believe that it is
affected in a significantly different manner by these regulations than are its
competitors in the oil and natural gas industry. Due to the myriad and complex
federal and state statutes and regulations which may affect the Company directly
or indirectly, the following discussion of certain statutes and regulations
should not be relied upon as an exhaustive review of all regulatory
considerations affecting the Company's operations.

  OSHA

  The Company is also subject to the requirements of the Federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The Company
believes that its operations substantially comply with OSHA requirements,
including general industry standards, record keeping requirements and monitoring
of occupational exposure to regulated.

  Commodities Regulation

     The Company's hedging activities are subject to constraints imposed under
the Commodity Exchange Act and the rules of the NYMEX. The futures and options
contracts that are traded on the NYMEX are subject to strict regulation by the
Commodity Futures Trading Commission.

                                       21
<PAGE>
 
  Trucking Regulation

     The Company operates a fleet of trucks to transport crude oil as a private
carrier. As a private carrier, the Company is subject to certain motor carrier
safety regulations issued by the Department of Transportation ("DOT"). 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. The Company is also
subject to OSHA with respect to its trucking operations.

  Pipeline Regulation

     PAA's pipelines are subject to regulation by the DOT 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 PAA and other pipeline
operators to comply with regulations issued 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 (the "Pipeline Safety Act") amends the
HLPSA in several important respects. It requires the Research and Special
Programs Administration ("RSPA") of DOT 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
DOT of pipeline operator qualification rules requiring minimum training
requirements for operators, and requires that pipeline operators provide maps
and records to RSPA. It also authorizes RSPA 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. PAA believes that its pipeline operations are in substantial
compliance with applicable HLPSA and Pipeline Safety Act requirements.
Nevertheless, significant expenses could be incurred 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. PAA
does not anticipate any significant problems in complying with applicable state
laws and regulations in those states in which it operates.

  Transportation and Sale of Crude Oil

     In October 1992 Congress passed the Energy Policy Act of 1992 ("Energy
Policy Act"). 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: (i) 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; (ii) the complainant was contractually barred
from challenging the rate prior to enactment; or (iii) a provision of the tariff
is unduly discriminatory or preferential.

     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 

                                       22
<PAGE>
 
for new services can be established through a cost-of-service proceeding or
through an uncontested agreement between the pipeline and 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.

     In a recent 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.

     There is also pending at the FERC a proceeding 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 September 25, 1997, the
administrative law judge in the Santa Fe Proceeding issued an initial decision
addressing various aspects of the tax allowance issue as it affects publicly
traded partnerships, as well as various technical issues involving the
application of the FERC oil pipeline ratemaking methodology. The administrative
law judge's initial decision in the Santa Fe Proceeding is currently pending
review by the FERC. In such review, it is possible that the FERC could alter its
current rulings on the tax allowance issue or on the application of the FERC oil
pipeline ratemaking methodology.

     The FERC generally has not investigated rates, such as those currently
charged by PAA, 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 PAA's gross margins on transportation are produced
by rates that are either grandfathered or set by agreement of the parties. The
rates for substantially all of the crude oil transported from California to West
Texas are grandfathered and not subject to decreases through the application of
indexing. 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, PAA believes that the rates now in effect can be sustained, although no
assurance can be given that the rates currently charged by PAA would ultimately
be upheld if challenged. In addition, PAA does not believe that an adverse
determination on the tax allowance issue in the Santa Fe Proceeding would have a
detrimental impact upon the current rates charged by PAA.

  Transportation and Sale of Natural Gas

     The FERC regulates interstate natural gas pipeline transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has adopted policies
intended to make natural gas transportation more accessible to natural gas
buyers and sellers on an open and non-discriminatory basis. The FERC's most
recent action in this area, Order No. 636, reflected the FERC's finding that,
under the then-existing regulatory structure, interstate pipelines and other
natural gas merchants, including producers, did not compete on a "level playing
field" in selling natural gas. Order No. 636 instituted individual pipeline
service restructuring proceedings, designed specifically to "unbundle" those
services (e.g., transportation, sales and storage) provided by many interstate
pipelines so that buyers of natural gas may secure natural gas supplies and
delivery services from the most economical source, whether interstate pipelines
or other parties. The FERC has issued final orders in all of the restructuring
proceedings and has announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price which shippers can charge for their released capacity. The FERC has
also adopted a new policy regarding the use of non-traditional methods of
setting rates for interstate natural gas pipelines in certain circumstances as
alternatives to cost of service based rates. A number of pipelines have obtained
FERC authorization to charge negotiated rates as one such alternative. The
Company cannot predict what action the FERC will take in the reexamination of
its transportation-related policies, nor can it accurately predict whether the
FERC's actions will achieve its stated goal of increasing competition in
domestic natural gas 

                                       23
<PAGE>
 
markets. However, the Company does not believe that it will be treated
materially differently than other natural gas producers and marketers with which
it competes.

     Although the FERC's actions, such as Order No. 636, do not regulate natural
gas producers such as the Company, these 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 the Company's
business or operations. On a prospective basis, however, such orders may
substantially increase the burden on the producers and transporters to nominate
and deliver on a daily basis a specified volume of natural gas. Producers and
transporters which deliver deficient volumes or volumes in excess of such daily
nominations could be subject to additional charges by the pipeline carriers.

     The United States Court of Appeals for the District of Columbia Circuit has
affirmed the FERC's Order No. 636 restructuring rule and remanded certain issues
for further explanation or clarification. Numerous petitions seeking judicial
review of the individual pipeline restructuring orders are currently pending in
that Court. Although it is difficult to predict when all appeals of pipeline
restructuring orders will be completed or their impact on the Company, the
Company does not believe that it will be affected by the restructuring rule and
orders any differently than other natural gas producers and marketers with which
it competes.

     Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective or their effect, if any, on the Company's
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 the Company's cost of doing business and, consequently, affects its
profitability and cash flow. Inasmuch as laws and regulations are frequently
expanded, amended or reinterpreted, the Company is unable to predict the future
cost or impact of complying with such regulations.

  Regulation of Production

     The production of 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 the
Company owns and operates 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 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 the Company can produce from its wells and to limit the number of
wells or the locations at which the Company 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 the Company's operations and costs. In
particular, the Company's exploration, exploitation and production operations,
its activities in connection with storage and transportation of crude oil and
other liquid hydrocarbons and its use of facilities for treating, processing or
otherwise handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation. As with the industry generally, compliance with
existing and anticipated regulations increases the Company's overall cost of
business. Such areas affected include unit production expenses primarily related
to the control and limitation of air emissions and the disposal of produced
water, capital costs to drill exploration and development wells due to solids
control and capital costs to construct, maintain and upgrade equipment and
facilities. While these regulations affect the Company's capital expenditures
and earnings, the Company believes that such regulations do not affect its
competitive position in that the operations of its competitors that comply with
such regulations are similarly affected. Environmental regulations have
historically been subject to frequent change by regulatory authorities, and the
Company is unable to predict the ongoing cost to it of complying with these laws
and regulations or the future impact of such regulations on its operation. A
discharge of hydrocarbons or hazardous substances into the environment could, to
the extent such event is not insured, subject the Company 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.

                                       24
<PAGE>
 
     Although the Company obtained environmental studies on its properties in
California, the Sunniland Trend and the Illinois Basin, and the Company believes
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, the Company 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 the Company agreed to excavate
and remediate nonhazardous crude oil contaminated soils. The Company is
obligated to construct and operate (for the next 12 years) a minimum of five
acres of bioremediation cells for crude oil contaminated soils designated for
excavation and treatment by Chevron. While the Company believes that it does not
have any material obligations for operations conducted prior to Stocker's
acquisition of the properties from Chevron, other than its 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 it 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 the Sunniland Trend Properties is located within the Big
Cypress National Preserve and the Company's 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 the Company's 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 the Company restore
the surface property affected by its drilling and production operations upon
cessation of these activities. The Company does 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
Acquisition 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 the Company's operations and its planned activities or future
commercial and/or residential development, the Company believes that it will be
able to operate the existing wells and realize the reserve potential identified
in its 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 United States. In the event of an oil spill into such
waters, substantial liabilities could be imposed upon the Company. States in
which the Company operates have also enacted similar laws. Regulations are
currently being developed under OPA and state laws that may also impose
additional regulatory burdens on the Company.

     The FWPCA imposes restrictions and strict controls regarding the discharge
of produced waters and other oil and natural gas wastes into navigable waters.
Permits must be obtained to discharge pollutants to state and federal waters.
The FWPCA provides for civil, criminal and administrative penalties for any
unauthorized discharges of oil and other hazardous substances in reportable
quantities and, along with the OPA, imposes substantial potential liability for
the costs of removal, remediation and damages. State laws for the control of
water pollution also provide varying civil, criminal and administrative
penalties and liabilities in the case of a discharge of petroleum or its
derivatives into state waters. The EPA has promulgated regulations that require
many oil and natural gas production operations to obtain permits to discharge
storm water runoff. At some facilities, such as the Sunniland Trend Properties,
the Company eliminated this permit requirement by collecting all potentially
contaminated storm water and disposing of it through the Company's underground
injection control ("UIC") disposal wells. At other facilities, the Company has
applied for and obtained any necessary storm water discharge permits, and is
currently in substantial compliance with applicable permit conditions. The
Company believes that compliance with existing 

                                       25
<PAGE>
 
permits and compliance with foreseeable new permit requirements will not have a
material adverse effect on the Company's financial condition or results of
operations.

     Air Emissions. The operations of the Company are subject to the Federal
Clean Air Act and comparable state and local statutes. The Company believes that
its operations are in substantial compliance with such statutes in all states in
which they 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 United States 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 particular, the Company's LA
Basin properties are located in an "extreme" non-attainment area for ozone. This
classification will force the local air quality regulatory authority, the South
Coast Air Quality Management District, to adopt stringent controls on all
emissions of nitrogen oxide and volatile organic compounds. As a result of these
future regulations, the Company may incur future capital expenditures to reduce
air emissions from the LA Basin production facilities. In addition, the 1990
Federal Clean Air Act Amendments include a new operating permit for major
sources ("Title V permits"), and several of the Company's facilities may require
permits under this new program. Although no assurances can be given, the Company
believes implementation of the 1990 Federal Clean Air Act Amendments will not
have a material adverse effect on the Company's financial condition or results
of operations.

     Solid Waste. The Company generates 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. RCRA also governs the
disposal of hazardous wastes. At present, the Company is not required to comply
with a substantial portion of the RCRA requirements because the Company's
operations generate minimal quantities of hazardous wastes. However, it is
anticipated 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 may
result in additional capital expenditures or operating expenses by the Company.

     Superfund. 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 its ordinary operations, the Company may generate waste
that may fall within CERCLA's definition of a "hazardous substance". The Company
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
or released into the environment.

     The Company currently owns or leases, and has in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and natural gas. Although the Company has 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 the Company or on or under other locations
where such 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 the Company's control.
These properties and wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, the Company 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. PAA believes that its
operations are in substantial compliance with such regulations.

                                       26
<PAGE>
 
Federal Taxation

     For federal income tax purposes, PAAI is the General Partner of PAA,
holding a direct and indirect ownership of approximately 57% 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.

     As a result of the formation of PAA, significant taxable income was
generated, allowing the Company to utilize certain net operating losses ("NOL")
previously subject to separate return limitation year ("SRLY") restrictions. As
a result, the Company no longer has any net operating losses subject to the SRLY
rules. At December 31, 1998, the Company and its 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 NOL carryforwards of
approximately $139.7 million and approximately $128.3 million of alternative
minimum tax ("AMT") net operating loss carryforwards available as a deduction
against future AMT income. In addition, the Company had approximately $.3
million of investment tax credit carryforwards, $1.3 of AMT credits and $7.0
million of percentage depletion carryforwards at December 1, 1998. The NOL
carryforwards expire from 2003 through 2011. The value of these carryforwards
depends on the ability of the Company 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.

     The ability of the Company to utilize NOL and investment tax credit
carryforwards to reduce future federal taxable income and federal income tax of
the Company 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 the offering of stock
by the Company during any three-year period resulting in an aggregate change of
more than 50% ("Ownership Change") in the beneficial ownership of the Company.

     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 (i) the fair market value of the equity of the Company multiplied by (ii) 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, the Company does not believe that an Ownership Change has occurred as of
December 31, 1998. Equity transactions after the date hereof by the Company or
by 5% stockholders (including relatively small transactions and transactions
beyond the Company's 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 the Company's 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

     The Company must continually acquire, explore for, develop or exploit new
oil and natural gas reserves to replace those produced or sold. Without
successful drilling, acquisition or exploitation operations, the Company's oil
and natural gas reserves and revenues will decline. Drilling activities are
subject to numerous risks, including the risk that no commercially viable 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 -- 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 the Company's oil and natural gas production also depends on a
number of factors, including the demand for and supply of 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.

                                       27
<PAGE>
 
     Substantially all of the Company's California crude oil and natural gas
production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could cause the Company to seek
transportation alternatives, which in turn could result in increased
transportation costs to the Company or involuntary curtailment of a significant
portion of its crude oil and natural gas production.

     The Company's operations are subject to all of the risks normally incident
to the exploration for and the production of oil and natural gas, including
blowouts, cratering, oil spills and fires, each of which could result in damage
to or destruction of oil and natural gas wells, production facilities or other
property, or injury to persons. The relatively deep drilling conducted by the
Company from time to time involves increased drilling risks of high pressures
and mechanical difficulties, including stuck pipe, collapsed casing and
separated cable. The Company's 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 the Company maintains insurance
coverage considered to be customary in the industry, it is 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 the Company's 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. PAA maintains insurance of
various types that it considers to be adequate to cover its operations and
properties. The insurance covers all of PAA's assets in amounts considered
reasonable. The insurance policies are subject to deductibles that PAA considers
reasonable and not excessive. PAA's 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, PAA's 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 PAA's operations and
financial condition. PAA believes that it is adequately insured for public
liability and property damage to others with respect to its operations. With
respect to all of its coverage, no assurance can be given that PAA will be able
to maintain adequate insurance in the future at rates it considers reasonable.

     The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and natural gas. Historically, the
prices for oil and natural gas have been volatile and are likely to continue to
be volatile in the future. The price received by the Company for its oil and
natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors beyond the Company's control,
including seasonality, the condition of the United States economy (particularly
the manufacturing sector), foreign imports, political conditions in other 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 oil and natural gas have had, and could
have in the future, an adverse effect on the carrying value of the Company's
proved reserves and the Company's revenues, profitability and cash flow. Almost
all of the Company's reserve base (approximately 90% of year-end 1998 reserve
volumes) is comprised of long-life oil properties that are sensitive to crude
oil price volatility. The crude oil price at December 31, 1998, upon which
proved reserve volumes, the Present Value of Proved Reserves and the
Standardized Measure as of such date were based, was $12.05 per barrel. Such
price was the lowest year-end price since oil was deregulated in 1980 and was
approximately 34% below the price used in preparing reserve estimates at the end
of 1997. Although the Company is not currently experiencing any significant
involuntary curtailment of its crude oil or natural gas production, market,
logistic, economic and regulatory factors may in the future materially affect
the Company's ability to sell its production.

     In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company from time to time enters into fixed price delivery
contracts, floating price collar arrangements, financial swaps and oil and
natural gas futures contracts as hedging devices. To ensure a fixed price for
future production, the Company may sell a futures contract and thereafter either
(i) make physical delivery of its product to comply with such contract or (ii)
buy a matching futures contract to unwind its futures position and sell its
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 the Company to the risk of financial loss in certain
circumstances, including instances where production is less than expected, the
Company's customers fail to purchase or deliver the contracted quantities of oil
or natural gas, or a sudden, unexpected event materially impacts oil or natural
gas prices. Such contracts may also restrict the ability of the Company to
benefit from unexpected increases in oil and natural gas prices. See "Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Capital Resources, 

                                       28
<PAGE>
 
Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices" and
"Item 7A, Quantitative and Qualitative Disclosures about Market Risks".

Title to Properties

     The Company's 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. The Company does not
believe that any of these burdens materially interferes with the use of such
properties in the operation of its business.

     The Company believes that it has generally satisfactory title to or rights
in all of its producing properties and other assets. 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 the Company's 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. Permits have been obtained 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. Permits
have also been obtained 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.

     Some of the leases, easements, rights-of-way, permits and licenses
transferred to PAA upon its formation in 1998 required the consent to transfer
of the grantor of such rights, which in certain instances is a governmental
entity. The Company believes that it has obtained such third-party consents,
permits and authorizations that are sufficient for the transfer to the Company
of the assets necessary for the Company to operate its business in all material
respects as described in this report. With respect to any consents, permits or
authorizations which have not yet been obtained, the Company believes 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 the Company's business. If any
such consents are not so obtained, the Company will enter into other agreements,
or take such other action as may be necessary to ensure that the Company has the
assets and concomitant rights necessary to enable it to operate the Company's
business in all material respects as described in this Report.

Employees

     As of March 1, 1999, the Company had 370 full-time employees, none of whom
is represented by any labor union. Approximately 178 of such full-time employees
are field personnel involved in oil and natural gas producing activities,
trucking and transport activities and crude oil terminalling and storage
activities. Approximately 210 employees spend the substantial majority of their
time on the business of PAA.

Item 2. PROPERTIES

     The Company is an independent energy company engaged in the acquisition,
exploitation, development, exploration and production of crude oil and natural
gas. Through its majority ownership in PAA, the Company is engaged in the
midstream activities of marketing, transportation, terminalling and storage of
crude oil. The Company's upstream oil and natural gas activities are focused in
California, the Sunniland Trend and the Illinois Basin. The Company's midstream
activities are concentrated in California, Texas, Oklahoma, Louisiana and the
Gulf of Mexico. The Company's upstream operations contributed approximately 58%
of the Company's EBITDA for the fiscal year ending December 31, 1998, while the
Company's midstream activities accounted for 42%. The Company conducts its
upstream operations in each of its three core areas through wholly owned
subsidiaries. The California Properties are operated by Stocker, the Sunniland
Trend properties are operated by Calumet and the Illinois Basin Properties are
operated by Plains Illinois. See "Item 1, Business" for a discussion of the
Company's acquisition, development, exploitation and exploration activities and
midstream businesses.

                                       29
<PAGE>
 
Oil and Natural Gas Reserves

     The following tables set forth certain information with respect to the
Company's reserves based upon reserve reports prepared by the independent
petroleum consulting firms of H.J. Gruy and Associates, Inc., Netherland, Sewell
& Associates, Inc., Ryder Scott Company and System Technology Associates, Inc.
Such reserve volumes and values were determined under the method prescribed by
the SEC which requires the application of year-end prices for each year, held
constant throughout the projected reserve life.

<TABLE>
<CAPTION>
                                                                       AS OF OR FOR THE YEAR ENDED DECEMBER 31,
                                           ------------------------------------------------------------------------------------
                                                          1998                         1997                     1996
                                           -------------------------------   ------------------------   -----------------------
                                                   OIL              GAS          OIL           GAS          OIL           GAS
                                                  (BBL)            (MCF)        (BBL)         (MCF)        (BBL)         (MCF)
                                           -------------------------------   ------------------------   -----------------------
<S>                                           <C>                 <C>          <C>           <C>          <C>           <C>
                                                                               (IN THOUSANDS)
 
Proved Reserves
 Beginning balance                                  151,627       60,350       115,996       37,273        94,408        43,110
 Revision of previous estimates                     (46,282)       2,925       (16,091)       3,805        19,424         6,641
 Extensions, discoveries, improved
  recovery and other additions                       14,729       29,306        17,884        8,126         8,179         1,294
 Sale of reserves in-place                                -       (2,799)          (26)        (547)           (5)      (12,491)
 Purchase of reserves in-place                        7,709            -        40,764       14,566            45           862
 Production                                          (7,575)      (3,001)       (6,900)      (2,873)       (6,055)       (2,143)
                                                   --------     --------      --------      -------      --------      --------
Ending balance                                      120,208       86,781       151,627       60,350       115,996        37,273
                                                   ========     ========      ========      =======      ========      ========
 
 
PROVED DEVELOPED RESERVES
 Beginning balance                                   99,193       38,233        86,515       25,629        67,266        29,397
                                                   ========     ========      ========      =======      ========      ========
 Ending balance                                      73,264       58,445        99,193       38,233        86,515        25,629
                                                   ========     ========      ========      =======      ========      ========
</TABLE>

     The following table sets forth the Present Value of Proved Reserves as of
December 31, 1998, 1997 and 1996.

