<PAGE>   1
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                    FORM 10-Q

    (Mark One)

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

                For the quarterly period ended September 30, 2000

                                       or

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

              For the transition period from _________to__________

    Commission File No. 0-22483

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

                            SEVEN SEAS PETROLEUM INC.
             (Exact name of registrant as specified in its charter)

        YUKON TERRITORY                                          73-1468669
   (State or other jurisdiction                               (I.R.S. Employer
of  incorporation or organization)                           Identification No.)

SUITE 1700, 5555 SAN FELIPE HOUSTON, TEXAS                         77056
 (Address of principal executive offices)                        (Zip Code)

    Registrant's telephone number, including area code: (713) 622-8218

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

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

    Yes  X   No ----

    Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.

As of November 13, 2000 there were 37,836,420 shares of the registrant's common
shares, no par value per share, outstanding.


<PAGE>   2

                                      INDEX
<TABLE>
<CAPTION>
                                                                            PAGE
<S>                                                                          <C>
PART I. FINANCIAL INFORMATION
(DEVELOPMENT STAGE ENTERPRISE)

  Item 1.  Condensed Consolidated Balance Sheets as of September 30, 2000
           (Unaudited) and December 31, 1999................................  3

           Condensed Statements of Consolidated Operations and
           Accumulated Deficit for the nine months and three months ended
           September 30, 2000 and 1999 and the Cumulative Total from
           Inception (February 3, 1995) to September 30, 2000 (Unaudited)...  4

           Condensed Statements of Consolidated Cash Flows for the nine
           months and three months ended September 30, 2000 and 1999 and the
           Cumulative Total from Inception (February 3, 1995) to
           September 30, 2000 (Unaudited)...................................  4

           Notes to Condensed Consolidated Financial Statements
           (Unaudited)......................................................  6

  Item 2.  Management's Discussion and Analysis of Financial Condition
           and Results of Operations........................................ 11

  Item 3.  Quantitative and Qualitative Disclosures about Market Risk....... 19

PART II. OTHER INFORMATION.................................................. 20

  Item 6.  Exhibits and Reports on Form 8-K................................. 20

</TABLE>



                                       2
<PAGE>   3
                   SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
                        (A DEVELOPMENT STAGE ENTERPRISE)
                     CONDENSED CONSOLIDATED BALANCE SHEETS
                        (In thousands, except share data)

<TABLE>
<CAPTION>

                                                                          SEPTEMBER 30,    DECEMBER 31,
                                                                              2000             1999
                                                                         --------------    ------------
                                                                         (UNAUDITED)
<S>                                                                         <C>              <C>
ASSETS
CURRENT ASSETS
<S>                                                                         <C>              <C>
     Cash and cash equivalents                                              $  14,236        $  22,447
     Short-term investments                                                       984               --
     Restricted short-term investments                                         13,479           13,312
     Accounts receivable                                                        4,150            9,821
     Interest receivable                                                          109              243
     Inventory                                                                    764              764
     Prepaids and other                                                           203              288
                                                                            ---------        ---------
                                                                               33,925           46,875

Notes receivable from employees                                                   215              435
Restricted long-term investments                                                   --            6,391
Land                                                                            1,071            1,065
Evaluated oil and gas interests, full-cost method, net of
     accumulated depletion of $1,111 at September 30, 2000 and $764
     at December 31, 1999                                                     108,366           96,244
Unevaluated oil and gas interests, full-cost method                           106,888          105,725
Fixed assets, net of accumulated depreciation of $957 at
     September 30, 2000 and $669 at December 31, 1999                             893            1,060
Other assets, net of accumulated amortization of $1,523 at
     September 30, 2000 and $1,068 at December 31, 1999                         2,831            3,287
                                                                            ---------        ---------
TOTAL ASSETS                                                                $ 254,189        $ 261,082
                                                                            =========        =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
     Accounts payable                                                       $   2,240        $   7,917
     Interest payable                                                           5,156            1,719
     Other accrued liabilities                                                     --               78
                                                                            ---------        ---------
                                                                                7,396            9,714
Long-term debt                                                                110,000          110,000
Deferred income taxes                                                          24,794           24,794
COMMITMENTS AND CONTINGENCIES (Note 4)