                                        1998        1997      1996
                                       -------     ------    -------
                                              (in thousands)     

        Proved developed             $ 185,961  $ 386,463   $ 574,686      
        Proved undeveloped              40,982    124,530     190,088 
                                      --------   --------    --------
        Total Proved                 $ 226,943  $ 510,993   $ 764,774
                                      ========   ========    ========   

     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 the control of
the Company. Reserve engineering is a subjective process of estimating the
recovery from underground accumulations of 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 oil and natural gas that are ultimately
recovered, production and operating costs, the amount and timing of future
development expenditures and future 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 oil and natural gas reserves
attributable to the Company's 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 the Company's reserve base (approximately 90% of
year-end 1998 reserve volumes) is comprised of long-life oil properties that are
sensitive to crude oil price volatility. The benchmark NYMEX crude oil price
received by the Company at December 31, 1998, 1997, and 1996 upon which proved
reserve volumes, the Present Value of Proved Reserves and the Standardized
Measure as of such dates were based, was $12.05 per barrel, $18.34 per barrel
and $25.92 per barrel, respectively. The crude oil price at December 31, 1998,
was the lowest year-end price since oil was deregulated in 1980 and was
approximately 34% below the price used in preparing reserve estimates at the end
of 1997. Revisions of previous estimates set forth above include downward price
related revisions of 52 MMBbls and 16 MMBbls in 1998 and 1997, respectively, and
positive price related revisions of 10 MMBbls in 1996. See "Item 7, Management's
Discussion 

                                       30
<PAGE>
 
and Analysis of Financial Condition and Results of Operations --Capital
Resources, Liquidity and Financial Condition -- Changing Oil and Natural Gas
Prices".

     In accordance with the SEC guidelines, the reserve engineers' estimates of
future net revenues from the Company's properties and the present value thereof
are made using 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, 1998, is based on the NYMEX Crude Oil Price received by
the Company of $12.05 per barrel with variations therefrom based on location and
grade of crude oil. The Company has entered into various arrangements to fix the
NYMEX Crude Oil Price for a significant portion of its crude oil production. On
December 31, 1998, these arrangements provided for a NYMEX Crude Oil Price for
9,000 barrels per day from January 1, 1999, through December 31, 1999, at
approximately $18.25 per barrel. Since December 31, 1998, the Company has
entered into additional arrangements, which provide for a NYMEX Crude Oil Price
for 2,000 barrels per day from January 1, 2000, through December 31, 2000, at
$15.30 per barrel. Location and quality differentials attributable to the
Company's properties are not included in the foregoing prices. Arrangements in
effect at December 31, 1998, 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, 1998, were $7.96 per barrel of crude oil, condensate and
natural gas liquids and $1.68 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, 1997, the Company has not filed any estimates of total
proved net oil or natural gas reserves with any federal authority or agency
other than the SEC. See Note 18 to the Company's Consolidated Financial
Statements appearing elsewhere in this Report for certain additional information
concerning the proved reserves of the Company.

Productive Wells and Acreage

     As of December 31, 1998, the Company had working interests in 1,727 gross
(1,726 net) active oil wells.

     The following table sets forth certain information with respect to the
developed and undeveloped acreage of the Company as of December 31, 1998.

<TABLE>
<CAPTION>
                                                                 DECEMBER 31, 1998
                              --------------------------------------------------------------------------------------
                                       DEVELOPED ACRES (1)                             UNDEVELOPED ACRES (2)
                              ---------------------------------------        ---------------------------------------
                                     GROSS                   NET                    GROSS                  NET(3)
                              ----------------       ----------------        ----------------       ----------------
<S>                              <C>                    <C>                     <C>                    <C>
California (4)                           5,896                  5,824                     460                    460
Florida (5)                             12,192                 12,192                  82,804                 78,650
Illinois                                16,412                 14,410                  16,906                  8,428
Indiana                                  1,155                    854                   1,280                    575
Kansas                                       -                      -                  48,147                 37,807
Kentucky                                     -                      -                   1,321                    521
Louisiana                                    -                      -                   4,875                  4,858
                              ----------------       ----------------        ----------------       ----------------
Total                                   35,655                 33,280                 155,793                131,299
                              ================       ================        ================       ================
</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 4% of total net undeveloped acres are covered by leases
             that expire from 1999 through 2002.
         (4) Does not include 9,000 acres covered by a farmout from Chevron, in
             which the Company owns a 50% interest.
         (5) Does not include approximately 800,000 acres covered by the
             Exploration Agreement entered into in February 1998 or 29,000 gross
             (28,000 net) acres under a seismic option. See "Item 1, Exploration
             -- Current Exploration Projects -- Sunniland Trend".

                                       31
<PAGE>
 
Drilling Activities

     Certain information with regard to the Company's drilling activities during
the years ended December 31, 1998, 1997 and 1996 is set forth below:

<TABLE> 
<CAPTION> 
 
                                                                  YEAR ENDED DECEMBER 31,
                        -----------------------------------------------------------------------------------------------------------
                                       1998                                  1997                                 1996
                        ---------------------------------     ----------------------------------     ------------------------------
                             GROSS               NET               GROSS               NET                GROSS              NET
                        --------------     --------------     --------------     ---------------     ---------------     ----------
<S>                     <C>                <C>                <C>                 <C>                 <C>                <C>      
Exploratory Wells:
 Oil                                 -                  -               2.00                2.00                   -              -
 Natural gas                         -                  -                  -                   -                   -              -
 Dry                                 -                  -                  -                   -                2.00           0.63
                        --------------     --------------     --------------     ---------------     ---------------     ----------
  Total                              -                  -               2.00                2.00                2.00           0.63
                        ==============     ==============     ==============     ===============     ===============     ==========
 
Development Wells:
 Oil                             76.00              76.00              58.00               57.06               24.00          24.00
 Natural gas                         -                  -                  -                   -                   -              -
 Dry                                 -                  -                  -                   -                   -              -
                        --------------     --------------     --------------     ---------------     ---------------     ----------
  Total                          76.00              76.00              58.00               57.06               24.00          24.00
                        ==============     ==============     ==============     ===============     ===============     ==========
 
Total Wells:
 Oil                             76.00              76.00              60.00               59.06               24.00          24.00
 Natural gas                         -                  -                  -                   -                   -              -
 Dry                                                    -                                      -                2.00           0.63
                        --------------     --------------     --------------     ---------------     ---------------     ----------
  Total                          76.00              76.00              60.00               59.06               26.00          24.63
                        ==============     ==============     ==============     ===============     ===============     ==========
 
</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 oil and
natural gas production attributable to the Company's 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, 1998, 1997
and 1996.

<TABLE> 
<CAPTION>
                                                                            YEAR ENDED DECEMBER 31,
                                                         -----------------------------------------------------------
                                                                  1998                  1997                1996
                                                         -------------------     ---------------     ---------------
                                                                       (IN THOUSANDS EXCEPT PER UNIT DATA)
<S>                                                      <C>                        <C>              <C>     
Production:
 Crude oil and natural gas liquids (Bbls)                              7,574               6,900               6,055
 Natural gas (Mcf)                                                     3,001               2,873               2,143
 BOE                                                                   8,075               7,379               6,412
 
Revenue:
 Crude oil and natural gas liquids                            $       98,664          $  104,988          $   95,224
 Natural gas                                                           4,090               4,415               2,377
                                                              --------------         -----------          ----------
  Total                                                       $      102,754         $   109,403          $   97,601
                                                              ==============         ===========          ==========
 
 
Average sales price:
 Crude oil and natural gas liquids (Bbls)                     $        13.03         $     15.22          $    15.73
 Natural gas (Mcf)                                            $         1.36         $      1.54          $     1.11
 Per BOE                                                      $        12.73         $     14.83          $    15.22
Production expenses per BOE                                   $         6.29         $      6.16          $     6.04
</TABLE> 
 
PAA Properties

     See description of PAA's properties under "Item 1, Business -- Midstream
Activities".

                                       32
<PAGE>
 
Item 3.  LEGAL PROCEEDINGS

     On July 9, 1987, 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, a wholly
owned subsidiary of the Company, 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 the Company's oil and
natural gas leases but denied such motion as to the counterclaim alleging
conversion of funds. The Company has reached an agreement in principle with all
parties to settle this case. In consideration for full and final settlement, and
dismissal with prejudice of all issues in this case, the Company has agreed to
pay to the defendants the total sum of $100,000, and release certain royalty
amounts held in suspense and in the court registry during the pendency of this
case. Finalization of this settlement has been delayed due to disputes over
certain title issues. Motions have been filed requesting the Court to rule on
the disputes, but no hearing date has been set. The Company does not believe
that the disputes will adversely affect the settlement reached between the
Company and the defendants.

     The Company, in the ordinary course of business, is a claimant and/or a
defendant in various other legal proceedings in which its exposure, individually
and in the aggregate, is not considered material to the Company.

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.

Executive Officers of the Company

     Information regarding the executive officers of the Company 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 40, has been President, Chief Executive Officer and a
director of the Company 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 47, has been Executive Vice President and Chief Operating
Officer-Upstream since May 1998. He was Senior Vice President of the Company
from 1991 to 1998. He was Vice President-Corporate Development of the Company
from 1984 to 1991 and Special Assistant-Corporate Planning from 1982 to 1984.

   Cynthia A. Feeback, Assistant Treasurer,            Officer Since 1993 
Controller and Principal Accounting Officer  

     Ms. Feeback, age 41, has been Assistant Treasurer, Controller and Principal
Accounting Officer since May 1998. She was Controller and Principal Accounting
Officer of the Company from 1993 to 1998. She was Controller of the Company from
1990 to 1993 and Accounting Manager from 1988 to 1990.

   Phillip D. Kramer, Executive Vice President,        Officer Since 1987 
Chief Financial Officer and Treasurer     

     Mr. Kramer, age 43, has been Executive Vice President, Chief Financial
Officer and Treasurer since May 1998. He was Senior Vice President and Chief
Financial Officer of the Company from May 1997 to May 1998. He was Vice
President and 

                                       33
<PAGE>
 
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 51, has been Vice President and General Counsel of the
Company since 1985 and Corporate Secretary since 1988.

     Harry N. Pefanis, Executive Vice President          Officer Since 1988

     Mr. Pefanis, age 41, 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 of the Company since 1988. From 1987 to 1988
he was Manager of Products Marketing. From 1983 to 1987 he was Special Assistant
for Corporate Planning for the Company. Mr. Pefanis is also President and Chief
Operating Officer of Plains All American Inc.

     Mary O. Peters, Vice President - Administration     Officer Since 1991 
and Human Resources                    

     Ms. Peters, age 50, has been Vice President-Administration and Human
Resources since 1991. She was Manager of Office Administration of the Company
from 1984 to 1991.

                                 PART II

Item 5.  MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
         MATTERS

     The Company's 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 25, 1999, was 1,353.

     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.


                                   High            Low
                                ----------      ---------
        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      

        1997:
          1st Quarter           $ 18 1/4        $ 12                   
          2nd Quarter             15 3/16         11 7/8
          3rd Quarter             18 1/2          15    
          4th Quarter             20 3/4          15 7/8      


     The Company has not paid cash dividends on shares of the Common Stock since
the Company's inception and does not anticipate paying any cash dividends on the
Common Stock in the foreseeable future. In addition, the Company is restricted
by provisions of the indenture governing the issue of $200 million 10.25% Senior
Subordinated Notes Due 2006 (the "10.25% Notes") and prohibited by the Company's
$225 million revolving credit facility (the "Revolving Credit Facility") from
paying dividends on the Common Stock.

     On October 1, 1998, the Company paid a dividend on its Series E Preferred
Stock for the period from July 29, 1998 through September 30, 1998. The dividend
amount of approximately $1.4 million was paid by issuing 2,824 additional shares
of the Series E Preferred Stock. After payment of such dividend, there were
172,824 shares of the Series E Preferred Stock outstanding with a liquidation
value, including accrued dividends through December 31, 1998, of approximately
$88.5 million.

                                       34
<PAGE>
 
Item 6. SELECTED FINANCIAL DATA

     The following selected historical financial information was derived from,
and is qualified by reference to, the Consolidated Financial Statements of the
Company, 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".

<TABLE>
<CAPTION>
                                                                                           YEAR ENDED DECEMBER 31,
                                                                      ------------------------------------------------------------ 
                                                                         1998            1997        1996        1995      1994
                                                                      ----------      ---------   ---------   ---------  ---------
                                                                                (IN THOUSANDS, EXCEPT PER SHARE INFORMATION)
<S>                                                                   <C>             <C>         <C>         <C>        <C> 
Statement of Income Data:
Revenues:
 Oil and natural gas sales                                            $  102,754      $ 109,403   $  97,601   $  64,080  $  57,234
 Marketing, transportation, storage and terminalling revenues          1,129,689        752,522     531,698     339,826    199,239
 Interest and other income                                                61,649 (1)        319         309         319        223
                                                                      ----------      ---------   ---------   ---------  ---------  
  Total revenue                                                        1,294,092        862,244     629,608     404,225    256,696
                                                                      ----------      ---------   ---------   ---------  ---------  

 
Expenses:
 Production expenses                                                      50,827        45,486       38,735     30,256      27,220
 Marketing, transportation, storage and terminalling expenses          1,091,328       740,042      522,167    333,460     193,049
 General and administrative                                               10,778         8,340        7,729      7,215       6,966
 Depreciation, depletion and amortization                                 31,020        23,778       21,937     17,036      16,305
 Reduction of carrying cost of oil and natural gas properties            173,874 (2)         -            -          -           -
 Interest expense                                                         35,730         22,012      17,286     13,606      12,585
 Litigation settlement                                                         -              -       4,000(3)       -           -
                                                                      ----------      ---------   ---------   ---------  ---------  
Total expenses                                                         1,393,557        839,658     611,854     401,573    256,125
                                                                      ----------      ---------   ---------   ---------  ---------  
Income (loss) before income taxes, extraordinary
 item and minority interest                                               (99,465)       22,586      17,754       2,652        571
Minority interest                                                           1,809             -           -           -          -
Income tax expense (benefit):
 Current                                                                     862            352           -           -          -
 Deferred                                                                (43,582)         7,975      (3,898)          -          -
                                                                      ----------      ---------   ---------   ---------  ---------  
Income (loss) before extraordinary item                                  (58,554)(2)     14,259      21,652       2,652        571
Extraordinary item, net of tax benefit                                         -              -      (5,104)(4)       -          -
                                                                      ----------      ---------   ---------   ---------  ---------  
Net income (loss)                                                        (58,554)(2)     14,259      16,548       2,652        571
Less:  cumulative preferred stock dividends                                4,762            163           -           -          -
                                                                      ----------      ---------   ---------   ---------  ---------  
Net income (loss) applicable to common shareholders                   $  (63,316)(2)  $  14,096   $  16,548   $   2,652  $     571
                                                                      ==========      =========   =========   =========  =========  
Earnings (loss) per common share - basic:
 Before extraordinary item                                            $    (3.77)     $    0.85   $    1.32   $    0.19  $    0.04
 Extraordinary item, net of income taxes                                       -              -       (0.31)          -          -
                                                                      ----------      ---------   ---------   ---------  ---------  
                                                                      $    (3.77)     $    0.85   $    1.01   $    0.19  $    0.04
                                                                      ==========      =========   =========   =========  =========  
Earnings (loss) per common share - assuming dilution:
 Before extraordinary item                                            $    (3.77)     $    0.77   $    1.23   $    0.16  $    0.04
 Extraordinary item, net of income taxes                                       -              -       (0.29)          -          -
                                                                      ----------      ---------   ---------   ---------  ---------  
                                                                      $    (3.77)     $    0.77   $    0.94   $    0.16  $    0.04
                                                                      ==========      =========   =========   =========  =========  
OTHER FINANCIAL DATA:
Cash flow from operations (5)                                         $   42,033      $ 46,233    $  39,942   $  19,688  $ 16,876
EBITDA (6)                                                                80,344        68,376       56,977      33,294    29,461
Net cash provided by operating activities                                 37,630        30,307       39,008      16,984    18,369
Net cash used in investing activities                                    483,422       107,634       52,496      64,398    40,158
Net cash provided by financing activities                                448,622        78,524        9,876      52,252    19,297
 

                                                                                          YEAR ENDED DECEMBER 31,
                                                                      ------------------------------------------------------------ 
                                                                         1998            1997        1996        1995      1994
                                                                      ----------      ---------   ---------   ---------  ---------
                                                                                              (IN THOUSANDS)
<S>                                                                   <C>             <C>         <C>         <C>        <C> 
BALANCE SHEET DATA:
Cash and cash equivalents                                             $    6,544      $   3,714   $   2,517   $   6,129  $   2,791
Working capital deficit                                                  (13,941)        (6,011)     (4,843)     (4,749)    (4,465)
Property and equipment, net                                              661,726        413,308     311,040     280,538    217,602
Total assets                                                             974,267        556,819     430,249     352,046    266,904
Long-term debt                                                           431,983        285,728     225,399     205,089    149,600
Other long-term liabilities                                               13,967          5,107       2,577       1,547      3,754
Redeemable preferred stock                                                88,487              -           -           -     20,937
Total stockholders' equity                                                72,962        133,193      95,572      77,029     46,462
</TABLE>
(footnotes on following page)
                                       35
<PAGE>
 
________________________
(1) Includes a $60.8 million non-cash gain recognized by the Company upon the
    formation of PAA.
(2) Includes a $173.9 million pre-tax ($109.0 million after tax) non-cash charge
    related to a writedown of the capitalized costs of the Company's proved 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".
(3) Represents charge related to the settlement of two lawsuits filed in 1992
    and 1993. See "Item 7, Management's Discussion and Analysis of Financial
    Condition and Results of Operations -- Results of Operations".
(4) Relates to the early redemption in March 1996 of the Company's 12% Senior
    Subordinated Notes due 1999.
(5) Net cash provided by operating activities after minority interest but before
    changes in assets and liabilities and other non-cash items.
(6) EBITDA means earnings before interest, taxes, depreciation, depletion,
    amortization and other non-cash items. 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. 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.

Item 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS

General

     On November 23, 1998, PAA, through which the Company's midstream activities
are conducted, completed its initial public offering of 13.1 million common
units representing limited partner interests. PAA's results are consolidated
into the Company's results with the public's 43% ownership reflected as a
minority interest deduction from income. PAA was formed to acquire the midstream
crude oil business and assets of the Company, including the All American
Pipeline and the SJV Gathering System, which the Company purchased from Goodyear
in July 1998. See "-- Capital Resources, Liquidity and Financial Condition". The
assets, liabilities and results of operations of the All American Pipeline
Acquisition are included in the Company's Consolidated Financial Statements
effective July 30, 1998. See Note 9 to the accompanying Consolidated Financial
Statements for pro forma information giving effect to the All American Pipeline
Acquisition as if such transaction occurred on January 1, 1997.

     The Company's 1998 earnings were adversely affected by low crude oil prices
throughout 1998. The NYMEX Crude Oil Price averaged $14.43 per barrel in 1998,
approximately 30% and 34% below the 1997 and 1996 average NYMEX Crude Oil Price,
respectively. Almost all of the Company's reserve base (approximately 90% of
year-end 1998 reserve volumes) is comprised of long-life oil properties that are
sensitive to crude oil price volatility. The benchmark NYMEX Crude Oil Price at
December 31, 1998, upon which proved reserve volumes, the Present Value of
Proved Reserves and the Standardized Measure as of such date were based, was
$12.05 per barrel. Such price was the lowest year-end price since oil was
deregulated in 1980 and was approximately 34% below the price used in preparing
reserve estimates at the end of 1997. Under full-cost accounting rules as
prescribed by the SEC, unamortized costs of proved oil and natural gas
properties are subject to a ceiling, which limits such costs to the Standardized
Measure. At December 31, 1998, the capitalized costs of the Company's proved oil
and natural gas properties exceeded the Standardized Measure, and the Company
recorded a non-cash, after-tax charge to expense of $109.0 million ($173.9
million pre-tax). Such amount was partially offset by a $37.1 million after-tax
gain associated with the initial public offering of PAA. As of March 25, 1999,
crude oil prices have recovered to such levels that would have resulted in a
significantly lower writedown.

Results of Operations

     Excluding the non-cash full cost ceiling writedown and the partnership-
related gain, the Company reported net income for 1998 of $8.4 million, or $0.22
per share ($0.20 per share diluted), on total revenue of $1.2 billion, as
compared to net income in 1997 of $14.3 million or $0.85 per share ($0.77 per
share diluted), on total revenue of $862.2 million. Including the impact of the
writedown and partnership-related gain, the Company reported a net loss of $58.6
million, or $3.77 per share in 1998. Net income for 1996 was $16.5 million, or
$1.01 per share ($.94 per share diluted). Net income for 1996 included an $11.0
million benefit associated with the recognition of a portion of a deferred tax
asset that was previously fully reserved  and a $5.1 million extraordinary
charge net of taxes for early extinguishment of debt.

     EBITDA increased 17% in 1998 to $80.3 million from the $68.4 million
reported in 1997 and 40% from the $57.2 million reported in 1996. Cash flow from
operations (cash provided by operating activities after minority interest but
before 

                                       36
<PAGE>
 
changes in assets and liabilities) was $42.0 million, $46.2 million and $39.9
million in 1998, 1997 and 1996, respectively. Net cash provided by operating
activities was $37.6 million for the year ended December 31, 1998, as compared
to $30.3 million for 1997 and $39.0 million in 1996. The decrease in 1997 from
1996 is attributable to the purchase of crude oil inventory in contango market
transactions. Such inventory was hedged against price risk and was sold during
the first quarter of 1998.

  Upstream Results

     The following table sets forth certain operating information of the Company
for the periods presented:
<TABLE> 
<CAPTION> 
                                                                      Years Ended December 31,     
                                                            ----------------------------------------    
                                                                1998           1997          1996
                                                            ----------      ----------    ----------
                                                              (in thousands, except per unit data) 
<S>                                                         <C>             <C>           <C>          
        Average Daily Production Volumes
         Barrels of oil equivalent
           California (approximately 90% oil)                     13.8            11.2           9.2   
           Sunniland Trend (100% oil)                              4.8             5.3           4.7
           Illinois Basin (100% oil)                               3.5             3.6           3.5
           Sold properties                                           -             0.1           0.1      
                                                            ----------      ----------    ---------- 
                Total (approximately 94% oil)                     22.1            20.2          17.5       
                                                            ==========      ==========    ========== 
        Unit Economics
         Average sales price per BOE                        $    12.73      $    14.83    $    15.22    
         Production expense per BOE                               6.29            6.16          6.04
                                                            ----------      ----------    ---------- 
         Gross margin per BOE                                     6.44            8.67          9.18
         Upstream G&A expense per BOE                             0.68            0.65          0.74
                                                            ----------      ----------    ---------- 
         Gross profits per BOE                              $     5.76      $     8.02    $     8.44    
                                                            ----------      ----------    ---------- 
</TABLE> 

     Oil and natural gas production volumes in 1998 totaled 8.1 million BOE, a
9% increase over the 1997 level of 7.4 million BOE and 26% above the 1996 level
of 6.4 million BOE. The volume increase in 1998 is primarily associated with the
continued exploitation and expansion of the Company's California properties,
offset somewhat by shut-ins and declines in production from certain of its other
properties. During the second half of 1998, the Company shut-in certain of its
lower margin wells in California, Florida and Illinois due to low crude oil
prices, resulting in a decrease in average net daily production of approximately
1,120 BOE per day. Average net daily production from the Company's California
Properties increased to approximately 13,800 BOE per day in 1998, up 2,600 BOE
per day, or 23% over 1997 and 50% over the 1996 level. Excluding production from
the Arroyo Grande Field which was acquired during the fourth quarter of 1997,
California production and aggregate Company production were up 13% and 4%,
respectively, from 1997. Net production from the Company's Sunniland Trend
properties averaged approximately 4,800 barrels of oil per day in 1998, compared
to 5,300 barrels per day in 1997 and 4,700 barrels per day in 1996. Due to the
high volume of production that is generated by very few wells in the Sunniland
Trend, abrupt or abnormal declines or downtime due to mechanical, marketing, or
other conditions on any of the properties in this area could have a significant
impact on production. Net daily production in the Illinois Basin averaged
approximately 3,500 barrels per day during 1998, 3,600 barrels per day in 1997
and 3,500 barrels per day in 1996.

     Oil and natural gas revenues were $102.8 million in 1998, a decrease of 6%
from the 1997 comparative period due to decreased product prices which offset
increased production volumes. Oil and natural gas revenues increased to $109.4
million in 1997 as compared to $97.6 million in 1996 due to increased production
volumes. The Company's average product price, which represents a combination of
fixed and floating price sales arrangements and incorporates location and
quality discounts from the benchmark NYMEX prices, averaged $12.73 per BOE in
1998, 14% and 16% lower than the price received in 1997 and 1996, respectively.
The NYMEX Crude Oil Price averaged $14.43 per barrel in 1998, $20.63 per barrel
in 1997, and $21.99 per barrel in 1996. Financial swap arrangements and futures
transactions entered into by the Company to hedge production are included in the
Company's average product prices. Such transactions had the effect of increasing
the overall average price per BOE received by the Company by $2.98 in 1998 and
decreasing such price by $1.26 in 1997 and $2.62 in 1996. Approximately 59% of
the Company's crude oil production was hedged throughout 1998 at an average
NYMEX Crude Oil Price of approximately $19.80 per barrel. The Company routinely
hedges a portion of its crude oil production. See "-- Capital Resources,
Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices" and
"Item 7a, -- Quantitative and Qualitative Disclosures about Market Risk".

                                       37
<PAGE>
 
     Upstream unit gross margin (well-head revenue less production expenses) for
1998 was $6.44 per BOE, compared to $8.67 per BOE in 1997 and $9.18 per BOE in
1996. Average unit production expenses were $6.29 per BOE, $6.16 per BOE and
$6.04 per BOE in 1998, 1997, and 1996, respectively. Total production expenses
increased to $50.8 million from $45.5 million and $38.7 million in 1997 and
1996, respectively, primarily due to increased production volumes resulting from
the Company's acquisition and exploitation activities. Unit G&A expense
increased slightly to $0.68 per BOE in 1998 compared to $0.65 per BOE during
1997 and $0.74 per BOE during 1996. Total upstream G&A expense was $5.5 million,
$4.8 million and $4.8 million in 1998, 1997 and 1996, respectively. The increase
in 1998 is primarily associated with the Company's California upstream
acquisitions.

     Upstream depreciation, depletion and amortization ("DD&A") per BOE
excluding the writedown was $3.00, $2.83 and $3.00 per BOE in 1998, 1997 and
1996, respectively. Total upstream DD&A expense, likewise excluding the
writedown, was $24.2 million, $20.9 million and $19.2 million in 1998, 1997 and
1996, respectively.

  Midstream Results

     The following table sets forth certain midstream operating information of
the Company for the periods presented.

                                               Year Ended December 31,
                                         ----------------------------------
                                           1998         1997         1996
                                         -------      --------     --------
                                                   (in thousands)

Operating Results:
  Gross margin
    Pipeline transportation service      $ 16,490     $      -     $      -
    Terminalling and storage
      and gathering and marketing          21,871       12,480        9,531
                                         --------     --------     --------
      Total                                38,361       12,480        9,531
  General and administrative expense       (5,297)      (3,529)      (2,974)
                                         --------     --------     --------
  Gross profit                           $ 33,064     $  8,951     $  6,557
                                         ========     ========     ========

Average Daily Volumes (barrels)
  Pipeline tariff activities                  113            -            -
  Pipeline margin activities                   50            -            -
                                         --------     --------     --------
      Total                                   163            -            -
                                         ========     ========     ========
  Lease gathering                              88           71           59
  Bulk purchases                               95           49           32
  Terminal throughput                          80           77           59


     Pipeline Operations. The activities from pipeline operations generally
consist of transporting third-party volumes of crude oil for a tariff ("Tariff
Activities") and merchant activities designed to capture price differentials
between the cost to purchase and transport crude oil to a sales point and the
price received for such crude oil at the sales point ("Margin Activities").
Tariffs on the All American Pipeline vary by receipt point and delivery point.
Tariffs for OCS crude oil delivered to California markets averaged $1.41 per
barrel and tariffs for OCS volumes delivered to West Texas averaged $2.96 per
barrel as of December 31, 1998. Tariffs for San Joaquin Valley crude oil
delivered to West Texas averaged $1.25 per barrel as of December 31, 1998. 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. As is common with most merchant
activities, the ability of the Company to generate a profit on 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 it sells crude oil. The Company combines
reporting of gross margin for Tariff Activities and Margin Activities due to the
sharing of fixed costs between the two activities.

     As noted above, the results of operations of the Company include
approximately five months of operations of the All American Pipeline and the SJV
Gathering System which were acquired effective July 30, 1998. Tariff revenues
for this period were $19.0 million and are primarily attributable to transport
volumes from the Santa Ynez field (approximately 65,300 barrels per day) and the
Point Arguello field (approximately 24,300 barrels per day). The margin between
revenue and direct cost of crude purchased was approximately $3.9 million.
Operations and maintenance expenses were $6.1 million.

                                       38
<PAGE>
 
     The following table sets forth All American Pipeline average deliveries per
day within and outside California from July 30, 1998, through December 31, 1998
(in thousands).


        Deliveries:
          Average daily volumes (barrels):
            Within California                               111    
            Outside California                               52   
                                                         ------
                Total                                       163
                                                         ======

     Terminalling and Storage Activities and Gathering and Marketing Activities.
Gross margin from terminalling and storage and gathering and marketing
activities was $21.9 million for the year ended December 31, 1998, reflecting a
75% increase over the $12.5 million reported for the 1997 period and an
approximate 129% increase over the $9.5 million reported for 1996. Gross profit
totaled $17.5 million for 1998, approximately 96% and 167% over the amounts
reported for 1997 and 1996, respectively. Net of interest expense associated
with contango inventory transactions, gross margin and gross profit for 1998
were $21.1 million and $16.8 million, respectively, representing increases of
approximately 82% and 108% over the 1997 respective amounts. The Company did not
have any material contango inventory transactions in 1996. The increase in gross
margin was primarily attributable to an increase in the volumes gathered and
marketed in West Texas, Louisiana and the Gulf of Mexico and activities at the
Cushing Terminal.

     Total G&A expenses were $5.3 million for the year ended December 31, 1998,
compared to $3.5 million and $3.0 million for 1997 and 1996, respectively. Such
increases were primarily attributable to increased personnel as a result of the
continued expansion of the Company's terminalling and storage activities and
gathering and marketing activities as well as G&A expenses associated with the
addition of the All American Pipeline and the SJV Gathering System. Depreciation
and amortization was $5.4 million in 1998, as compared to $1.2 million in 1997
and $1.1 million in 1996. The increase is due to the acquisition of the All
American Pipeline and the SJV Gathering System in 1998.

  General

     Total G&A expenses, including midstream activities, were $10.8 million for
the year ended December 31, 1998, compared to $8.3 million and $7.7 million for
1997 and 1996, respectively. The increases are primarily attributable to
increased expenses associated with the Company's midstream activities, including
the July 1998 All American Pipeline Acquisition and the Company's upstream
California acquisitions. Primarily as a result of the All American Pipeline
Acquisition and increased production levels, total DD&A for the year ended
December 31, 1998, was $31.0 million as compared to $23.8 million and $21.9
million in 1997 and 1996, respectively.

     Interest expense, net of capitalized interest, for 1998 increased to $35.7
million as compared to $22.0 million in 1997 and $17.3 million in 1996. The
increases are primarily due to the debt incurred for the All American Pipeline
Acquisition and to higher debt levels related to the Company's acquisition,
exploitation, development and exploration activities. During 1998, 1997 and
1996, the Company capitalized $3.7 million, $3.3 million and $3.6 million of
interest, respectively.

     During 1998, the Company recognized a pre-tax gain (net of approximately
$9.2 million in formation related expenses) in connection with the formation of
PAA. Such gain is the result of an increase in the book value of the Company's
equity in PAA to reflect their proportionate share of the underlying net assets
of PAA due to the sale of units in the IPO. 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.

     During 1996, the Company settled two lawsuits filed in 1992 and 1993
against certain of its officers and directors for a cash payment of
approximately $6.3 million which resulted in a charge to 1996 first quarter
earnings of $4 million. Approximately $4.1 million of such amount was paid by
the Company's insurance carrier and $2.2 million was paid by the Company.

     For the year ended December 31, 1998, the Company recognized a deferred tax
benefit of $43.6 million and a current tax provision of $0.9 million. For the
year ended December 31, 1997, the Company recognized a deferred tax provision of
$8.0 million and a current tax provision of $0.4 million. For 1996, the Company
recognized a net deferred tax benefit before extraordinary item of $3.9 million.
Such amount consists of a $7.1 million deferred tax provision on the Company's
income before extraordinary item and an $11.0 million reduction in the valuation
allowance reserved against the Company's net deferred tax asset. In 1996, the
Company also reported a $3.4 million deferred tax benefit as an extraordinary
item which was attributable 

                                       39
<PAGE>
 
to the $8.5 million pre-tax first quarter extraordinary loss from the early
redemption of the Company's 12% Senior Subordinated Notes.

     At December 31, 1998, the Company has a net deferred tax asset of $47.8
million. Management believes that it is more likely than not that it will
generate taxable income sufficient to realize such asset based on certain tax
planning strategies available to the Company. As an example, the Company,
through its existing ownership in PAA which is publicly traded, could generate
sufficient taxable income to utilize the tax asset existing at December 31,
1998. Therefore, the Company has concluded that the valuation allowance is
adequate.

     In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("FAS 133"). FAS 133 is effective for all
fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company).
FAS 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 it is,
the type of hedge transaction. For fair value hedge transactions in which the
Company is 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 the Company is 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. The Company has not yet determined the affect
that the adoption of FAS 133 will have on its results of operations or financial
position.

     In November 1998, the Emerging Issues Task Force ("EITF") released Issue
No. 98-10, "Accounting for Energy Trading and Risk Management Activities". EITF
98-10 deals with entities that enter into derivatives and other third-party
contracts for the purchase and sale of a commodity in which they normally do
business (for example, crude oil and natural gas). The EITF reached a consensus
that energy trading contracts should be measured at fair value determined as of
the balance sheet date with the gains and losses included in earnings and
separately disclosed in the financial statements or footnotes thereto. The EITF
acknowledged that determining whether or when an entity is involved in energy
trading activities is a matter of judgment that depends on the relevant facts
and circumstances. As such, certain factors or indicators have been identified
by the EITF which should be considered in evaluating whether an operation's
energy contracts are entered into for trading purposes. EITF 98-10 is required
to be applied to financial statements issued by the Company beginning in 1999.
The adoption of this consensus is not expected to have a material impact on the
Company's results of operations or financial position.

Capital Resources, Liquidity and Financial Condition

  All American Pipeline Acquisition

     On July 30, 1998, PAAI, a wholly owned unrestricted subsidiary of the
Company, as defined in the indentures for the Company's $200 million 10.25%
Senior Subordinated Notes (the "Indentures"), 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 Ventures Seven, Inc., a wholly-owned
subsidiary of Goodyear for approximately $400 million, including transaction
costs. The principal assets of the entities acquired include the All American
Pipeline System, a 1,233-mile crude oil pipeline extending from California to
Texas, and a 45-mile crude oil gathering system in the San Joaquin Valley of
California, as well as other assets related to such operations.

     Financing for the acquisition was provided through (i) PAAI's $325 million,
limited recourse bank facility with ING (U.S.) Capital Corporation, BankBoston,
N.A. and other lenders (the "PAAI Credit Facility") and (ii) an approximate $114
million capital contribution to PAAI by the Company. Approximately $29 million
of such capital contribution was funded from existing cash and the Company's
revolving credit facility (the "Revolving Credit Facility") and the remaining
$85 million was provided by a privately placed issuance of the Company's Series
E Cumulative Convertible Preferred Stock (the "Series E Preferred Stock"). A
portion of the PAAI Credit Facility was subsequently repaid and the remainder
restructured as described below.

     On July 29, 1998, the Company sold in a private placement 170,000 shares of
its Series E Preferred Stock for $85 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 the Company's option and 

                                       40
<PAGE>
 
are cumulative from the date of issue. Each share of Series E Preferred Stock is
convertible into 27.78 shares of the Company's common stock ("Common Stock") (an
initial effective conversion price of $18.00 per share) and in certain
circumstances may be converted at the Company's 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 the option
of the Company after March 31, 1999, at 110% of stated value and at declining
amounts thereafter. If not previously redeemed or converted, the Series E
Preferred Stock is required to be redeemed in 2012.

  Formation and Initial Public Offering of PAA and Related Financial
  Restructuring

     PAA was formed during 1998 to acquire and operate the midstream crude oil
business and assets of the Plains Midstream Subsidiaries, including the All
American Pipeline and SJV Gathering System. PAAI is the general partner of the
Partnership.

     On November 23, 1998, PAA sold 13,085,000 common units representing limited
partner interests in PAA and received net proceeds therefrom of approximately
$244.7 million. PAAI is both the sole general partner of PAA and the majority
owner, holding a 57% interest through ownership of approximately 17 million
common and subordinated units and its general partner interest. For financial
statement purposes, the assets, liabilities and earnings of PAA are included in
the Company's consolidated financial statements with the public Unitholders' 43%
ownership reflected as a minority interest. Concurrently with the closing of the
IPO, the Company and PAA reduced consolidated indebtedness by approximately $240
million and significantly restructured or eliminated various midstream credit
facilities.

     Concurrently with the closing of the IPO, PAA entered into the Bank Credit
Agreement that includes the Term Loan Facility and the PAA Revolving Credit
Facility. PAA may borrow up to $50 million under the PAA Revolving Credit
Facility for acquisitions, capital improvements, working capital and general
business purposes.

     The Term Loan Facility bears interest at PAA's option at either (i) the
Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin.
Borrowings under the PAA Revolving Credit Facility bear interest at PAA's option
at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an
applicable margin. PAA incurs a commitment fee on the unused portion of the PAA
Revolving Credit Facility and, with respect to each issued letter of credit, an
issuance fee.

     At December 31, 1998, $175 million was outstanding under the Term Loan
Facility, which amount represents indebtedness assumed from the General Partner.
PAA has two 10-year interest rate swaps (subject to cancellation by the counter
party after seven years) aggregating $175 million notional principal amount,
which fix the LIBOR portion of the interest rate (not including the applicable
margin) at a weighted average rate of approximately 5.24%. 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
PAA Revolving Credit Facility expires in 2000. All borrowings for working
capital purposes outstanding under the PAA Revolving Credit Facility must be
reduced to no more than $8 million for at least 15 consecutive days during each
fiscal year. At December 31, 1998, there were no amounts outstanding under the
PAA Revolving Credit Facility. The Bank Credit Agreement is secured by a lien on
substantially all of the assets of PAA.

     Simultaneously with the IPO, PAA entered into a $175 million letter of
credit and borrowing facility, which replaced an existing facility. The purpose
of the Letter of Credit Facility is to provide (i) standby letters of credit to
support the purchase and exchange of crude oil for resale and (ii) borrowings to
finance crude oil inventory which have been hedged against future price risk or
designated as working inventory. The Letter of Credit Facility is collateralized
by a lien on substantially all of the assets of PAA. 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
current assets and current liabilities of PAA, primarily crude oil inventory and
accounts receivable and accounts payable related to the purchase and sale of
crude oil. At December 31, 1998, the borrowing base under the Letter of Credit
Facility was approximately $175 million.

     The Letter of Credit Facility has a $40 million sublimit for borrowings to
finance crude oil purchased in connection with operations at PAA's crude oil
terminal and storage facilities. All purchases of crude oil inventory financed
are required to be hedged against future price risk on terms acceptable to the
lenders. At December 31, 1998, approximately $9.8 million was outstanding under
the sublimit.

     Letters of credit under the Letter of Credit Facility are generally issued
for up to 70 day periods. Borrowings bear interest at PAA's option at either (i)
the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the applicable
margin. PAA incurs a commitment fee on the unused portion of the borrowing
sublimit under the Letter of Credit Facility and an issuance fee 

                                       41
<PAGE>
 
for each letter of credit issued. The Letter of Credit Facility expires July 31,
2001. At December 31, 1998, there were outstanding letters of credit of
approximately $62 million issued under the Letter of Credit Facility.

     Both the Letter of Credit Facility and the Bank Credit Agreement contain a
prohibition on distributions on, or purchases or redemptions of, Units if any
Default or Event of Default (as defined) is continuing. In addition, both
facilities contain various covenants limiting the ability of PAA to (i) incur
indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain
limitations, (iv) engage in transactions with affiliates, (v) make investments,
(vi) enter into hedging contracts and (vii) enter into a merger, consolidation
or sale of its assets. In addition, the terms of the Letter of Credit Facility
and the Bank Credit Agreement require PAA to maintain (i) a Current Ratio (as
defined) of at least 1.0 to 1.0; (ii) a Debt Coverage Ratio (as defined) which
is not greater than 5.0 to 1.0; (iii) an Interest Coverage Ratio (as defined)
which is not less than 3.0 to 1.0; (iv) a Fixed Charge Coverage Ratio (as
defined) which is not less than 1.25 to 1.0; and (v) a Debt to Capital Ratio (as
defined) of not greater than .60 to 1.0. In both the Letter of Credit Facility
and the Bank Credit Agreement, a Change in Control (as defined) of the Company
constitutes an Event of Default.

     PAA will distribute 100% of its Available Cash within 45 days after the end
of each quarter to Unitholders of record and to the General Partner. Available
Cash is generally defined as all cash and cash equivalents of PAA on hand at the
end of each quarter less reserves established by the General Partner for future
requirements. Distributions of Available Cash to holders of Subordinated Units
are subject to the prior rights of holders of Common Units to receive the
minimum quarterly distribution ("MQD") for each quarter during the subordination
period (which will not end earlier than December 31, 2003) and to receive any
arrearages in the distribution of the MQD on the Common Units for the prior
quarters during the subordination period. The MQD is $0.45 per unit ($1.80 per
unit on an annual basis). Approximately 10 million of the 17 million Units held
by PAAI are Subordinated Units. Upon expiration of the Subordination Period, all
Subordinated Units will be converted on a one-for-one basis into Common Units
and will participate pro rata with all other Common Units in future
distributions of Available Cash. Under certain circumstances, up to 50% of the
Subordinated Units may convert into Common Units prior to the expiration of the
Subordination Period. Common Units will not accrue arrearages with respect to
distributions for any quarter after the Subordination Period and Subordinated
Units will not accrue any arrearages with respect to distributions for any
quarter.