STOCKHOLDERS' EQUITY
Share capital
     Authorized unlimited common shares without par value and
       37,836,420 and 37,833,420 issued and outstanding common
       shares at September 30, 2000 and December 31, 1999,
       respectively                                                           225,807          225,805
     Authorized unlimited Class A preferred shares without
       par value                                                                   --               --
Deficit accumulated during development stage                                 (113,808)        (109,231)
Treasury stock, 29 shares held at September 30, 2000 and
     December 31, 1999                                                             --               --
Total Stockholders' Equity                                                    111,999          116,574
                                                                            ---------        ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                  $ 254,189        $ 261,082
                                                                            =========        =========
</TABLE>


    The accompanying notes are an integral part of these financial statements.


                                       3
<PAGE>   4
                   SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
                        (A DEVELOPMENT STAGE ENTERPRISE)
    STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS AND ACCUMULATED DEFICIT
                  (Unaudited, In thousands, except share data)

<TABLE>
<CAPTION>
                                                                                                                     CUMULATIVE
                                                                                                                     TOTAL FROM
                                                                                                                     INCEPTION
                                                                                                                    (FEBRUARY 3,
                                                         NINE MONTHS ENDED               THREE MONTHS ENDED           1995) TO
                                                            SEPTEMBER 30,                   SEPTEMBER 30,           SEPTEMBER 30,
                                                        2000            1999            2000            1999           2000
                                                     ----------      ----------      ----------      ----------     -------------
<S>                                                  <C>             <C>             <C>             <C>             <C>
REVENUE
     Crude oil sales                                 $    1,959      $      308      $    1,943      $      123      $    5,249
     Interest income                                      1,397           2,403             391             705           9,511
                                                     ----------      ----------      ----------      ----------      ----------
                                                          3,356           2,711           2,334             828          14,760
EXPENSES
     General and administrative                           5,409           6,234           1,676           1,610          35,093
     Oil and gas operating expenses                       1,209           1,662             255             151           5,802
     Depletion, depreciation and amortization             1,094             806             581             292           3,890
     Interest expense                                        97            --                97            --                97
     Writedown of proved oil & gas properties              --              --              --              --           129,789
     Loss (Gain) on sale of exploration properties         --               670            --              --               124
     Dry hole and abandonment costs                        --              --              --              --             1,145
     Geological and geophysical                            --              --              --              --                47
     Other (income) expense                                 104              73             (53)             51             (54)
                                                     ----------      ----------      ----------      ----------      ----------
                                                          7,913           9,445           2,556           2,104         175,933
NET LOSS BEFORE INCOME TAXES
     AND MINORITY INTEREST                               (4,557)         (6,734)           (222)         (1,276)       (161,173)
                                                     ----------      ----------      ----------      ----------      ----------
INCOME TAX EXPENSE                                           20              30              20              10         (45,636)

NET LOSS BEFORE MINORITY INTEREST                        (4,577)         (6,764)           (242)         (1,286)       (115,537)
                                                     ----------      ----------      ----------      ----------      ----------
MINORITY INTEREST                                          --               593            --              --             1,729
                                                     ----------      ----------      ----------      ----------      ----------

NET LOSS                                             $   (4,577)     $   (6,171)     $     (242)     $   (1,286)     $ (113,808)
                                                     ==========      ==========      ==========      ==========      ==========
DEFICIT ACCUMULATED DURING THE DEVELOPMENT
     STAGE, BEGINNING OF PERIOD                        (109,231)       (102,442)       (113,566)       (107,327)           --

DEFICIT ACCUMULATED DURING THE DEVELOPMENT
     STAGE, END OF PERIOD                            $ (113,808)     $ (108,613)     $ (113,808)     $ (108,613)     $ (113,808)
                                                     ==========      ==========      ==========      ==========      ==========
BASIC AND DILUTED NET LOSS PER COMMON SHARE          $    (0.12)     $    (0.16)     $    (0.01)     $    (0.03)     $    (4.12)
                                                     ==========      ==========      ==========      ==========      ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING           37,834,777      37,806,072      37,836,420      37,833,420      27,593,915
                                                     ==========      ==========      ==========      ==========      ==========
</TABLE>




    The accompanying notes are an integral part of these financial statements.