     If quarterly distributions of Available Cash exceed the MQD or the Target
Distribution Levels (as defined), the General Partner will receive distributions
which are generally equal to 15%, then 25% and then 50% of the distributions of
Available Cash that exceed the MQD or Target Distribution Level. The Target
Distribution Levels are based on the amounts of Available Cash from PAA's
Operating Surplus (as defined) distributed with respect to a given quarter that
exceed distributions made with respect to the MQD and Common Unit arrearages, if
any.

     On February 12, 1999, PAA paid a cash distribution of $0.193 per unit on
its outstanding Common Units and Subordinated Units. The $5.8 million
distribution was paid to all Unitholders of record at the close of business on
January 29, 1999. A distribution of approximately $118,000 was paid to PAAI as
general partner and $3.3 million as limited partner with the remainder being
distributed to PAA's public Unitholders. The distributions represented a partial
quarterly distribution for the 39-day period from November 23, 1998, the closing
of the IPO, through December 31, 1998.

  Revolving Credit Facility

     The Company has a $225 million revolving credit facility (the "Revolving
Credit Facility") with a group of banks (the "Lenders"). The Revolving Credit
Facility is guaranteed by all of the Company's upstream subsidiaries and is
secured by the upstream oil and gas properties of the Company and the
guaranteeing subsidiaries and the stock of such subsidiaries. The borrowing base
under the Revolving Credit Facility is subject to borrowing base availability as
determined 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 oil and natural gas loans to borrowers
similar to the Company. Such borrowing base may be affected from time to time by
the performance of the Company's oil and natural gas properties and changes in
oil and natural gas prices. The borrowing base was affirmed at $225 million in
December 1998. The next redetermination will be in the second quarter of 1999.
The Company incurs 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, 2000, at which time the remaining outstanding balance converts to a term loan
which is repayable in twenty equal quarterly installments commencing October 1,
2000, with a final maturity of July 1, 2005. The Revolving Credit Facility bears
interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as
defined therein). At December 31, 1998, outstanding borrowings under the
Revolving Credit Facility were $52 million.

                                       42
<PAGE>
 
  Capital Expenditures

     At December 31, 1998, the Company had a working capital deficit of
approximately $13.9 million. The Company has historically operated with a
working capital deficit due primarily to ongoing capital expenditures that have
been financed through cash flow and the Revolving Credit Facility. The working
capital deficits at December 31, 1997 and 1996, were $6.0 million and $4.8
million, respectively.

     The Company has made and will continue to make, substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of oil and natural gas reserves. Historically, the Company has
financed these expenditures primarily with cash generated by operations, bank
borrowings and the sale of subordinated notes, common stock and preferred stock.
The Company intends to make aggregate capital expenditures of approximately $76
million in 1999, including approximately $64 million on the development and
exploitation of its California, Sunniland Trend and Illinois Basin properties,
approximately $3 million on exploration activities primarily in the Sunniland
Trend, approximately $8.8 million for midstream activities, primarily related to
the expansion of the Cushing Terminal, and approximately $0.6 million for other
equipment. In addition, the Company intends to continue to pursue the
acquisition of underdeveloped producing properties. The Company believes that it
will have sufficient cash from operating activities and borrowings under the
Revolving Credit Facility to fund such planned capital expenditures. The
midstream capital expenditures are expected to be funded by PAA through working
capital, cash flow and draws under the PAA Revolving Credit Facility.

  Changing Oil and Natural Gas Prices

     The Company's upstream activities are affected by changes in crude oil
prices which have historically been volatile. Although the Company has routinely
hedged a substantial portion of its crude oil production and intends to continue
this practice, substantial future crude oil price declines would adversely
affect the Company's overall results, and therefore its liquidity. Furthermore,
low crude oil prices could affect the Company's ability to raise capital on
terms favorable to the Company. In order to manage its exposure to commodity
price risk, the Company has routinely hedged a portion of its crude oil
production. For 1999, the Company has entered into crude oil swap agreements
which provide the Company with downside price protection on approximately 9,000
barrels of oil per day at a NYMEX Crude Oil Price of approximately $18.25 per
barrel. Thus, based on the Company's average fourth quarter 1998 crude oil
production rate, these arrangements generally provide the Company with downside
price protection for approximately 45% of its production. In addition, the
Company has fixed price arrangements on 2,000 barrels per day in 2000 at a NYMEX
Crude Oil Price of $15.30 per barrel, or approximately 10% of fourth quarter
1998 crude oil production levels. The foregoing NYMEX Crude Oil Prices are
before quality and location differentials. Management intends to continue to
maintain hedging arrangements for a significant portion of its production. Such
contracts may expose the Company 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".

     Additionally, decreases in the prices of oil and natural gas have had, and
could have in the future, an adverse effect on the carrying value of the
Company's proved reserves and the Company's revenues, profitability and cash
flow. Almost all of the Company's reserve base (approximately 90% of year-end
1998 reserve volumes) is comprised of long-life oil properties that are
sensitive to crude oil price volatility. The benchmark NYMEX Crude Oil Price at
December 31, 1998, upon which proved reserve volumes, the Present Value of
Proved Reserves and the Standardized Measure as of such date were based, was
$12.05 per barrel. Such price was the lowest year-end price since oil was
deregulated in 1980 and was approximately 34% below the price used in preparing
reserve estimates at the end of 1997. Under full-cost accounting rules as
prescribed by the SEC, unamortized costs of proved oil and natural gas
properties are subject to a ceiling, which limits such costs to the Standardized
Measure. At December 31, 1998, the capitalized costs of the Company's proved oil
and natural gas properties exceeded the Standardized Measure, and the Company
recorded a non-cash, after-tax charge to expense of $109.0 million ($173.9
million pre-tax).

     As is common with most merchant activities, the ability of the Company to
generate a profit on its 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 it sells 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.

  Investing Activities

     Net cash flows used in investing activities were $483.4 million, $107.6
million and $52.5 million for the years ended December 31, 1998, 1997 and 1996,
respectively. Included in such amounts are payments, net of cash received from
property 

                                       43
<PAGE>
 
sales and reimbursements from partners, for acquisition, development and
exploration costs of $80.2 million, $103.0 million and $49.9 million for the
same periods, respectively. Approximately $394.0 million and $4.2 million
related to the All American Pipeline Acquisition and the Cushing Terminal
expansion, respectively, are included in investing activities for 1998. Such
payments for 1997 include $22.0 million related to the acquisition of the
Montebello Field. The Company expended $1.1 million, $4.7 million and $2.6
million in 1998, 1997 and 1996, respectively, for other property additions,
primarily for surface fee land acquired in connection with the Montebello Field
in 1997, midstream activities and computer equipment.

  Financing Activities

     Net cash provided by financing activities amounted to $448.6 million, $78.5
million and $9.9 million for 1998, 1997 and 1996, respectively. Aggregate
proceeds from long-term borrowings for these same years were $570.6 million,
$266.9 million and $263.7 million, respectively, while payments of long-term
debt were $423.6 million, $207.0 million and $248.1 million for the respective
periods. Financing activities for 1998 include the following related to the All
American Acquisition: (i) approximately $300 million in borrowings and $15
million in repayments under the PAAI Credit Facility; (ii) proceeds of $85
million from the issuance of the Series E Preferred Stock; (iii) approximately
$16 million in borrowings under the Revolving Credit Facility to fund the
Company's capital contribution to PAAI and (iv) approximately $6.1 million of
financing costs. Financing activities for 1998 related to the PAA IPO include
(i) approximately $242.1 million in net proceeds; (ii) approximately $117
million in repayments on the PAAI Credit Facility; (iii) approximately $123.6
million of repayments on the Revolving Credit Facility and (iv) approximately
$9.9 million of financing costs. Approximately $25 million borrowed under the
Revolving Credit Facility to fund the acquisition of the Montebello Field and
related surface fee land is included in proceeds from long-term debt in 1997.
Also included in financing activities during 1997 are net proceeds of
approximately $53 million from the sale of the Company's Series C & D 10.25%
Notes and a corresponding payment on the Revolving Credit Facility. Financing
activities during 1996 include net proceeds of approximately $144.6 million from
the Company's Series A & B 10.25% Notes, approximately $107 million for the
repayment of the Company's 12% Notes, including the 6% call premium and the net
defeasance costs, and approximately $42 million for the repayment of the
Illinois Basin acquisition bridge indebtedness. Remaining long-term debt
activity is primarily related to advances received and payments made on the
Revolving Credit Facility. Financing activities during 1998 and 1997 include
proceeds of $32 and $39 million, respectively, from short-term borrowings and
$40 and $21 million, respectively, of repayments related to crude oil inventory
transactions at the Cushing Terminal. Financing activities include proceeds from
the sale of capital stock of $0.8 million, $1.1 million and $1.8 million in
1998, 1997 and 1996, respectively. Such proceeds were primarily from the
exercise of employee stock options.

  Commitments

     Although the Company obtained environmental studies on its properties in
California, the Sunniland Trend and Illinois Basin, and the Company believes
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.

     Consistent with normal industry practices, substantially all of the
Company's 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. The Company has estimated that the costs to perform these tasks is
approximately $12.8 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 1998, 1997 and 1996 include $0.8 million, $0.6 million and
$0.8 million, respectively, of expense associated with these estimated future
costs. For valuation and realization purposes of the affected 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.

     PAA owns approximately 5.0 million barrels of crude oil that is used to
maintain the All American Pipeline's linefill requirements. PAA amended its
tariff with the FERC to require third party shippers to buy linefill from PAA
and replenish the linefill when their movement of crude oil on the All American
Pipeline System is completed. Accordingly, PAA does not anticipate large
variations in the amounts of linefill provided by PAA in the future.

Year 2000

     Year 2000 Issue. Some software applications, hardware and equipment and
embedded chip systems identify dates using only the last two digits of the year.
These products may be unable to distinguish between dates in the Year 2000 and
dates in the 

                                       44
<PAGE>
 
year 1900. That inability (referred to as the "Year 2000" issue), if not
addressed, could cause applications, equipment or systems to fail or provide
incorrect information after December 31, 1999, or when using dates after
December 31, 1999. This in turn could have an adverse effect on the Company,
because the Company directly depends on its own applications, equipment and
systems and indirectly depends on those of other entities with which the Company
must interact.

     Compliance Program. In order to address the Year 2000 issues, the Company
has implemented a Year 2000 project for all of its business units. A project
team has been established to coordinate the six phases of this Year 2000 project
to assure that key automated systems and related processes will remain
functional through Year 2000. Those phases include:  (i) awareness, (ii)
assessment, (iii) remediation, (iv) testing, (v) implementation of the necessary
modifications and (vi) contingency planning. The key automated systems consist
of (a) financial systems applications, (b) hardware and equipment, (c) embedded
chip systems and (d) third-party developed software. The evaluation of the Year
2000 issue includes the evaluation of the Year 2000 exposure of third parties
material to the operations of the Company or any of its business units. The
Company retained a Year 2000 consulting firm to review the operations of all of
its business units and to assess the impact of the Year 2000 issue on such
operations. Such review has been completed and the consultant's recommendations
are being utilized in the Year 2000 project.

     The Company's State of Readiness. The awareness phase of the Year 2000
project has begun with a corporate-wide awareness program which will continue to
be updated throughout the life of the project. The portion of the assessment
phase related to financial systems applications has been substantially completed
and the necessary modifications and conversions are underway. The portion of the
assessment phase which will determine the nature and impact of the Year 2000
issue for hardware and equipment, embedded chip systems, and third-party
developed software is continuing. The Company has retained a Year 2000
consulting firm which is currently identifying and evaluating field equipment
which has embedded chip systems. The assessment phase of the project involves,
among other things, efforts to obtain representations and assurances from third
parties, including third party vendors, that their hardware and equipment,
embedded chip systems, and software being used by or impacting the Company or
any of its business units are or will be modified to be Year 2000 compliant. To
date, the responses from such third parties are inconclusive. As a result,
management cannot predict the potential consequences if these or other third
parties are not Year 2000 compliant. The exposure associated with the Company's
interaction with third parties is currently being evaluated. Management expects
that the remediation, testing and implementation phases will be substantially
completed by the third quarter of 1999.

     Contingency Planning. As part of the Year 2000 project, the Company will
seek to determine which of its business activities may be vulnerable to a Year
2000 disruption. Appropriate contingency plans will then be developed for each
"at risk" business activity to provide an alternative means of functioning which
minimizes the effect of the potential Year 2000 disruption, both internally and
on those with whom it does business. Such contingency plans are expected to be
completed by the fourth quarter of 1999.

     Costs to Address Year 2000 Compliance Issues. Through December 31, 1998,
the Company has expended approximately $380,000 in its Year 2000 project,
excluding costs borne by PAA. While the total cost to the Company of the Year
2000 project is still being evaluated, the Company currently estimates that the
costs to be incurred in 1999 and 2000 associated with assessing, testing,
modifying or replacing financial system applications, hardware and equipment,
embedded chip systems and third party developed software is between $350,000 and
$450,000. The Company expects to fund these expenditures with cash from
operations or borrowings. Based upon these estimates, the Company does not
expect the costs of its Year 2000 project to have a material adverse effect on
its financial position, results of operation or cash flows.

     Risk of Non-Compliance. The major applications that pose the greatest Year
2000 risks for the Company if implementation of the Year 2000 compliance program
is not successful are the Company's financial systems applications and the
Company's SCADA computer systems and embedded chip systems in field equipment.
The potential problems if the Year 2000 compliance program is not successful are
disruptions of the Company's revenue gathering from and distribution to its
customers and vendors and the inability to perform its other financial and
accounting functions. Failures of embedded chip systems in field equipment of
the Company or its customers could disrupt the Company's upstream exploitation,
development, production and exploration activities and its midstream crude oil
transportation, terminalling and storage activities and gathering and marketing
activities.

     While the Company believes that its Year 2000 project will substantially
reduce the risks associated with the Year 2000 issue, there can be no assurance
that it will be successful in completing each and every aspect of the project on
schedule, and if successful, the project will have the expected results. Due to
the general uncertainity inherent in the Year 2000 issues, the 

                                       45
<PAGE>
 
Company cannot conclude that its failure or the failure of third parties to
achieve Year 2000 compliance will not adversely affect its financial position,
results of operations or cash flows.

Item 7a QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

     The Company is exposed to various market risks, including volatility in
crude oil and natural gas commodity prices and interest rates. To manage such
exposure, the Company enters into various derivative transactions. The Company
does not enter into derivative transactions for speculative trading purposes.
Substantially all the Company's derivative contracts are exchange traded or with
major financial institutions and the risk of credit loss is considered remote.

     In its upstream activities, in order to manage its exposure to commodity
price risk, the Company routinely hedges a portion of its crude oil production.
For 1999, the Company has entered into crude oil swap agreements that provide
the Company with downside price protection on approximately 9,000 barrels of oil
per day at a NYMEX Crude Oil Price of approximately $18.25 per barrel. Thus,
based on the Company's average fourth quarter 1998 crude oil production rate,
these arrangements provide the Company with downside price protection for
approximately 45% of its crude oil production throughout 1999. Subsequent to
December 31, 1998, the Company entered into additional arrangements which fix
the price on 2,000 barrels per day in 2000 at a NYMEX Crude Oil Price of $15.30
per barrel, or approximately 10% of fourth quarter 1998 crude oil production
levels. While these hedging arrangements reduce the Company's exposure to
decreases in crude oil prices, they may also limit the benefit the Company might
otherwise receive from crude oil price increases

     In its midstream activities, as the Company purchases crude oil, it
establishes 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, the Company seeks to maintain a position that is
substantially balanced between crude oil purchases and sales and future delivery
obligations. From time to time, the Company enters into fixed price delivery
contracts, floating price collar arrangements, financial swaps and oil futures
contracts as hedging devices. To ensure a fixed price for future production, the
Company may sell a futures contract and thereafter either (i) make physical
delivery of its product to comply with such contract or (ii) buy a matching
futures contract to unwind its futures position and sell its production to a
customer. Such contracts may expose the Company to the risk of financial loss in
certain circumstances, including instances where production is less than
expected, the Company's customers fail to purchase or deliver the contracted
quantities of crude oil , or a sudden, unexpected event materially affects crude
oil prices. Such contracts may also restrict the ability of the Company to
benefit from unexpected increases in crude oil prices. The Company's policy is
generally to purchase only crude oil for which it has a market and to structure
its sales contracts so that crude oil price fluctuations do not materially
affect the gross margin which it receives. The Company does 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 the Company to
indeterminable losses.

     The Company has interest rate swaps on an aggregate $200 million notional
principal amount, which fix the LIBOR portion of the interest rate (not
including the applicable margin) on the Term Loan Facility and a portion of the
Revolving Credit Facility. At December 31, 1998, the Company would be required
to pay approximately $3.3 million to terminate the interest rate swaps.

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:

                                           Change in Fair     
                                Fair       Value from 10%       
        At December 31, 1998    Value   Adverse Price Change
        --------------------   ------   --------------------
                                  (in millions)      

        Crude Oil
         Swaps                 $ 16.9           $ (4.3) 
         Futures contracts        1.8             (0.3)
                        

     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 NYMEX market prices compared to the contract price of the swap and
approximate the 

                                       46
<PAGE>
 
gain 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 prices,
the fair value of the Company's derivative portfolio would typically change less
than that shown in the table due to lower volatility in out-month prices.

Interest Rate Risk

     The Company's debt instruments are sensitive to market fluctuations in
interest rates. The table below presents principal cash flows and the related
weighted average interest rates by expected maturity dates. The Company's
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, 1998. 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, 1998.

<TABLE> 
<CAPTION> 
                                                                  December 31,
                                   -------------------------------------------------------------------------
                                                            Expected Year of Maturity
                                   -------------------------------------------------------------------------       Fair
                                       1999        2000      2001      2002      2003    Thereafter    Total       Value
                                     --------    -------   -------   -------   -------   ----------   -------    ---------
                                                              (dollars in millions)
Liabilities:
<S>                                   <C>        <C>       <C>       <C>       <C>        <C>         <C>         <C> 
  Short-term debt  - variable rate    $  9.7     $   -     $   -     $   -     $   -      $   -       $   9.7     $   9.7
    Average interest rate               6.80%
  Long-term debt - variable rate           -         -         -         -         -        175.0       175.0       175.0
    Average interest rate                  -         -         -         -         -         6.75%
  Long-term debt - fixed rate              -         -         -         -         -        200.0       200.0       202.0
    Average interest rate                  -         -         -         -         -        10.25%
Redeemable Preferred Stock                 -         -         -         -         -      $  88.5        88.5        88.5
</TABLE> 

     Additional details regarding accounting policy for these financial 
instruments are set forth in Note 1 to the Consolidated Financial Statements.

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The information required to be provided in this item is included in the 
Consolidated Financial Statements of the Company, including the Notes thereto, 
attached hereto as pages F-1 to F-30 and such information is incorporated herein
by reference.

Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 
         FINANCIAL DISCLOSURE

     There were no disagreements on accounting and financial disclosure with the
Company's independent accountants.


                                 PART III

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     Information regarding the directors of the Company will be included in the
proxy statement for the 1999 Annual Meeting of Stockholders (the "Proxy
Statement") to be filed within 120 days after December 31, 1998, and is
incorporated herein by reference. Information with respect to the Company's
executive officers is presented in Part I, Item 4 of this Report.

                                       47
<PAGE>
 
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

     Information, if any, regarding beneficial ownership of the Common Stock
will be included in the Proxy Statement and is incorporated herein by reference.

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.

                                 PART IV

Item 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

  (a)  (1)  Financial Statements

          The financial statements filed as part of this report are listed in
          the "Index to Consolidated Financial Statements" on Page F-1 hereof.

    (2)  Exhibits

       2(a)    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(a)    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(b)    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(c)    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(d)    Certificate of Designation, Preference and Rights of Series E
               Cumulative Convertible Preferred Stock (incorporated by reference
               to Exhibit 3.1 to the Company's Current Report on Form 8-K filed
               August 11, 1998).

       4       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(a)    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(b)    Specimen Common Stock Certificate (incorporated by reference to
               Exhibit 4 to the Company's Form S-1 Registration Statement (Reg.
               No. 33-33986)).

       4(c)    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(d)    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).

       10(a)*  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).

                                       48
<PAGE>
 
       10(b)*  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(c)*  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(d)*  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(e)*  The Company's 1996 Stock Incentive Plan (incorporated by
               reference to Exhibit 4 to the Company's Form S-8 Registration
               Statement (Reg. No. 333-06191)).

       10(f)*  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(g)*  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(h)*  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(i)*  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(j)   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(k)   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(l)   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(m)   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.

       10(n)   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.

       10(o)*  Employment Agreement dated as of November 23, 1998, between Harry
               N. Pefanis and the Company.

       21      Subsidiaries of the Company.

       23(a)   Consent of PricewaterhouseCoopers LLP.

       27(b)   Financial Data Schedule for the year ended December 31, 1998.

       *A management contract or compensation plan.

  (b)  Reports on Form 8-K

    Amendment No. 2 to Current Report filed on December 7, 1998, on form 8-K/A
    which amends the following items, financial statements, exhibits or other
    portion of the Current Report on Form 8-K filed with the Securities and
    Exchange Commission on August 11, 1998, by the Company in connection with
    the acquisition by Plains All American Inc., a wholly-owned subsidiary of
    the Company, of three subsidiaries from Wingfoot Ventures Seven, Inc.

    A Current Report on Form 8-K filed December 7, 1998, with respect to the
    Company's transfer of its midstream assets to PAA and its operating
    partnerships, Plains Marketing, L.P. and All American Pipeline, L.P. by
    Plains All American Inc., a wholly owned subsidiary of the Company. This
    report also provided information on PAA's initial public offering of Common
    Units which closed on November 23, 1998.

                                       49
<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:  March 31, 1999               By:  /s/ Phillip D. Kramer
                                       -------------------------------------- 
                                       Phillip D. Kramer, Executive Vice 
                                       President and Chief Financial Officer 
                                       (Principal Financial Officer)

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.



Date:  March 31, 1999               By:  /s/ Greg L. Armstrong
                                       -------------------------------------- 
                                       Greg L. Armstrong, President and
                                       Chief Executive Officer (Principal 
                                       Executive Officer)



Date:  March 31, 1999               By:  /s/ Jerry L. Dees
                                       -------------------------------------- 
                                       Jerry L. Dees, Director



Date:  March 31, 1999               By:  /s/ Tom H. Delimitros
                                       -------------------------------------- 
                                       Tom H. Delimitros, Director



Date:  March 31, 1999               By:  /s/ Cynthia A. Feeback
                                       -------------------------------------- 
                                       Cynthia A. Feeback, Assistant Treasurer,
                                       Controller and Principal Accounting 
                                       Officer (Principal Accounting Officer)



Date:  March 31, 1999               By:  /s/ William M. Hitchcock
                                       --------------------------------------
                                       William M. Hitchcock, Director



Date:  March 31, 1999               By:  /s/ Phillip D. Kramer
                                       -------------------------------------- 
                                       Phillip D. Kramer, Executive Vice 
                                       President and Chief Financial Officer 
                                       (Principal Financial Officer)



Date:  March 31, 1999               By:  /s/ Dan M. Krausse
                                       -------------------------------------- 
                                       Dan M. Krausse, Chairman of the Board and
                                       Director

                                       50
<PAGE>
 
Date:  March 31, 1999               By:  /s/ John H. Lollar
                                       -------------------------------------- 
                                       John H. Lollar, Director



Date:  March 31, 1999               By:  /s/ Robert V. Sinnott
                                       -------------------------------------- 
                                       Robert V. Sinnott, Director



Date:  March 31, 1999               By:  /s/ J. Taft Symonds
                                       --------------------------------------
                                       J. Taft Symonds, Director

     The Annual Report to Stockholders of the Company for the year ended
December 31, 1998, and the proxy statement relating to the annual meeting of
stockholders will be furnished to stockholders subsequent to the filing of this
Annual Report on Form 10-K. Such documents have not been mailed to stockholders
as of the date of this report.

                                       51
<PAGE>
 
                  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE> 
<CAPTION> 

                                                                                                 PAGE
                                                                                                 ----
Plains Resources Inc. and Subsidiaries Consolidated Financial Statements:
<S>                                                                                               <C> 
Report of Independent Accountants.................................................................F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997......................................F-3
Consolidated Statements of Operations for the years ended December 31, 1998, 1997 and 1996........F-4
Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996........F-5
Consolidated Statements of Changes in Stockholders' Equity for the years ended
    December 31, 1998, 1997 and 1996..............................................................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 present fairly, in all material respects, the financial position of Plains
Resources Inc. and its subsidiaries at December 31, 1998 and 1997, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1998, in conformity with generally accepted
accounting principles. 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 generally accepted auditing standards 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, 1999

                                      F-2
<PAGE>
 
                    PLAINS RESOURCES INC. AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS
                       (in thousands, except share data)

<TABLE> 
<CAPTION> 

                                                                                                   December 31,
                                                                                           ------------------------------
                                                                                               1998             1997
                                                                                           ------------     -------------
                                                    ASSETS
<S>                                                                                         <C>             <C> 
CURRENT ASSETS
Cash and cash equivalents                                                                   $    6,544      $     3,714
Accounts receivable                                                                            128,875           99,597
Inventory                                                                                       42,520           22,802
Prepaid expenses and other                                                                       1,527              667
                                                                                            -----------     ------------
Total current assets                                                                           179,466          126,780
                                                                                            -----------     ------------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
  Subject to amortization                                                                      596,203          498,038
  Not subject to amortization                                                                   54,545           52,024
Crude oil pipeline, gathering and terminal assets                                              378,254           35,451
Other property and equipment                                                                     8,606            8,074
                                                                                            -----------     ------------
                                                                                             1,037,608          593,587

Less allowance for depreciation, depletion and amortization                                   (375,882)        (180,279)
                                                                                            -----------     ------------
                                                                                               661,726          413,308
                                                                                            -----------     ------------
OTHER ASSETS                                                                                   133,075           16,731
                                                                                            -----------     ------------
                                                                                            $  974,267      $   556,819
                                                                                            ===========     ============
                                           LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable and other current liabilities                                              $  170,985      $   102,663
Interest payable                                                                                 7,950            6,601
Royalties payable                                                                                4,211            5,016
Notes payable and other current obligations                                                     10,261           18,511
                                                                                            -----------     ------------
Total current liabilities                                                                      193,407          132,791

BANK DEBT                                                                                       52,000           80,000
BANK DEBT OF A SUBSIDIARY                                                                      175,000                -
SUBORDINATED DEBT                                                                              202,427          202,661
OTHER LONG-TERM DEBT                                                                             2,556            3,067
OTHER LONG-TERM LIABILITIES                                                                     13,967            5,107
                                                                                            -----------     ------------
                                                                                               639,357          423,626
                                                                                            -----------     ------------
COMMITMENTS AND CONTINGENCIES (NOTE 13)

MINORITY INTEREST                                                                              173,461                -
                                                                                            -----------     ------------
SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK,
  STATED AT LIQUIDATION PREFERENCE                                                              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 $1,354,000 and $2,629,000
  at December 31, 1998 and 1997, respectively                                                   21,946           20,671
Common Stock, $.10 par value, 50,000,000 shares authorized; issued and outstanding
  16,881,938 and 16,703,074 shares at December 31, 1998 and 1997, respectively                   1,688            1,670
Additional paid-in capital                                                                     124,679          122,887
Accumulated deficit                                                                            (75,351)         (12,035)
                                                                                            -----------     ------------
                                                                                                72,962          133,193
                                                                                            -----------     ------------
                                                                                            $  974,267      $   556,819
                                                                                            ===========     ============
</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,
                                                                        --------------------------------------------
                                                                             1998           1997           1996
                                                                        -------------  -------------   -------------
REVENUES
<S>                                                                      <C>            <C>             <C> 
Oil and natural gas sales                                                $   102,754    $   109,403     $    97,601
Marketing, transportation, storage and terminalling revenues               1,129,689        752,522         531,698
Gain on formation of PAA (See Note 2)                                         60,815              -               -
Interest and other income                                                        834            319             309
                                                                        -------------  -------------   -------------
                                                                           1,294,092        862,244         629,608
                                                                        -------------  -------------   -------------
EXPENSES
Production expenses                                                           50,827         45,486          38,735
Marketing, transportation, storage and terminalling expenses               1,091,328        740,042         522,167
General and administrative                                                    10,778          8,340           7,729
Depreciation, depletion and amortization                                      31,020         23,778          21,937
Reduction in carrying cost of oil and natural gas properties                 173,874              -               -
Interest expense                                                              35,730         22,012          17,286
Litigation settlement                                                              -              -           4,000
                                                                        -------------  -------------   -------------
                                                                           1,393,557        839,658         611,854
                                                                        -------------  -------------   -------------

Income (loss) before income taxes, extraordinary item and
  minority interest                                                          (99,465)        22,586          17,754
Minority interest                                                              1,809              -               -
                                                                        -------------  -------------   -------------
Income (loss) before income taxes and extraordinary item                    (101,274)        22,586          17,754
Income tax expense (benefit)
  Current                                                                        862            352               -
  Deferred                                                                   (43,582)         7,975          (3,898)
                                                                        -------------  -------------   -------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM                                      (58,554)        14,259          21,652

EXTRAORDINARY ITEM:
  Loss on early extinguishment of debt, net of tax benefit                         -              -          (5,104)
                                                                        -------------  -------------   -------------
NET INCOME (LOSS)                                                            (58,554)        14,259          16,548
Less:  cumulative preferred stock dividends                                    4,762            163               -
                                                                        -------------  -------------   -------------
NET INCOME (LOSS) AVAILABLE TO COMMON
  STOCKHOLDERS                                                           $   (63,316)   $    14,096     $    16,548
                                                                        =============  =============   =============
Basic earnings per share:
  Income (loss) before extraordinary item                                $     (3.77)   $      0.85     $      1.32
  Extraordinary item                                                               -              -           (0.31)
                                                                        -------------  -------------   -------------
  Net income (loss)                                                      $     (3.77)   $      0.85     $      1.01
                                                                        =============  =============   =============
Diluted earnings per share:
  Income (loss) before extraordinary item                                $     (3.77)   $      0.77     $      1.23
  Extraordinary item                                                               -              -           (0.29)
                                                                        -------------  -------------   -------------
  Net income (loss)                                                      $     (3.77)   $      0.77     $      0.94
                                                                        =============  =============   =============
</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,
                                                                             ------------------------------------------
                                                                                 1998            1997          1996
                                                                             ------------   ------------   ------------

CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                           <C>            <C>            <C> 
Net income (loss)                                                             $  (58,554)    $   14,259     $   16,548
  Items not affecting cash flows from operating activities:
  Depreciation, depletion and amortization                                        31,020         23,778         21,937
  Reduction in carrying costs of oil and natural gas properties                  173,874              -              -
  Non-cash gain (See Note 2)                                                     (70,037)             -              -
  Minority interest in income                                                      1,809              -              -
  Loss on early extinguishment of debt, net of tax                                     -              -          5,104
  Deferred income taxes                                                          (43,582)         7,975         (3,898)
  Other non-cash items                                                                90            221            251
Change in assets and liabilities from operating activities:
  Accounts receivable                                                             24,952         (9,518)       (41,046)
  Inventory                                                                      (19,057)       (18,239)           551
  Purchase of pipeline linefill                                                   (3,904)             -              -
  Prepaids and other                                                                (868)           128            (64)
  Accounts payable and other current liabilities                                     410          9,858         37,296
  Interest payable                                                                 1,467          1,494            977
  Royalties payable                                                                   10            351          1,352
                                                                             ------------   ------------   ------------

Net cash provided by operating activities                                         37,630         30,307         39,008
                                                                             ------------   ------------   ------------

CASH FLOWS FROM INVESTING ACTIVITIES

Midstream acquisition (see Note 9):
  Payment for acquisition of pipeline and related assets                        (392,528)             -              -
  Payment for working capital (excluding cash received of $7,481)                 (1,498)             -              -
Payment for crude oil pipeline, gathering and terminal assets                     (8,131)          (923)        (1,850)
Cash received from the sale of oil and gas natural properties                        131          2,667          3,066
Payment for acquisition, exploration and developments costs                      (80,318)      (105,646)       (53,011)
Payment for additions to other property and assets                                (1,078)        (3,732)          (701)
                                                                             ------------   ------------   ------------

Net cash used in investing activities                                           (483,422)      (107,634)       (52,496)

CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from long-term debt                                                     570,560        266,905        263,723
Proceeds from short-term debt                                                     31,750         39,000              -
Proceeds from sale of capital stock, options and warrants                            828          1,104          1,785
Proceeds from issuance of preferred stock                                         85,000              -              -
Proceeds from issuance of common units (See Note 2)                              244,690              -              -
Principal payments of long-term debt                                            (423,560)      (207,011)      (248,144)
Principal payments of short-term debt                                            (40,000)       (21,000)             -
Costs incurred to redeem long-term debt                                                -              -         (6,468)
Debt issue and other costs incurred in connection with 
 acquisition (See Note 9)                                                         (6,138)             -              -
Debt issue and other costs incurred in connection with 
 public offering (See Note 2)                                                     (9,937)             -              -
Other                                                                             (4,571)          (474)        (1,020)
                                                                             ------------   ------------   ------------

Net cash provided by financing activities                                        448,622         78,524          9,876
                                                                             ------------   ------------   ------------

Net increase (decrease) in cash and cash equivalents                               2,830          1,197         (3,612)
Cash and cash equivalents, beginning of year                                       3,714          2,517          6,129
                                                                             ------------   ------------   ------------

Cash and cash equivalents, end of year                                        $    6,544     $    3,714     $    2,517
                                                                             ============   ============   ============
</TABLE> 

                See notes to consolidated financial statements.

                                      F-5
<PAGE>
 
                    PLAINS RESOURCES INC. AND SUBSIDIARIES
          CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
                                (in thousands)

<TABLE> 
<CAPTION> 

                                 Series D                  Series E
                                Cumulative                Cumulative                                  Additional      Accumu-
                               Convertible               Convertible                                    Paid-In        lated
                             Preferred Stock           Preferred Stock           Common Stock           Capital       Deficit
                         ------------------------  -----------------------  -----------------------  -------------  ------------
                           Shares       Amount       Shares       Amount      Shares      Amount
                         ----------  ------------  ----------  -----------  ----------  -----------
<S>                        <C>         <C>           <C>         <C>          <C>         <C>           <C>           <C> 
BALANCE AT
  DECEMBER 31, 1995             -      $      -           -      $      -     16,179      $ 1,618      $ 118,090      $ (42,679)

Capital stock issued
  upon exercise of
  options and other             -             -           -             -        340           34          1,961              -

Net income for the year         -             -           -             -          -            -              -         16,548
                         ----------  ------------  ----------  -----------  ----------  -----------  -------------  -------------

BALANCE AT
  DECEMBER 31, 1996             -             -           -             -     16,519        1,652        120,051        (26,131)

Capital stock issued
  upon exercise of
  options and other             -             -           -             -        184           18          1,936              -

Issuance of preferred
  stock and warrant
  in connection with
  an acquisition               47        20,508           -             -          -            -            900              -

Dividends on
  preferred stock               -           163           -             -          -            -              -           (163)

Net income for the year         -             -           -             -          -            -              -         14,259
                         ----------  ------------  ----------  -----------  ----------  -----------  -------------  -------------

BALANCE AT
  DECEMBER 31, 1997            47        20,671           -             -     16,703        1,670        122,887        (12,035)

Capital stock issued
  upon exercise of
  options and other             -             -           -             -        179           18          1,792              -

Issuance of
  preferred stock               -             -         170        85,000          -            -              -              -

Dividends on
  preferred stock               -         1,275           3         3,487          -            -              -         (4,762)

Net loss for the year           -             -           -             -          -            -              -        (58,554)
                         ----------  ------------  ----------  -----------  ----------  -----------  -------------  -------------

BALANCE AT
  DECEMBER 31, 1998            47      $ 21,946         173    $   88,487     16,882     $  1,688      $ 124,679      $ (75,351)
                         ==========  ============  ==========  ===========  ==========  ===========  =============  =============

</TABLE> 

                See notes to consolidated financial statements.

                                      F-6
<PAGE>
 
                    PLAINS RESOURCES INC. AND SUBSIDIARIES
                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                        
NOTE 1 - ACCOUNTING POLICIES

Principles of Consolidation and Presentation

     The consolidated financial statements include the accounts of Plains
Resources Inc. (the "Company"), its wholly-owned subsidiaries and Plains All
American Pipeline, L.P. ("PAA") in which the Company has an approximate 57%
ownership interest and serves as its sole general partner (See Note 2). For
financial statement purposes, the assets, liabilities and earnings of PAA are
included in the Company's consolidated financial statements, with the public
unitholders' interest reflected as a minority interest. All material
intercompany accounts and transactions have been eliminated. Certain
reclassifications have been made to the prior year statements to conform with
the current year presentation.

     The Company is an independent energy company engaged in the acquisition,
exploitation, development, exploration and production of crude oil and natural
gas. Through its majority ownership in PAA, the Company is engaged in the
midstream activities of marketing, transportation, terminalling and storage of
crude oil. The Company's upstream oil and natural gas activities are focused in
California in the Los Angeles Basin (the "LA Basin"), the Arroyo Grande Field
and the Mt. Poso Field (collectively the "California Properties"), the Sunniland
Trend of South Florida (the "Sunniland Trend") and the Illinois Basin in
southern Illinois (the "Illinois Basin"). The Company's midstream activities are
concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico.

     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. Estimates made by management include: oil and natural gas
reserves, depreciation, depletion and amortization, including future abandonment
costs, income taxes and related valuation allowance and pension 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. The Company's cash management program results in
book overdraft balances which have been reclassified to current liabilities.

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.

Oil and Natural Gas Properties

     The Company follows 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 the Company's 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 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 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 18).

                                      F-7
<PAGE>
 
Crude Oil Pipeline Gathering and Terminal Assets

     Crude oil pipeline, gathering and terminal assets are recorded at cost and
consist primarily of (i) crude oil pipeline facilities (primarily the All
American Pipeline System and SJV Gathering System), (ii) crude oil terminal and
storage facilities (primarily the Cushing Terminal), and (iii) trucking
equipment, injection stations and other. Depreciation is computed using the
straight-line method over estimated useful lives of 5 to 40 years. Pipeline
facilities are depreciated over estimated useful lives of twenty-five to forty
years. Depreciation on the Cushing Terminal is provided based on a useful life
of forty years. 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.

Pipeline Linefill

     Pipeline linefill 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. The Company owns approximately 5.0 million barrels of crude
oil that is used to maintain the All American Pipeline's 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.

Debt Issue Costs

     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.

Federal and State Income Taxes

     Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards ("SFAS ") No. 109, Accounting for Income Taxes. 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.

Marketing, Transportation, Storage and Terminalling Revenues

     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 the Company, which typically occurs upon receipt
of the product by the Company. Except for crude oil purchased from time to time
as inventory to service the needs of its terminalling and storage customers and
working requirements of third party pipelines, the Company's policy is to
purchase only crude oil for which it has a market to sell and to structure its
sales contracts so that crude oil price fluctuations do not materially affect
the gross margin which it receives. As the Company purchases crude oil, it
establishes 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 New York
Mercantile Exchange ("NYMEX"). Through these transactions, the Company seeks
to maintain a position that is substantially balanced between crude oil
purchases and sales and future delivery obligations. Terminalling and storage
revenues are recognized at the time service is performed. As a regulated
interstate pipeline, revenues for the transportation of crude oil on the All
American Pipeline is recognized based upon Federal Energy Regulatory Commission
("FERC") and the Public Utilities Commission of the State of California ("CPUC")
filed tariff rates and the related transported volume. Tariff revenue is
recognized at the time such volume is delivered.

Hedging

     The Company utilizes various derivative instruments to hedge its exposure
to price fluctuations on oil and natural gas transactions. The derivative
instruments used consist primarily of futures and option contracts traded on the
NYMEX and crude oil swap contracts entered into with financial institutions.
These instruments are utilized to hedge transactions which are based on NYMEX
oil and gas prices; therefore, a high correlation exists between the hedged item
and the hedge contract. The Company has entered into interest rate swaps to
manage the interest rate exposure on certain of its long-term debt.

                                      F-8
<PAGE>
 
     Recognized gains and losses on hedge contracts are reported as a component
of the related transaction. Results for hedging transactions are reflected in
oil and natural gas sales to the extent related to the Company's oil and natural
gas production and in marketing, transportation, storage and terminalling
revenues to the extent related to such activities. Cash flows from hedging
activities are included in operating activities in the Consolidated 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 accounts payable and other current liabilities in the
Consolidated Balance Sheets. Deferred gains or losses from inventory hedges are
included as part of the inventory cost and recognized when the related inventory
is sold. Crude oil swap contracts have no carrying value and therefore are not
reflected in the Consolidated Balance Sheets. Amounts paid or received from
interest rate swaps are charged or credited to interest expense over the term of
the swap.

Stock Options

     In October 1995, the Financial Accounting Standards Board ("FASB") issued
Statement No. 123 ("SFAS 123"), Accounting for Stock Based Compensation. In
accordance with the provisions of SFAS No. 123, the Company applies APB
Opinion 25 and related interpretations in accounting for its stock option plans
(See Note 12).

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 ("FAS 133"). FAS 133 is effective for all
fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company).
FAS 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 it is,
the type of hedge transaction. For fair-value hedge transactions in which the
Company is 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 the Company is 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. The Company has not yet determined the impact
that the adoption of FAS 133 will have on its earnings or financial position.