                                       4
<PAGE>   5
                   SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
                        (A DEVELOPMENT STAGE ENTERPRISE)
                STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS
                            (Unaudited; In thousands)

<TABLE>
<CAPTION>
                                                                                                                CUMULATIVE
                                                                                                                TOTAL FROM
                                                                                                                 INCEPTION
                                                                                                               (FEBRUARY 3,
                                                                                                                 1995) TO
                                                                       NINE MONTHS ENDED SEPTEMBER 30,         SEPTEMBER 30,
                                                                       -------------------------------         -------------
                                                                          2000                1999                 2000
                                                                       ---------           ----------          -------------

<S>                                                                     <C>                <C>                  <C>
OPERATING ACTIVITIES
     Net loss                                                           $(4,577)           $  (6,171)           $(113,808)
     Add (subtract) items not requiring (providing) cash:
     Compensation expense                                                    --                   --                2,140
     Minority interest                                                       --                 (593)              (1,729)
     Common stock contribution to 401(k) retirement plan                     --                   --                   79
     Depletion, depreciation and amortization                             1,094                  806                3,895
     Interest expense                                                        97                   --                   97
     Writedown of proved oil & gas properties                                --                   --              129,789
     Gain (loss) on sale of exploration property                             --                  670                  124
     Dry hole and abandonment costs                                          --                   --                1,140
     Gain on sale of marketable securities                                   --                   --                   (6)
     Gain on sale of fixed assets                                             2                                         2
     Deferred income tax benefit                                             --                   --              (45,665)
     Amortization of investments                                           (651)              (1,048)              (2,008)
     Changes in working capital excluding changes to cash and
      cash equivalents:
        Accounts receivable                                               5,671                2,115               (1,888)
        Interest receivable                                                 134                  442                 (109)
        Inventory                                                            --                   27                 (968)
        Prepaids and other, net                                              86                  172                 (202)
        Accounts payable                                                 (4,947)              (3,513)                  54
       Other accrued liabilities                                            (78)                (223)                 249
                                                                        --------           ---------            ---------
Cash Flow Used in Operating Activities                                   (3,169)              (7,316)             (28,814)
                                                                        -------            ---------            ---------
INVESTING ACTIVITIES
     Exploration of oil and gas properties                              (11,023)             (20,427)            (111,236)
     Purchase of land                                                        (6)                  (1)              (1,264)
     Purchase of investments                                               (984)              (8,818)             (39,285)
     Proceeds from acquisition                                               --                   --                  630
     (Payment to withdraw) proceeds from sale of property                    --                 (250)                 997
     Proceeds from sale of marketable securities                             --                   --                   50
     Proceeds from sale of investments                                    6,875               13,080               26,830
     Notes receivable from employees                                        220                 (236)                (215)
     Other asset additions                                                 (126)                (216)              (2,121)
                                                                        -------            ---------            ---------
Cash Flow Used in Investing Activities                                   (5,044)             (16,868)            (125,614)
                                                                        -------            ---------            ---------
FINANCING ACTIVITIES
     Proceeds from special warrants issued                                   --                   --               12,393
     Proceeds from share capital issued                                       2                   --               15,468
     Proceeds from additional paid-in capital contributed                    --                   --                    1
     Proceeds from issuance of  long-term debt                               --                   --              135,000
     Costs of issuing long-term debt                                         --                   --               (5,821)
     Contributions by minority interest                                      --                1,386               11,623
                                                                        -------            ---------            ---------
Cash Flow Provided by Financing Activities                                    2                1,386              168,664
                                                                        -------            ---------            ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                     (8,211)             (22,798)              14,236
Cash and cash equivalents, beginning of period                           22,447               38,147                   --
                                                                        -------            ---------            ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD                                $14,236            $  15,349            $  14,236
                                                                        =======            =========            =========
</TABLE>

Supplemental disclosures of cash flow information:

    The Company incurred interest costs of $10.3 million and $10.3 million for
the nine-month periods ended September 30, 2000 and 1999, respectively, and
$10.2 million and $10.3 million was capitalized during the respective periods.

    Cash paid for interest for the nine-month periods ended September 30, 2000
and 1999 was $6.9 million and $6.9 million, respectively.

    The Company paid $11,000 and zero for estimated income taxes during the
nine-month periods ended September 30, 2000 and 1999, respectively.

    The accompanying notes are an integral part of these financial statements.


                                       5
<PAGE>   6
                   SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
                        (A DEVELOPMENT STAGE ENTERPRISE)
              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)

                        1. DEVELOPMENT STAGE OPERATIONS

FORMATION

    Seven Seas Petroleum Inc. (a Yukon Territory, Canada corporation) was formed
on February 3, 1995. Seven Seas Petroleum Inc. and its subsidiaries
(collectively referred to as "Seven Seas" or the "Company") are a development
stage enterprise engaged in the exploration, development and production of oil
and natural gas in Colombia. The Company is the operator of an oil discovery,
known as the "Guaduas field," which is located in an area defined by the Rio
Seco and Dindal Association Contracts (the "Association Contracts") covering a
total of approximately 109,000 contiguous acres in central Colombia. The Company
owns a 57.7% working interest in the two Association Contracts before
participation by Empresa Colombiana de Petroleos ("Ecopetrol"), the Colombian
state oil company. The Company has no significant income producing properties
and its principal assets, its interests in the Association Contracts, are in the
early stage of exploration and development.

ACTIVITY TO DATE

    As of September 30, 2000, the Company has spent $242.2 million to acquire
and $77.8 million to delineate the reserve potential of the Guaduas field. The
Company has drilled twelve exploratory wells within the Association Contracts,
of which six have been production tested and have achieved maximum actual oil
production rates ranging from 3,415 to 13,123 Bbls/d. Four of the twelve did not
produce commercial amounts of oil and gas during testing and two remain to be
tested. As of September 30, 2000, the Guaduas field had produced a cumulative
volume of approximately 969,000 barrels (354,000 barrels net to the Company) of
oil. The Company plans to truck any production prior to installation of the
necessary production facilities and pipeline.

    Since inception through September 30, 2000, the Company incurred cumulative
losses of $113.8 million and, because of its continued exploration and
development activities, expects that it will continue to incur losses and that
its accumulated deficit will increase until commencement of production from the
Association Contracts occurs in quantities sufficient to cover operating
expenses.

CURRENT STRATEGY

    In late May 2000, Ecopetrol advised the Company that it elected not to
participate in the Guaduas field development at this time, and authorized us to
proceed with the development of the field on a sole-risk basis. Proceeding on a
sole risk basis will mean that Seven Seas, Sipetrol, and Cimarrona LLC will pay
100% of the development costs. We will also retain all revenues from production
after the 20% Colombian royalty deduction. If we proceed on a sole-risk basis,
Ecopetrol can still participate in development, at any time, but that right is
subject to our right to 200% reimbursement of any costs we incur after
Ecopetrol's original decision not to participate in the field's development.