     In November 1998, the Emerging Issues Task Force ("EITF") released Issue
No. 98-10, "Accounting for Energy Trading and Risk Management Activities".
EITF 98-10 deals with entities that enter into derivatives and other third-party
contracts for the purchase and sale of a commodity in which they normally do
business (for example, crude oil and natural gas). The EITF reached a consensus
that energy trading contracts should be measured at fair value determined as of
the balance sheet date with the gains and losses included in earnings and
separately disclosed in the financial statements or footnotes thereto. The EITF
acknowledged that determining whether or when an entity is involved in energy
trading activities is a matter of judgment that depends on the relevant facts
and circumstances. As such, certain factors or indicators have been identified
by the EITF which should be considered in evaluating whether an operation's
energy contracts are entered into for trading purposes. EITF 98-10 is required
to be applied to financial statements issued by the Company beginning in 1999.
The adoption of this consensus is not expected to have a material impact on the
Company's results of operations or financial position.

NOTE 2 - PAA - INITIAL PUBLIC OFFERING AND CONCURRENT TRANSACTIONS
------------------------------------------------------------------

     The Company's midstream activities are conducted through PAA. PAA was
formed during 1998 to acquire and operate the business and assets of the
Company's wholly-owned midstream subsidiaries (the "Plains Midstream
Subsidiaries"). Plains All American Inc. ("PAAI" or the "General Partner"), a
wholly owned subsidiary of the Company, is the general partner of PAA.

     On November 23, 1998, PAA completed an initial public offering (the "IPO")
of 13,085,000 common units representing limited partner interests (the "Common
Units") in PAA and received therefrom net proceeds of approximately $244.7
million. Concurrently with the closing of the IPO, certain transactions
described in the following paragraphs were consummated in connection with the
formation of PAA. Such transactions and the transactions which occurred in
conjunction with the IPO are referred to herein as the "Transactions".

     Certain of the Plains Midstream Subsidiaries were merged into the Company,
which sold the assets of these subsidiaries to PAA in exchange for $64.1 million
and the assumption of $11 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, which it purchased in July 1998 for approximately $400
million (See Note 9), to PAA in exchange for (i) 6,974,239 Common Units,
10,029,619 Subordinated

                                      F-9
<PAGE>
 
Units and an aggregate 2% general partner interest in PAA, (ii) the right to
receive Incentive Distributions; and (iii) the assumption by PAA of $175 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 the Company, PAA distributed
approximately $177.6 million to the General Partner and used approximately $3
million of the remaining proceeds to pay expenses incurred in connection with
the Transactions. 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 balance, $56.6
million, was distributed to the Company, which used the cash to repay
indebtedness and for other general corporate purposes.

     In addition, concurrently with the closing of the IPO, PAA entered into a
$225 million bank credit agreement (the "Bank Credit Agreement") that includes
a $175 million term loan facility (the "Term Loan Facility") and a $50 million
revolving credit facility (the "PAA Revolving Credit Facility") (See Note 4).

     During 1998, the Company recognized a pretax gain (net of approximately
$9.2 million in formation related expenses) in connection with the formation of
PAA. Such gain is the result of an increase in the book value of the Company's
equity in PAA to reflect their proportionate share of the underlying net assets
of PAA due to the sale of units in the IPO. 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.

NOTE 3 - INVENTORY AND OTHER ASSETS
-----------------------------------

     Inventory consists of the following:

                                       December 31,
                                ---------------------------
                                   1998           1997
                                ------------   ------------
                                      (in thousands)
Crude oil                          $ 37,702       $ 18,986
Materials and supplies                4,818          3,816
                                ------------   ------------
                                   $ 42,520       $ 22,802
                                ============   ============

     At December 31, 1998 and 1997, approximately 76% and 77%, respectively, of
the crude oil inventory volumes were hedged with NYMEX futures contracts or
short-term physical delivery contracts. The unhedged inventory is comprised of
working inventory and linefill primarily at the Cushing Terminal.

     Other assets consist of the following:


                                              December 31,
                                    -------------------------------
                                         1998            1997
                                    ---------------  --------------
                                            (in thousands)

Pipeline linefill                         $ 54,511             $ -
Deferred tax asset (See Note 7)             47,785             796
Land                                         8,853           8,853
Debt issue costs                            19,026           8,718
Other                                        9,218           2,776
                                    ---------------  --------------
                                           139,393          21,143
Accumulated amortization                    (6,318)         (4,412)
                                    ---------------  --------------
                                          $133,075        $ 16,731
                                    ===============  ==============


                                      F-10
<PAGE>
 
NOTE 4 - LONG-TERM DEBT AND CREDIT FACILITIES
---------------------------------------------

           Long-term debt consists of the follows:

<TABLE> 
<CAPTION> 
                                                                                    December 31,        
                                                                              --------------------------
                                                                                 1998          1997     
                                                                              ------------  ------------
                                                                                   (in thousands)            
           <S>                                                                   <C>           <C> 
           Revolving Credit Facility, bearing interest at weighted                                      
             average interest rates of 6.9% and 7.3%, at                                                
             December 31, 1998 and 1997, respectively                            $ 52,000      $ 80,000 
           PAA Bank Credit Agreement, bearing interest                                                  
             at 6.75% at December 31, 1998.                                       175,000             - 
           10.25% Senior Subordinated Notes, due 2006, net of                                           
             unamortized premium of $2.4 million and $2.7 million                                       
             at December 31, 1998 and 1997, respectively                          202,427       202,661 
           Other long-term debt                                                     3,067         3,578 
                                                                              ------------  ------------
             Total long-term debt                                                 432,494       286,239 
             Less current maturities                                                 (511)         (511)
                                                                              ------------  ------------
                                                                                $ 431,983     $ 285,728 
                                                                              ============  ============ 
</TABLE> 

Revolving Credit Facility

     The Company has a $225 million revolving credit facility (the "Revolving
Credit Facility") with a group of banks (the "Lenders"). The Revolving Credit
Facility is guaranteed by all of the Company's upstream subsidiaries and is
collateralized by the oil and gas properties of the Company and the guaranteeing
subsidiaries and the stock of all upstream subsidiaries. The borrowing base
under the Revolving Credit Facility at December 31, 1998, is $225 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 oil and natural gas
loans to borrowers similar to the Company. Such borrowing base may be affected
from time to time by the performance of the Company's oil and natural gas
properties and changes in oil and natural gas prices. The Company incurs 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, 2000, at which
time the remaining outstanding balance converts to a term loan which is
repayable in twenty equal quarterly installments commencing October 1, 2000,
with a final maturity of July 1, 2005. The Revolving Credit Facility bears
interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as
defined therein). At December 31, 1998, outstanding borrowings under the
Revolving Credit Facility were $52 million.

     The Revolving Credit Facility contains covenants which, among other things,
prohibit the payment of cash dividends, limit the amount of consolidated debt,
limit the Company's ability to make certain loans and investments, and provides
that the Company must maintain a Current Ratio, as defined, of 1:1.

10.25% Senior Subordinated Notes Due 2006

     The Company has $200 million principal amount of 10.25% Senior
Subordinated Notes Due 2006 (the "10.25% Notes") outstanding which bear a coupon
rate of 10.25% and consist of (i) Series A - $.5 million principal amount; (ii)
Series B - $149.5 million principal amount; (iii) Series C - $50,000 principal
amount and (iv) Series D - $49.95 million principal amount.

     The Series A & B  10.25% Notes were issued  in 1996 at 99.38% of par to
yield 10.35%. Proceeds from the sale of the Series A and B 10.25% Notes, net of
offering costs, were approximately $144.6 million and were used to redeem the
Company's 12% Senior Subordinated Notes due 1999 (the "12% Notes") at 106% of
the $100 million principal amount outstanding and to retire $42 million of
bridge bank indebtedness which was incurred in December 1995 in connection with
the acquisition of the Company's Illinois Basin properties. The 12% Notes were
redeemed in April 1996, and the Company recognized an extraordinary loss of $8.5
million, $5.1 million net of deferred income taxes, in connection therewith.

     The Series C & D 10.25% Notes were issued in 1997 at approximately 107% of
par to yield a minimum yield to worst of 8.79%, or 9.03% to maturity. Proceeds
from the sale of the Series C & D 10.25% Notes, net of offering costs, were
approximately $53 million and were used to reduce the balance on the Revolving
Credit Facility.

                                      F-11
<PAGE>
 
     The 10.25% Notes are redeemable, at the option of the Company, 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.
In addition, prior to March 15, 1999, up to $45 million in principal amount of
the Series A & B 10.25% Notes and up to $15 million in principal amount of the
Series C & D 10.25% Notes are redeemable at the option of the Company, in whole
or in part, from time to time, at 110.25% of the principal amount thereof, with
the Net Proceeds of any Public Equity Offering (as both are defined in the
indenture under which the 10.25% Notes were issued (the "Indenture")).

     The Indenture contains covenants including, but not limited to the
following: (i) limitations on incurrence of additional indebtedness; (ii)
limitations on certain investments; (iii) limitations on restricted payments;
(iv) limitations on dispositions of assets; (v) limitations on dividends and
other payment restrictions affecting subsidiaries; (vi) limitations on
transactions with affiliates; (vii) limitations on liens; and (viii)
restrictions on 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, the Company will be required to make an offer to repurchase the
10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid
interest to the date of the repurchase. The 10.25% Notes are unsecured general
obligations of the Company and are subordinated in right of payment to all
existing and future senior indebtedness of the Company and are guaranteed by all
of the Company's principal subsidiaries.

PAA Credit Facilities

  Bank Credit Agreement.

     PAA has a $225 million Bank Credit Agreement which consists of the $175
million Term Loan Facility and the $50 million PAA Revolving Credit Facility.
The $50 million PAA Revolving Credit Facility is used for capital improvements
and working capital and general business purposes and contains a $10 million
sublimit for letters of credit issued for general corporate purposes. The Bank
Credit Agreement is secured by a lien on substantially all of the assets of PAA.

     The Term Loan Facility bears interest at PAA's option at either (i) the
Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin.
PAA has two 10-year interest rate swaps (subject to cancellation by the counter
party after seven years) aggregating $175 million notional principal amount,
which fix the LIBOR portion of the interest rate (not including the applicable
margin) at a weighted average rate of approximately 5.24%. Borrowings under the
Revolving Credit Facility bear interest at PAA's option at either (i) the Base
Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. PAA
incurs a commitment fee on the unused portion of the PAA Revolving Credit
Facility and, with respect to each issued letter of credit, an issuance fee.

     At December 31, 1998, PAA had $175 million outstanding under the Term Loan
Facility, which amount represents indebtedness assumed from the General Partner.
The Term Loan Facility matures in seven years, and no principal is scheduled for
payment prior to maturity. The Term Loan Facility may be prepaid at any time
without penalty. The PAA Revolving Credit Facility expires in two years. All
borrowings for working capital purposes outstanding under the PAA Revolving
Credit Facility must be reduced to no more than $8 million for at least 15
consecutive days during each fiscal year. At December 31, 1998, there are no
amounts outstanding under the PAA Revolving Credit Facility.

  Letter of Credit Facility

     Simultaneously with the IPO, PAA entered into a $175 million secured letter
of credit and borrowing facility with BankBoston, N.A. ("BankBoston"), ING
(U.S.) Capital Corporation ("ING Baring") and certain other lenders (the
"Letter of Credit Facility"), which replaced the existing facility for the
benefit of one of the Plains Midstream Subsidiaries. The purpose of the Letter
of Credit Facility is to provide (i) standby letters of credit to support the
purchase and exchange of crude oil for resale and (ii) borrowings to finance
crude oil inventory which has been hedged against future price risk or has been
designated as working inventory. The Letter of Credit Facility is collateralized
by a lien on substantially all of the assets of PAA. 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
current assets and current liabilities of PAA, primarily crude oil inventory and
accounts receivable and accounts payable related to the purchase and sale of
crude oil. At December 31, 1998, the borrowing base under the Letter of Credit
Facility was approximately $175 million.

     The Letter of Credit Facility has a $40 million sublimit for borrowings to
finance crude oil purchased in connection with operations at PAA's crude oil
terminal and storage facilities. All purchases of crude oil inventory financed
are required to be hedged against future price risk on terms acceptable to the
lenders. At December 31, 1998, approximately $9.8 million was

                                      F-12
<PAGE>
 
outstanding under the sublimit. At December 31, 1997, approximately $18 million
in borrowings was outstanding under a similar sublimit under a previous credit
facility.

     Letters of credit under the Letter of Credit Facility are generally issued
for up to 70 day periods. Borrowings bear interest at PAA's option at either (i)
the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the applicable
margin. PAA incurs a commitment fee on the unused portion of the borrowing
sublimit under the Letter of Credit Facility and an issuance fee for each letter
of credit issued. The Letter of Credit Facility expires July 31, 2001.

     At December 31, 1998 and 1997, there were outstanding letters of credit of
approximately $62 million and $38 million, respectively, issued under the Letter
of Credit Facility and a previous letter of credit facility, respectively. To
date, no amounts have been drawn on such letters of credit issued by PAA or the
Plains Midstream Subsidiaries.

     Both the Letter of Credit Facility and the Bank Credit Agreement contain a
prohibition on distributions on, or purchases or redemption's of, Units if any
Default or Event of Default (as defined) is continuing. In addition, both
facilities contain various covenants limiting the ability of PAA to (i) incur
indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain
limitations, (iv) engage in transactions with affiliates, (v) make investments,
(vi) enter into hedging contracts and (vii) enter into a merger, consolidation
or sale of its assets. In addition, the terms of the Letter of Credit Facility
and the Bank Credit Agreement require PAA to maintain (i) a Current Ratio (as
defined) of 1.0 to 1.0; (ii) a Debt Coverage Ratio (as defined) which is not
greater than 5.0 to 1.0; (iii) an Interest Coverage Ratio (as defined) which is
not less than 3.0 to 1.0; (iv) a Fixed Charge Coverage Ratio (as defined) which
is not less than 1.25 to 1.0; and (v) a Debt to Capital Ratio (as defined) of
not greater than .60 to 1.0. In both the Letter of Credit Facility and the Bank
Credit Agreement, a Change in Control (as defined) of the Company constitutes an
Event of Default.

Maturities

     The aggregate amount of maturities of all long-term indebtedness for the
next five years is:  1999 - $.5 million, 2000 - $3.1 million, 2001 - $10.9
million, 2002 - $10.9 million and 2003 - $10.9 million.

NOTE 5 - CAPITAL STOCK
----------------------

Common Stock

     The Company has authorized capital stock consisting of 50 million shares of
common stock, $.10 par value, and 2 million shares of preferred stock, $1.00 par
value. At December 31, 1998, there were 16.9 million shares of common stock
("Common Stock") issued and outstanding and 219,424 shares of preferred stock
outstanding.

Stock Warrants and Options

     At December 31, 1998, the Company had warrants outstanding which entitle
the holders thereof to purchase an aggregate one million shares of Common Stock.
Per share exercise prices and expiration dates for the warrants are as follows:
750,000 shares at $6.00 expiring in 1999, 100,000 shares at $7.50 expiring in
2000 and 150,000 shares at $25.00 expiring in 2002.

     The Company has various stock option plans for its employees and directors
(See Note 12).

Series D Cumulative Convertible Preferred Stock

     In November 1997, the Company issued 46,600 shares of Series D Cumulative
Convertible Preferred Stock (the "Series D Preferred Stock") in connection with
the acquisition of the Arroyo Grande Field (See Note 8). The Series D Preferred
Stock has an aggregate stated value of $23.3 million and is redeemable at the
Company's 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 of
stated value for each share of Common Stock to be issued. Commencing January 1,
2000, the Series D Preferred Stock will bear an annual dividend of $30 per
share. Prior to such date, no dividends will accrue. 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. This discount will be amortized to retained
earnings during the two year period dividends do not accrue.

                                      F-13
<PAGE>
 
Redeemable Preferred Stock

     On July 29, 1998, the Company sold in a private placement 170,000 shares of
its Series E Preferred Stock for $85 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 the Company's 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 the Company's
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 the option of the Company after March 31, 1999, at 110%
of stated value and at declining amounts 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
the Company's capital contribution to PAAI to acquire all of the outstanding
capital stock of the Celeron Companies (See Note 9).

     On October 1, 1998, the Company paid a dividend on the Series E Preferred
Stock for the period from July 29, 1998 through September 30, 1998. The dividend
amount of approximately $1.4 million was paid by issuing 2,824 additional shares
of the Series E Preferred Stock. After payment of such dividend, there were
172,824 shares of the Series E Preferred Stock outstanding with a liquidation
value, including accrued dividends through December 31, 1998, of approximately
$88.5 million.

NOTE 6 - EARNINGS PER SHARE
---------------------------

     In February 1997, the FASB issued Statement of Financial Accounting
Standards No. 128 ("SFAS 128"), Earnings Per Share ("EPS"). Basic EPS excludes
dilutive securities and is computed by dividing income available to common
stockholders by the weighted-average number of common shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if dilutive
securities were converted into common stock and is computed similarly to fully
diluted EPS pursuant to previous accounting pronouncements.

     The following is a reconciliation of the numerators and the denominators of
the basic and diluted EPS computations for income from continuing operations for
the years ended December 1998, 1997 and 1996, as required by SFAS 128. All prior
period EPS data has been restated in accordance with the provisions of SFAS 128.

<TABLE> 
<CAPTION> 
                                                           For the Year Ended December 31,
                     -------------------------------------------------------------------------------------------------------
                                     1998                              1997                              1996
                     ---------------------------------- ---------------------------------- ---------------------------------
                       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
                     ------------ ----------- --------- ------------ ---------- ---------- -----------  ---------- ---------
                                                                  (in thousands)

<S>                   <C>                                 <C>                                <C> 
Income before
  extraordinary item  $ (63,316)                          $ 14,259                           $ 21,652
Less:  preferred
  stock dividends             -                               (163)                                 -
                     ------------                       ------------                       -----------
Income available
  to common
  stockholders          (63,316)     16,816    $ (3.77)     14,096     16,603     $ 0.85       21,652     16,384     $ 1.32
                                              =========                         ==========                         =========

Effect of dilutive
  securities:
Employee stock
  options                     -           -                      -      1,085                       -        839
Warrants                      -           -                      -        516                       -        421
                     ------------ -----------           ------------ ----------            -----------  ----------

Income available
  to common
  stockholders
  assuming
  dilution            $ (63,316)     16,816    $ (3.77)   $ 14,096     18,204     $ 0.77     $ 21,652     17,644     $ 1.23
                     ============ =========== ========= ============ ========== ========== ===========  ========== =========
</TABLE> 

     Certain options and warrants to purchase shares of Common Stock were not
included in the computations of diluted EPS because the exercise prices were
greater than the average market price of the Common Stock during the periods of
the EPS calculations, resulting in antidilution. In addition, the Series E
Preferred Stock, which was issued during 1998, and the Company's

                                      F-14
<PAGE>
 
Series D Preferred Stock, which was issued during 1997, is convertible into
Common Stock but was not included in the computation of diluted EPS because the
effect was antidilutive. See Notes 5 and 12 for additional information
concerning outstanding options and warrants.

NOTE 7 - INCOME TAXES
---------------------

     The Company's deferred income tax assets (liabilities) at December 31, 1998
and 1997, 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
the Company's upstream oil and gas operations and its midstream activities as
follows:

                                                               December
                                                      -------------------------
                                                          1998         1997
                                                      ------------  -----------
U.S. Federal
  Deferred tax assets:
    Net operating losses                                $ 48,911      $ 60,055
    Percentage depletion                                   2,450         2,450
    Tax credit carryforwards                               1,614         1,010
    Other                                                  1,354           335
                                                      ------------  -----------
                                                          54,329        63,850
  Deferred tax liabilities:
    Oil and gas acquisition, exploration
      and development costs                                    -       (53,873)
    Marketing and pipeline depreciation
      and related adjustments                             (3,758)       (2,243)
                                                      ------------  -----------
    Net deferred tax asset                                50,571         7,734
    Valuation allowance                                   (2,786)       (6,938)
                                                      ------------  -----------
                                                        $ 47,785      $    796
                                                      ============  ===========

States
  Deferred tax liability                                $ (3,714)     $   (958)
                                                      ============  ===========

     At December 31, 1998, the Company has a net deferred tax asset of
$47.8 million.  Management believes that it is more likely than not that it will
generate taxable income sufficient to realize such asset based on certain tax
planning strategies available to the Company. As an example, the Company,
through its existing ownership in PAA which is publicly traded, could generate
sufficient taxable income to utilize the tax asset existing at December 31,
1998. Therefore, the Company has concluded that the valuation allowance is
adequate. In the fourth quarter of 1998, as a result of  the formation of PAA,
significant taxable income was generated allowing the Company to utilize certain
net operating losses ("NOLs") generated in past years. The use of such NOLs has
permitted the Company to revise the valuation allowance previously associated
with a portion of those NOLs. The benefit of NOL carryforwards recognized during
the current year totaled approximately $5.0 million.

     In the first quarter of 1996, the Company reduced its valuation allowance
resulting in the recognition of an $11 million credit to deferred income tax
expense. The remaining deferred tax asset was not recognized primarily due to
limitations imposed by the IRS regarding the utilization of NOLs generated prior
to certain of the Company's subsidiaries being acquired and the uncertainty of
utilizing the Company's investment tax credit ("ITC") carryforwards.

     At December 31, 1998, the Company had carryforwards of approximately $139.7
million of regular tax NOLs, $7.0 million of statutory depletion, $.3 million of
ITC and $1.3 million of alternative minimum tax ("AMT") credit. Utilization of
a portion of the ITC carryforwards is limited to certain companies within the
consolidated group. At December 31, 1998, the Company had approximately $128.3
million of AMT NOL carryforwards available as a deduction against future AMT
income. The NOL carryforwards expire from 2003 through 2011.

                                      F-15
<PAGE>
 
     Set forth below is a reconciliation between the income tax provision
computed at the United States statutory rate on income before income taxes and
the income tax provision per the accompanying Consolidated Statements of
Operations:

<TABLE> 
<CAPTION> 
                                                                            Year Ended December 31,
                                                                  -----------------------------------------
                                                                     1998           1997           1996    
                                                                  ------------   ------------   -----------
                                                                                (in thousands)
           <S>                                                     <C>            <C>            <C>  
           U.S. federal income tax provision at statutory rate     $  (35,446)    $    7,905     $   6,214 
           State income taxes                                          (5,094)           376           888 
           Valuation allowance adjustment                              (4,987)             -       (11,000)
           Full cost ceiling test limitation                            2,903              -             - 
           Other                                                          (96)            46             - 
                                                                  ------------   ------------   -----------
           Income taxes on income before extraordinary item           (42,720)         8,327        (3,898)
           Income tax benefit allocated to extraordinary item               -              -        (3,403)
                                                                  ------------   ------------   -----------
           Income tax (benefit) provision                          $  (42,720)    $    8,327     $  (7,301)
                                                                  ============   ============   =========== 
</TABLE> 

     In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of the beneficial ownership of the Company within a
three-year period (an "Ownership Change") will place an annual limitation on the
Company's ability to utilize its existing tax carryforwards. Under the Final
Treasury Regulations issued by the Internal Revenue Service, the Company does
not believe that an Ownership Change has occurred as of December 31, 1998.

NOTE 8 - UPSTREAM ACQUISITIONS AND DISPOSITIONS
-----------------------------------------------

     During 1998, the Company 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 1,200 barrels of oil per day of 15-17 degree API gravity crude and
added approximately 8 million barrels of oil equivalent to the Company's proved
reserves.

     In March 1997, the Company completed the acquisition of Chevron USA's
("Chevron") interest in the Montebello Field for $25 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 the
Company's existing California operations, was producing approximately 800
barrels of oil and 800 Mcf of gas per day and added approximately 23 million
barrels of oil equivalent to the Company's proved reserves. The acquisition was
funded with proceeds from the Revolving Credit Facility.

     In November 1997, the Company 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 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 oil
per day from 70 wells and added approximately 20 million barrels of oil
equivalent to the Company's proved reserves.

     The aggregate purchase price of $22.1 million 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 per share. No
proved reserves had been assigned to the rights to the property interest
conveyed.

     During 1997 and 1996, the Company sold certain non-strategic oil and
natural gas properties located primarily in Louisiana and Utah for net proceeds
of approximately $2.7 million and $3.1 million, respectively.

NOTE 9 - MIDSTREAM ACQUISITION
------------------------------

     On July 30, 1998, PAAI, a wholly owned unrestricted subsidiary of the
Company, as defined in the Indentures for the 10.25% Senior Subordinated Notes,
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 Ventures Seven,
Inc., a wholly-owned subsidiary of The Goodyear Tire & Rubber Company
("Goodyear") for approximately $400 million, including transaction costs. The
principal assets of the entities acquired include the All American Pipeline
System,

                                      F-16
<PAGE>
 
a 1,233-mile crude oil pipeline extending from California to Texas, and a
45-mile crude oil gathering system in the San Joaquin Valley of California, as
well as other assets related to such operations.

     Financing for the acquisition was provided through (i) PAAI's $325 million,
limited recourse bank facility with ING (U.S.) Capital Corporation, BankBoston,
N.A. and other lenders (the "PAAI Credit Facility") (See Note 4) and (ii) an
approximate $114 million capital contribution to PAAI by the Company.
Approximately $29 million of such capital contribution was funded by cash flow
and the Revolving Credit Facility and the remaining $85 million was provided by
the issuance of the Series E Preferred Stock (See Note 5).

     The assets, liabilities and results of operations of the Celeron Companies
are included in the Consolidated Financial Statements of the Company effective
July 30,1998. The following unaudited pro forma information is presented to show
pro forma revenues, net loss and net loss per share as if the acquisition
occurred on January 1, 1997.

                                          Year Ended December 31,          
                                     ----------------------------------
                                          1998               1997      
                                     ---------------     --------------
                                               (in thousands,          
                                          except per share data)       
                                                                       
           Revenues                     $ 1,731,746        $ 1,854,562 
                                     ===============     ==============
                                                                       
           Net loss                       $ (51,110)          $ (6,067)
                                     ===============     ==============
           Net loss per share:                                         
           Basic                            $ (3.60)           $ (0.86)
                                     ===============     ==============
           Diluted                          $ (3.60)           $ (0.86)
                                     ===============     ============== 

     The pro forma net loss for the year ended December 31, 1997, includes a
non-cash impairment charge of $64.2 million related to the writedown of pipeline
assets and linefill by Wingfoot in connection with the sale of Wingfoot by
Goodyear to the Company. Based on the Company's purchase price allocation to
property and equipment and pipeline linefill, an impairment charge would not
have been required had the Company actually acquired Wingfoot effective
January 1, 1997. Excluding this impairment charge, the Company's pro forma net
income for 1997 would have been $33.1 million, or $1.36 per share.

     The acquisition was accounted for utilizing the purchase method of
accounting and the purchase price was allocated in accordance with Accounting
Principles Board Opinion No. 16 as follows (in thousands):

     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 
                                                                   ============ 

NOTE 10 - RELATED PARTY TRANSACTIONS
-------------------------------------

     In conjunction with the IPO, the Company entered into various agreements
with PAA, including (i) the Omnibus Agreement, providing for the resolution of
certain conflicts arising from the conduct of PAA and the Company of related
businesses and for the General Partner's indemnification of PAA for certain
matters and (ii) the Crude Oil Marketing Agreement which provides for the
marketing by PAA of the Company's crude oil production.

     PAA does not directly employ any persons to manage or operate its business.
These functions are provided by employees of the General Partner and the
Company. The General Partner does not receive a management fee or other

                                      F-17
<PAGE>
 
compensation in connection with its management of PAA. PAA reimburses the
General Partner and the Company for all direct and indirect costs of services
provided, including the costs of employee, officer and director compensation and
benefits properly allocable to PAA, and all other expenses necessary or
appropriate to conduct the business of, and allocable to PAA. The PAA
Partnership Agreement provides that the General Partner will determine the
expenses that are allocable to PAA in any reasonable manner determined by the
General Partner in its sole discretion. Total costs reimbursed to the General
Partner and the Company by PAA were approximately $.5 million for 1998. Such
costs include, (i) allocated personnel costs (such as salaries and employee
benefits) of the personnel providing such services, (ii) rent on office space
allocated to the General Partner in the Company's offices in Houston, Texas and
(iii) out-of-pocket expenses related to the providing of such services.

     PAAI adopted its 1998 Long-Term Incentive Plan (the "Long-Term Incentive
Plan") for employees and directors of PAAI and its affiliates who perform
services for PAA. The Long-Term Incentive Plan consists of two components, a
restricted unit plan (the "Restricted Unit Plan") and a unit option plan (the
"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 PAAI'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.
Approximately 500,000 Restricted Units were granted upon consummation of the IPO
to employees of PAAI. In general, Restricted Units granted to employees during
the Subordination Period (as defined in the PAA Partnership Agreement) will vest
only upon, and in the same proportion as, the conversion of Subordinated Units
to Common Units. PAAI will be entitled to reimbursement by PAA for the cost
incurred in acquiring such Common Units.

     Unit Option Plan. The Unit Option Plan currently permits the grant of
options ("Unit Options") covering Common Units. No grants will initially be
made under the Unit Option Plan. The Compensation Committee may, in the future,
determine to make grants under such plan to employees and directors containing
such terms as the Committee shall determine.

     In addition to the grants made under the Restricted Unit Plan described
above, PAAI agreed to transfer approximately 325,000 of its affiliates' Common
Units to certain key employees of the General Partner (the "Transaction
Grants"). Generally, approximately 72,000 of such Common Units will 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 ("MQD") 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 has been paid. In addition, approximately
36,000 of such Common Units will 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 MQD on all outstanding Common Units and Subordinated
Units and the related distribution on the general partner interest. Any Common
Units remaining unvested shall vest upon, and in the same proportion as, the
conversion of Subordinated Units.

     The Company will recognize compensation expense in the future for the
Restricted Units, Unit Options and Transaction Grants described above, when
vesting becomes probable.

NOTE 11 - RETIREMENT PLAN
-------------------------

     Effective June 1, 1996, the Company's Board of Directors adopted a
nonqualified retirement plan (the "Plan") for certain officers of the Company.
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, 1998 and 1997, is
comprised of the following components:

                                                              Year Ended
                                                              December 31,
                                                      -------------------------
                                                         1998          1997
                                                      -----------   -----------
                                                            (in thousands)

Service cost - benefits earned during the period            $ 97          $ 82
Interest on projected benefit obligation                      74            60
Amortization of prior service cost                            37            37
Unrecognized loss                                              3             -
                                                      -----------   -----------
Net pension expense                                        $ 211         $ 179
                                                      ===========   ===========

                                      F-18
<PAGE>
 
     The following schedule reconciles the status of the Plan with amounts
reported in the Company's balance sheet at December 31, 1998 and 1997.

<TABLE> 
<CAPTION> 
                                                                            December 31,
                                                                       -----------------------
                                                                          1998         1997
                                                                       ----------   ----------
                                                                           (in thousands)
<S>                                                                     <C>         <C> 
Actuarial present value of benefit obligations:
  Vested benefits                                                        $ 1,108      $   857
  Nonvested benefits                                                         172          184
                                                                       ----------   ----------
  Accumulated benefit obligation                                           1,280        1,041
                                                                       ==========   ==========
  Projected benefit obligation for service rendered to date              $ 1,280      $ 1,041
  Plan assets at fair value                                                    -            -
                                                                       ----------   ----------
  Projected benefit obligation for service rendered to date                1,280        1,041
  Unrecognized loss                                                         (211)        (145)
  Prior service cost not yet recognized in net periodic pension expense     (582)        (619)
                                                                       ----------   ----------
  Net pension liability                                                      487          277
  Adjustment required to recognize minimum liability                         582          619
                                                                       ----------   ----------
  Accrued pension cost liability recognized in the balance sheet         $ 1,069      $   896
                                                                       ==========   ==========
</TABLE> 

     The weighted-average discount rate used in determining the projected
benefit obligation was 6.5% and 7% for the years ended December 31, 1998 and
1997, respectively.

NOTE 12 - STOCK COMPENSATION PLANS
----------------------------------

     Historically, the Company has used stock options as a long-term incentive
for its 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 Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees ("APB 25"), no compensation expense has
been recognized in the accompanying financial statements.

     During 1996, the Company's shareholders approved the Company's 1996 Stock
Incentive Plan, under which a maximum of 1.5 million shares of Common Stock were
reserved for issuance. The Company also has options outstanding under its 1991
and 1992 plans, under which a maximum of 2.0 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 the Company's 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.

     In addition, during 1996, the Company granted performance options to
purchase a total of 500,000 shares of Common Stock 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 of five years. The performance
options vest when the price of the Common Stock trades at or above $24 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.

     A summary of the status of the Company's stock options as of December 31,
1998, 1997, and 1996, and changes during the years ending on those dates are
presented below:

<TABLE> 
<CAPTION> 
                                             1998                 1997                 1996
                                     -------------------- --------------------  --------------------
                                                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       2,614    $  9.50     2,435    $  8.56      1,728    $  6.40
 Granted                                  333    $ 16.62       384    $ 14.33      1,060    $ 11.34
 Exercised                               (179)   $  6.71      (163)   $  6.80       (285)   $  6.26
 Forfeited                                (19)   $ 11.36       (42)   $  9.82        (68)   $  6.63
                                     ---------            ---------             ---------
 Outstanding at end of year             2,749    $ 10.53     2,614    $  9.50      2,435    $  8.56
                                     =========            =========             =========
 Options exercisable at year-end        1,646    $  8.53     1,494    $  7.24      1,289    $  6.78
                                     =========            =========             =========
 Weighted-average fair value of
   options granted during the year    $  4.93              $  4.53               $  3.19
</TABLE> 

                                      F-19
<PAGE>
 
     In October 1995, the Financial Accounting Standards Board issued SFAS
No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 establishes
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 No. 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. The
Company has elected to follow APB 25 and related Interpretations in accounting
for its employee stock options because, as discussed below, the alternative fair
value accounting provided for under SFAS No. 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 the Company's 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. The Company will recognize compensation expense under APB 25 in the
future for the two performance options described above, if certain conditions
are met and such options vest.

     Pro forma information regarding net income and EPS is required by SFAS
No. 123 and has been determined as if the Company had accounted for its 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
1998, 1997 and 1996: risk-free interest rates of 5.6% for 1998, 6.1% for 1997
and 6.0% for 1996; a volatility factor of the expected market price of the
Company's common stock of .38 for 1998, .42 for 1997 and .36 for 1995; no
expected dividends; and weighted-average expected option lives of 2.7 years in
1998, 2.6 years in 1997 and 2.7 years in 1996.

     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 the Company's 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. Set forth below
is a summary of the Company's net income and EPS as reported and pro forma as if
the fair value based method of accounting defined in SFAS No. 123 had been
applied. The pro forma information is not meant to be representative of the
effects on reported net income 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.

<TABLE> 
<CAPTION> 
                                                              Year Ended December 31,
                                  -------------------------------------------------------------------------------
                                            1998                       1997                       1996
                                  -------------------------  -------------------------  -------------------------
                                      As           Pro           As           Pro           As           Pro
                                   Reported       Forma       Reported       Forma       Reported       Forma
                                  ------------ ------------  ------------ ------------  ------------ ------------
 <S>                                 <C>          <C>           <C>          <C>           <C>          <C> 
 Net income/(loss) (in thousands)    $(58,554)    $(59,262)     $ 14,259     $ 13,665      $ 16,548     $ 16,161
 Basic EPS                           $ (3.77)     $ (3.81)      $ 0.85       $ 0.81        $ 1.01       $ 0.99
 Diluted EPS                         $ (3.77)     $ (3.81)      $ 0.77       $ 0.74        $ 0.94       $ 0.92
</TABLE> 

     The following table summarizes information about stock options outstanding
at December 31, 1998:

<TABLE> 
<CAPTION> 
                                        Weighted
                                        Average       Weighted                   Weighted
                            Number      Remaining     Average       Number       Average
       Range of          Outstanding  Contractual    Exercise    Exercisable    Exercise
    Exercise Price       at 12/31/98      Life         Price      at 12/31/98     Price
-----------------------  ------------  ------------- ------------ ------------- ------------
                                  (share amounts in thousands)
    <S>                     <C>          <C>           <C>            <C>         <C>   
    $ 5.25 to   $ 6.75         917        3.8 years     $  6.14          899       $  6.13
    $ 7.50 to   $ 7.81         445        4.3 years     $  7.65          369       $  7.63
    $10.50 to  $ 15.63       1,282        3.1 years     $ 13.96          273       $ 13.53
    $19.19 to  $ 19.19         105        4.4 years     $ 19.19          105       $ 19.19
                          ---------                                 ---------
    $ 5.25 to  $ 19.19       2,749        3.6 years     $ 10.53        1,646       $  8.53
                          =========                                 =========
</TABLE> 

     During 1998, 1997 and 1996, pursuant to Board of Directors' resolutions,
the Company contributed approximately 28,000, 21,000 and 18,000 shares,
respectively, of Common Stock at weighted average prices of $16.21, $15.22 and
$11.35 per share, respectively, on behalf of participants in the Company's
401(k) Savings Plan, representing a matching contribution by the Company for 50%
of an employee's contribution.

                                      F-20
<PAGE>
 
NOTE 13 - COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION
---------------------------------------------------------------

Commitments and Contingencies

     Minimum commitments in connection with office space and office equipment
leased by the Company are: 1999 - $1.8 million; 2000 and 2001 - $1.7 million
annually; 2002 and 2003 - $1.6 million annually; thereafter - $4.1 million.
Rental payments made under the terms of similar arrangements totaled
approximately $1.3 million in 1998 and $1.1 million in 1997 and in 1996.

     In connection with its crude oil marketing, PAA provides certain purchasers
and transporters with irrevocable standby letters of credit to secure PAA's
obligation for the purchase of crude oil (See Note 4). Generally, these letters
of credit are issued for up to seventy day periods and are terminated upon
completion of each transaction. At December 31, 1998, PAA had outstanding
letters of credit of approximately $62 million. Such letters of credit are
secured by the crude oil inventory and accounts receivable of PAA (See Note 4).

     The Company incurred costs associated with leased land, rights-of-way,
permits and regulatory fees of $.3 million during  1998. At December 31, 1998,
minimum future payments, net of sublease income, associated with these contracts
are approximately $.3 million for the following year. Generally these contracts
extend beyond one year but can be canceled at any time should they not be
required for operations.

     In order to receive electrical power service at certain remote locations,
the Company has entered into facilities contracts with several utility
companies. These facilities charges are calculated periodically based upon,
among other factors, actual electricity energy used. Minimum future payments for
these contracts at December 31, 1998, are approximately $760,000 annually for
each of the next five years.

     Under the amended terms of an asset purchase agreement between the Company
and Chevron, commencing with the year beginning January 1, 2000, and each year
thereafter, the Company is required to plug and abandon 20% of the then
remaining inactive wells, which currently aggregate approximately 225. To the
extent the Company elects not to plug and abandon the number of required wells,
the Company is 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, the Company is
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 the Company does not
expend the required amounts during a calendar year, the Company is required to
contribute an amount equal to 125% of the actual shortfall to an escrow account.
The Company may withdraw amounts from such escrow account to the extent it
expends excess amounts in a future year. As of December 31, 1998, the Company
has not been required to make contributions to an escrow account.

     Although the Company obtained environmental studies on its properties in
California, the Sunniland Trend and the Illinois Basin and the Company believes
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 its California
Properties, the Company 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. While the Company
believes that it does not have any material obligations for operations conducted
prior to the Company's acquisition of the properties from Chevron, other than
its 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 it 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 the
Company's 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. The Company has estimated that the costs to perform these tasks is
approximately $12.8 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 ("DD&A").
Results from operations for 1998, 1997 and 1996 include $0.8 million, $0.6
million and $0.8 million, respectively, of expense associated with these
estimated future costs. For valuation and realization purposes of the affected
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 18.

                                      F-21
<PAGE>
 
     As is common within the industry, the Company has entered into various
commitments and operating agreements related to the exploration and development
of and production from certain 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 the Company's financial position, results of operations or cash flows.

     In March 1999, PAA signed a definitive agreement to acquire Scurlock
Permian LLC and certain other pipeline assets (See Note 21).

Industry Concentration

     Financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of trade receivables. The
Company's accounts receivable are primarily from purchasers of oil and natural
gas products. This industry concentration has the potential to impact the
Company's 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. The Company generally requires letters of credit for
receivables from customers which are not considered investment grade, unless the
credit risk can otherwise be mitigated.

     There are a limited number of alternative methods of transportation for the
Company's production. Substantially all of the Company's California crude oil
and natural gas production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could result in the
Company having to find transportation alternatives, increased transportation
costs to the Company or involuntary curtailment of a significant portion of its
crude oil and natural gas production which could have a negative impact on
future results of operations or cash flows.

NOTE 14 - LITIGATION
--------------------

     During 1996, the Company settled two lawsuits filed in 1992 and 1993,
relating to activities in 1991 and 1992, against certain of its officers and
directors for a cash payment of approximately $6.3 million. Approximately $4.1
million of such amount was paid by the Company's insurance carrier and $2.2
million was paid by the Company. Taking into account prior costs incurred by the
Company to defend these suits, and for which the Company agreed to relinquish
its claims for reimbursement against its insurance company, this settlement
resulted in a charge to 1996 first quarter earnings of $4 million.

     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"), a wholly owned subsidiary
of the Company, 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 the Company's oil and
natural gas leases but denied such motion as to the counterclaim alleging
conversion of funds. The Company has reached an agreement in principle with all
parties to settle this case. In consideration for full and final settlement, and
dismissal with prejudice of all issues in this case, the Company has agreed to
pay to the defendants the total sum of $100,000, and release certain royalty
amounts held in suspense and in the court registry during the pendency of this
case. Finalization of this settlement has been delayed due to disputes over
certain title issues. Motions have been filed requesting the Court to rule on
the disputes, but no hearing date has been set. The Company does not believe
that the disputes will adversely affect the settlement reached between the
Company and the defendants.

     The Company, in the ordinary course of business, is a claimant and/or a
defendant in various other legal proceedings in which its exposure, individually
and in the aggregate, is not considered material to the consolidated financial
statements.

                                      F-22
<PAGE>
 
NOTE 15 - MAJOR CUSTOMERS
-------------------------

     Sales to Sempra Energy Trading Corporation ("Sempra") (formerly AIG
Trading Corporation) and Koch Oil Company ("Koch") accounted for 27% and 15%,
respectively, of the Company's total revenue (exclusive of interest and other
income) during 1998. Customers accounting for more than 10% of total revenue
for 1997 and 1996 were as follows: 1997 -- Koch -27% and Sempra - 11%, 1996 --
Koch-16% and Basis Petroleum, Inc. (formerly Phibro Energy USA, Inc.) - 11%. No
other single customer accounted for as much as 10% of total sales during 1998,
1997 or 1996. Additionally during 1998, Tosco Refining Company and Scurlock
Permian LLC accounted for approximately 50% and 17%, respectively, of the
Company's oil and gas sales.

NOTE 16 - FINANCIAL INSTRUMENTS
-------------------------------

Derivatives

     The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119, Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments and does not use them for
speculative trading purposes. The Company's principle objective is to hedge
exposure to price volatility on crude oil and natural gas. These arrangements
expose the Company to credit risk (as to counterparties) and to risk of adverse
price movements in certain cases where the Company's production is less than
expected. Substantially all derivatives are either exchange traded or with major
financial institutions and the risk of loss is considered remote.

     The Company has entered into various arrangements to fix the NYMEX crude
oil spot price ("NYMEX Crude Oil Price") for a significant portion of its crude
oil production. On December 31, 1998, these arrangements provided for a NYMEX
Crude Oil Price for 9,000 barrels per day from January 1, 1999, through
December 31, 1999, at approximately $18.25 per barrel. Since December 31, 1998,
the Company has entered into additional arrangements which provide for a NYMEX
Crude Oil Price for 2,000 barrels per day from January 1, 2000, through
December 31, 2000, at $15.30 per barrel. Location and quality differentials
attributable to the Company's properties are not included in the foregoing
prices. The agreements provide for monthly settlement based on the differential
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 oil
and natural gas sales.

     In addition, the Company has entered into ten year swap agreements with
various financial institutions to hedge the interest rate on an aggregate of
$200 million of bank debt.  Approximately $175 million of such debt relates to
the Term Loan Facility of PAA and fixes the LIBOR portion of the interest rate
on such loan at approximately 5.24%. The remaining $25 million swap locks in
LIBOR at approximately 5.9%.

Fair Value of Financial Instruments

     The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of SFAS No. 107,
Disclosures About Fair Value of Financial Instruments. The estimated fair value
amounts have been determined by the Company 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.

                                      F-23
<PAGE>
 
     The carrying amounts and fair values of the Company's other financial
instruments are as follows:

<TABLE> 
<CAPTION> 
                                                                            December 31,
                                                     ----------------------------------------------------------
                                                                 1998                          1997
                                                     ----------------------------  ----------------------------
                                                       Carrying         Fair         Carrying         Fair
                                                        Amount         Value          Amount         Value
                                                     -------------  -------------  -------------  -------------
                                                                           (in thousands)
<S>                                                    <C>            <C>            <C>             <C> 
Long Term Debt:
  Bank debt                                            $ 227,000      $ 227,000       $ 80,000       $ 80,000
  Subordinated debt                                      202,427        202,000        202,661        214,750
  Other long-term debt                                     2,556          2,556          3,067          3,067
  Redeemable Preferred Stock                              88,487         88,487              -              -
Off Balance Sheet Financial Information:
  Unrealized gain on crude oil swap agreements (1)             -         16,870              -          7,246
  Unrealized loss on interest rate swap agreements             -         (3,253)             -              -
</TABLE> 

--------------------

  (1) These amounts represent the calculated difference between the NYMEX Crude
      Oil Price and the hedge arrangements for future production of the
      Company's properties as of December 31, 1998 and 1997. Such hedges, and
      therefore the unrealized gains, have been included in estimated future
      gross revenues to arrive at the estimated future net revenues and the
      Standardized Measure disclosed in Note 18.

     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 the Company's incremental borrowing rate. The fair value of the
Redeemable Preferred Stock is estimated to be its liquidation value at
December 31, 1998. The fair value of the interest rate swap is based on the
termination value at December 31, 1998.

NOTE 17 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
-----------------------------------------------------------

     Selected cash payments and noncash activities were as follows:

<TABLE> 
<CAPTION> 
                                                                       Year Ended December 31,
                                                              ---------------------------------------
                                                                1998           1997          1996
                                                              ----------    -----------   -----------
                                                                          (in thousands)
<S>                                                           <C>           <C>           <C> 
Cash paid for interest (net of amount capitalized)             $ 34,546      $ 20,486       $ 16,309
                                                              ==========    ===========   ===========

Noncash investing and financing activities:
  Series D Preferred Stock Dividends                           $  1,275      $    163       $      -
                                                              ==========    ===========   ===========
  Series E Preferred Stock Dividends                           $  3,487      $      -       $      -
                                                              ==========    ===========   ===========
  Tax benefit from exercise of employee stock options          $    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> 

                                      F-24
<PAGE>
 
NOTE 18 - OIL AND NATURAL GAS ACTIVITIES
-----------------------------------------

Costs Incurred

     The Company's oil and natural gas acquisition, exploration, exploitation
and development activities are conducted in the United States. The following
table summarizes the costs incurred in connection therewith during the last
three years.

<TABLE> 
<CAPTION> 
                                                    Year Ended December 31,
                                            ---------------------------------------
                                                1998          1997         1996
                                            ------------  ------------  -----------
                                                         (in thousands)
<S>                                           <C>           <C>           <C> 
 Property acquisitions costs:
     Unproved properties                      $   6,266     $  15,249     $    728
     Proved properties                            3,851        28,182        3,087
 Exploration costs                                1,657         1,730        2,433
 Exploitation and development costs              89,161        82,217       45,007
                                            ------------  ------------  -----------
                                              $ 100,935     $ 127,378     $ 51,255
                                            ============  ============  ===========
</TABLE> 

Capitalized Costs

     The following table presents the aggregate capitalized costs subject to
amortization relating to the Company's oil and natural gas acquisition,
exploration, exploitation and development activities, and the aggregate related
DD&A. Under full cost accounting rules as prescribed by the SEC, unamortized
costs of proved 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 the Company's proved oil and natural
gas properties exceeded the Standardized Measure and the Company recorded a non-
cash, after tax charge to expense of $109.0 million ($173.9 million pre-tax).

                                            Year Ended December 31,    
                                          -----------------------------
                                              1998           1997      
                                          -------------  --------------
                                                 (in thousands)               
                                                                       
           Proved properties                 $ 596,203       $ 498,038 
           Accumulated DD&A                   (369,260)       (171,162)
                                          -------------  --------------
                                             $ 226,943       $ 326,876 
                                          =============  ============== 

     The DD&A rate per equivalent unit of production excluding the writedown in
1998 was $3.00, $2.83 and $3.00 for the years ended December 31, 1998, 1997 and
1996, respectively.

Costs Not Subject to Amortization

     The following table summarizes the categories of costs which comprise the
amount of unproved properties not subject to amortization.

                                                   December 31,        
                                          -----------------------------
                                              1998           1997      
                                          -------------  --------------
                                                 (in thousands)        
                                                                       
           Acquisition costs                  $ 47,657        $ 41,652 
           Exploration costs                     2,467           2,573 
           Capitalized interest                  4,421           7,799 
                                          -------------  --------------
                                              $ 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. The
Company 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 20%, 35% and 5% of the balance in
unproved properties at December 31, 1998, related to additions made in 1998,
1997 and 1996, respectively.

     During 1998, 1997 and 1996, the Company capitalized $3.7 million, $3.3
million and $3.6 million, respectively, of interest related to the costs of
unproved properties in the process of development.

                                      F-25
<PAGE>
 
Supplemental Reserve Information (Unaudited)

     The following information summarizes the Company's net proved reserves of
oil (including condensate and natural gas liquids) and natural gas and the
present values thereof for the three years ended December 31, 1998. The
following reserve information is based upon reports of the independent petroleum
consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc.,
Ryder Scott Company and System Technology Associates, Inc. The estimates are in
accordance with regulations prescribed by the Securities and Exchange Commission
("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 the control of the Company. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of 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
oil and natural gas that are ultimately recovered, production and operating
costs, the amount and timing of future development expenditures and future 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 oil and
natural gas reserves attributable to the Company's 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 oil and natural gas have had, and could have in
the future, an adverse effect on the carrying value of the Company's proved
reserves and the Company's revenues, profitability and cash flow. Almost all of
the Company's reserve base (approximately 90% of year-end 1998 reserve volumes)
is comprised of long-life oil properties that are sensitive to crude oil price
volatility. The crude oil price at December 31, 1998, upon which proved reserve
volumes, the estimated present value (discounted at 10%) of future net revenue
from the Company's proved oil and natural gas reserves (the "Present Value of
Proved Reserves") and the Standardized Measure as of such date were based, was
$12.05 per barrel. Such price was the lowest year-end price since oil was
deregulated in 1980 and was approximately 34% below the price used in preparing
reserve estimates at the end of 1997.

Estimated Quantities of Oil and Natural Gas Reserves (Unaudited)

     The following table sets forth certain data pertaining to the Company's
proved and proved developed reserves for the three years ended December 31,
1998.

<TABLE> 
<CAPTION> 
                                                            As of or for the Year Ended December 31,
                                         -----------------------------------------------------------------------------
                                                    1998                      1997                       1996
                                         ------------------------- -------------------------  ------------------------
                                             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                          151,627       60,350      115,996       37,273       94,408       43,110
  Revision of previous estimates             (46,282)       2,925      (16,091)       3,805       19,424        6,641
  Extensions, discoveries, improved
    recovery and other additions              14,729       29,306       17,884        8,126        8,179        1,294
  Sale of reserves in-place                        -       (2,799)         (26)        (547)          (5)     (12,491)
  Purchase of reserves in-place                7,709            -       40,764       14,566           45          862
  Production                                  (7,575)      (3,001)      (6,900)      (2,873)      (6,055)      (2,143)
                                         ------------ ------------ ------------  -----------  -----------  -----------
  Ending balance                             120,208       86,781      151,627       60,350      115,996       37,273
                                         ============ ============ ============  ===========  ===========  ===========

Proved Developed Reserves
  Beginning balance                           99,193       38,233       86,515       25,629       67,266       29,397
                                         ============ ============ ============  ===========  ===========  ===========
  Ending balance                              73,264       58,445       99,193       38,233       86,515       25,629
                                         ============ ============ ============  ===========  ===========  ===========
</TABLE> 

                                      F-26
<PAGE>
 
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

     The Standardized Measure of discounted future net cash flows relating to
proved oil and natural gas reserves is presented below:

<TABLE> 
<CAPTION> 
                                                            December 31,
                                           ----------------------------------------------
                                               1998             1997            1996
                                           -------------    -------------   -------------
                                                           (in thousands)
<S>                                         <C>              <C>             <C> 
Future cash inflows                         $ 1,102,863      $ 2,237,876     $ 2,681,007
Future development costs                       (117,924)        (157,877)       (111,785)
Future production expense                      (546,091)      (1,019,254)       (977,551)
Future income tax expense                             -         (261,130)       (437,654)
                                           -------------    -------------   -------------
Future net cash flows                           438,848          799,615       1,154,017
Discounted at 10% per year                     (211,905)        (387,792)       (575,436)
                                           -------------    -------------   -------------
Standardized measure of
  discounted future net cash flows          $   226,943      $   411,823     $   578,581
                                           =============    =============   =============
</TABLE> 

     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 the Company's proved properties and the present value
        thereof are made using 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 received by the Company at December 31,
        1998, is based on the NYMEX Crude Oil Price of $12.05 per barrel with
        variations therefrom based on location and grade of crude oil. The
        Company has entered into various fixed price and floating price collar
        arrangements to fix or limit the NYMEX Crude Oil Price for a significant
        portion of its crude oil production. Arrangements in effect at
        December 31, 1998, are reflected in the reserve reports through the term
        of the arrangements (See Note 16). The overall average prices used in
        the reserve reports as of December 31, 1998, were $7.96 per barrel of
        crude oil, condensate and natural gas liquids and $1.68 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 Present Value of Proved Reserves to be $226.9
        million, $511.0 million and $764.8 million at December 31, 1998, 1997
        and 1996, respectively. SFAS No. 69 requires the Company to further
        reduce these estimates by an amount equal to the present value of
        estimated income taxes which might be payable by the Company in future
        years to arrive at the Standardized Measure. Future income taxes were
        calculated by applying the statutory federal income tax rate to pretax
        future net cash flows, net of the tax basis of the properties involved
        and utilization of available tax carryforwards. A large portion of the
        Company's reserve base (approximately 90% of year-end 1998 reserve
        volumes) is comprised of long-life oil properties that are sensitive to
        crude oil price volatility. By comparison, using a NYMEX Crude Oil Price
        of $18.34 per barrel, results in a Present Value of Proved Reserves of
        $705 million and estimated net proved reserves of 219 million barrels of
        oil equivalent. Such information is based upon reserve reports prepared
        by independent petroleum engineers, in accordance with the rules and
        regulations of the SEC, using the same crude oil price used in preparing
        year-end 1997 reserve information.

                                      F-27
<PAGE>
 
     The principal sources of changes in the Standardized Measure of future net
cash flows for the three years ended December 31, 1998, are as follows:

<TABLE> 
<CAPTION> 
                                                                                 Year End December 31,
                                                                      -------------------------------------------
                                                                           1998           1997           1996
                                                                      -------------  -------------  -------------
                                                                                     (in thousands)
<S>                                                                     <C>            <C>            <C> 
 Balance, beginning of year                                             $ 411,823      $ 578,581      $ 304,841
 Sales, net of production expenses                                        (51,927)       (63,917)       (58,866)
 Net change in sales and transfer prices, net of production expenses     (288,320)      (359,138)       275,200
 Changes in estimated future development costs                             42,858          9,927         (5,188)
 Extensions, discoveries and improved recovery, net of costs               21,095         84,676         50,013
 Previously estimated development costs incurred during the year           25,501         23,449         19,662
 Purchase of reserves in-place                                             14,173         74,278          2,253
 Sales of reserves in-place                                                (1,151)        (1,501)        (3,357)
 Revision of quantity estimates                                           (91,942)       (57,597)       145,815
 Accretion of discount                                                     51,099         76,477         36,678
 Net change in income taxes                                                99,170         87,024       (124,254)
 Changes in estimated timing of production and other                       (5,436)       (40,436)       (64,216)
                                                                      -------------  -------------  -------------
 Balance, end of year                                                   $ 226,943      $ 411,823      $ 578,581
                                                                      =============  =============  =============
</TABLE> 


NOTE 19 - QUARTERLY FINANCIAL DATA (UNAUDITED)
----------------------------------------------

     The following table shows summary financial data for 1998 and 1997.

<TABLE> 
<CAPTION> 
                                                        Quarter Ended
                         -------------------------------------------------------------------------
                           March 31,         June 30,          September 30,        December 31,
                         --------------    --------------    -----------------    ----------------
                                          (in thousands, except per share data)
1998
<S>                          <C>               <C>                  <C>                 <C> 
Revenues                     $ 193,572         $ 189,441            $ 393,719           $ 456,545 (1)
Operating profits               17,534            18,323               27,111              28,154 (1)
Net income                       1,431             1,418                3,625             (65,028)
Basic EPS                         0.07              0.07                 0.11               (4.00)
Diluted EPS                       0.06              0.06                 0.10               (4.00)

1997
Revenues                     $ 207,132         $ 188,592            $ 220,660           $ 245,860
Operating profits               18,609            18,666               18,567              20,874
Net income                       3,891             3,252                2,759               4,357
Basic EPS                         0.24              0.20                 0.17                0.25
Diluted EPS                       0.22              0.18                 0.15                0.23
</TABLE> 
------------------
(1) Excludes the net gain of $60.8 million recorded upon the formation of PAA.

NOTE 20 - OPERATING SEGMENTS
----------------------------

     The Company's operations consist of two operating segments: (1) Upstream
Operations - engages in the acquisition, exploitation, development, exploration
and production of crude oil and natural gas and (2) Midstream Operations -
engages in crude oil gathering, marketing, terminalling, storage and
transportation. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies (See Note 1). The
Company evaluates segment performance based on gross margin, gross profit and
income before income taxes and extraordinary items.

                                      F-28
<PAGE>
 
     The following schedule summarizes certain segment information.

<TABLE> 
<CAPTION> 
 (In thousands)                                              Upstream          Midstream           Total
------------------------------------------------------------------------------------------------------------
<S>                                                         <C>              <C>               <C> 
 1998
 Revenues:
   External Customers                                         $ 102,754       $ 1,129,689       $ 1,232,443
   Intersegment (a)                                                   -               119               119
   Interest income                                                  250               584               834
                                                          --------------     -------------     -------------
     Total revenues of reportable segments                    $ 103,004       $ 1,130,392       $ 1,233,396
                                                          ==============     =============     =============

 Segment gross margin (b)(d)                                  $  51,927       $    38,361       $    90,288
 Segment gross profit (c)(d)                                     46,446            33,064            79,510
 Segment income/(loss) before income taxes
   and extraordinary item (d)                                  (175,926)           15,646          (160,280)
 Interest expense                                                23,099            12,631            35,730
 Depreciation, depletion and amortization                       199,523             5,371           204,894
 Income tax expense (benefit)                                   (47,283)            4,563           (42,720)
 Capital expenditures                                           100,935           405,508           506,443
 Assets                                                         364,059           610,208           974,267

------------------------------------------------------------------------------------------------------------
 1997
 Revenues:
   External Customers                                         $ 109,403       $   752,522       $   861,925
   Intersegment (a)                                                   -                 -                 -
   Interest 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

------------------------------------------------------------------------------------------------------------
 1996
 Revenues:
   External Customers                                         $  97,601       $   531,698       $   629,299
   Intersegment (a)                                                   -                 -                 -
   Interest income                                                  219                90               309
                                                          --------------     -------------     -------------
     Total revenues of reportable segments                    $  97,820       $   531,788       $   629,608
                                                          ==============     =============     =============

 Segment gross margin (b)                                     $  58,866       $     9,531       $    68,397
 Segment gross profit (c)                                        54,111             6,557            60,668
 Segment income before income taxes and
   extraordinary item                                            15,806             1,948            17,754
 Interest expense                                                13,727             3,559            17,286
 Depreciation, depletion and amortization                        20,797             1,140            21,937
 Income tax expense (benefit)                                    (4,624)              726            (3,898)
 Capital expenditures                                            51,134             2,941            54,075
 Assets                                                         307,692           122,557           430,249

------------------------------------------------------------------------------------------------------------
</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 the segments.

                                      F-29
<PAGE>
 
     The following schedule reconciles segment revenues to amounts reported in
the Company's financial statements:

<TABLE> 
<CAPTION> 
                                                                 For the Year Ended December 31,
                                                          ------------------------------------------
                                                               1998           1997           1996
                                                          -------------   -----------    -----------
           <S>                                             <C>             <C>            <C> 
           Revenues of reportable segments                 $ 1,233,396     $ 862,244      $ 629,608
           Intersegment                                           (119)            -              -
           Net gain recorded upon the formation of PAA     
             not allocated to reportable segments               60,815             -              -
                                                          -------------   -----------    -----------
           Total company revenues                          $ 1,294,092       862,244        629,608
                                                          =============   ===========    ===========
</TABLE> 


NOTE 21 - SUBSEQUENT EVENT
---------------------------

     On March 17, 1999, PAA signed a definitive agreement with Marathon Ashland
Petroleum LLC to acquire Scurlock Permian LLC and certain other pipeline assets.
The cash purchase price for the acquisition is approximately $138 million, plus
associated closing and financing costs. The purchase price is subject to
adjustment at closing for working capital on April 1, 1999, the effective date
of the acquisition. Closing of the transaction is subject to regulatory review
and approval, consents from third parties, and customary due diligence. Subject
to satisfaction of the foregoing conditions, the transaction is expected to
close in the second quarter of 1999. PAA has received a financing commitment
from one of its existing lenders, which in addition to other financial resources
currently available to PAA, will provide the funds necessary to complete the
transaction. The definitive agreement provides that if either party fails to
perform its obligations thereunder through no fault of the other party, such
defaulting party shall pay the nondefaulting party $7.5 million as liquidated
damages.

     Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland
Petroleum LLC, is engaged in crude oil transportation, trading and marketing,
operating in 14 states with more than 2,400 miles of active pipelines, numerous
storage terminals and a fleet of more than 225 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, Howard, Martin, Midland, Regan,
Upton and Irion Counties, Texas. The assets to be acquired also include
approximately one million barrels of crude oil used for linefill requirements.

                                      F-30