Sipetrol and Cimarrona collectively own 42.3% of the working interest under the
association contracts, but they have not decided whether to participate in the
pipeline. We could not agree with our association contract partners on a
comprehensive budget for the development of the Guaduas field, including
pipeline construction and a schedule for the drilling of additional development
wells. As a consequence, we have given Sipetrol and Cimarrona formal notice
under the operating agreement of our intention to proceed sole risk, even if
they do not participate. It is our position that Sipetrol and Cimarrona have now
forfeited their right to participate in the pipeline and are subject to the
penalty provision of our operating agreement which allows Seven Seas to retain
their share of production until we recoup our costs of construction of the
pipeline plus the applicable penalties. Sipetrol and Cimarrona dispute our
position. We are currently negotiating with Sipetrol and Cimarrona to resolve
the controversy. The matter may have to be resolved by arbitration under the
provisions of the operating agreement. In any event, Seven Seas is proceeding
with plans for the construction of the pipeline.

    The continued development of the Company's evaluated properties and
evaluation of its unevaluated properties is expected to require additional
capital which the Company may be required to raise through debt or equity
financing, encumbering properties or entering into arrangements whereby certain
costs will be paid by others to earn an interest in the property. If the Company
is


                                       6
<PAGE>   7
unsuccessful or delayed in its exploration and development plan, constructing
production and transportation facilities, increasing its proved reserves or
realizing future production from its properties, the Company may be unable to
pay existing or future debt or meet operating cash flow requirements and the
recoverability and classification of asset carrying amounts or the amount and
classification of liabilities may be impacted.

CAPITAL AVAILABILITY AND LIQUIDITY

    As of September 30, 2000, the Company had unrestricted cash and short-term
investments of $15.2 million and commitments under existing oil and gas
agreements of $2.2 million for the remainder of 2000. Management believes that
it has adequate cash resources to fund its existing commitments and operating
needs during 2000. However, if available capital is utilized as contemplated by
the current strategy, the Company will have to seek additional financing for
operations, including further exploratory drilling to extend the area of the
Guaduas field and to test the deeper formations of the subthrust structure on
the Dindal association contract area. Under the terms of the Company's $110
million senior notes, general indebtedness that can be senior to our senior
notes not exceeding the greater of a) $25 million, or b) the sum of 100% of our
cash and cash equivalents, 100% of our receivable from Ecopetrol, and 30% of our
discounted future net revenues from proved oil and gas reserves prepared in
accordance with United States Securities Exchange Commission. The Company is
also allowed to borrow an additional $10 million for project financing, e.g.,
pipeline and production facilities. Any additional financing obtained by the
Company to execute its business plans may result in a dilution of current
stakeholder interests.

    Funds sufficient to meet interest payments for three years of the $110
million senior notes were placed into escrow upon issue of the senior notes. The
final interest payment under this escrow arrangement is May 2001. Seven Seas
cannot be certain that additional sources of financing will be available when
needed or will be available on acceptable terms. The Company has suffered
recurring losses from operations, has an accumulated deficit, has not generated
positive cash flow from operations, has significant unproved property balances,
is nearing the end of the exploration phase of its association contracts, is
dependant on the actions of Ecopetrol, and will likely require additional
capital to execute its business plans.

RISK FACTORS

    Seven Seas is subject to several categories of risk associated with its
development stage activities. Oil and gas exploration and development is a
speculative business and involves a high degree of risk. Among the factors that
have a direct bearing on Seven Seas' prospects are uncertainties inherent in
estimating oil and gas reserves and future hydrocarbon production and cash
flows, particularly with respect to wells that have not been fully tested and
with wells having limited production testing histories; access to additional
capital; changes in the price of oil and natural gas, services and equipment;
the limited exploration of the concessions; the status of existing and future
contractual relationships with Ecopetrol; regulation in Colombia; lack of
significant income producing property; foreign currency fluctuation risks; Seven
Seas' substantial indebtedness, the presence of competitors with greater
financial resources and capacity; and difficulties and risks associated with
operating in Colombia.

2. BASIS OF PRESENTATION

    The accompanying unaudited, condensed consolidated financial statements
include the accounts of Sevens Seas Petroleum Inc. and its subsidiaries after
elimination of intercompany balances and transactions.

    The unaudited, condensed consolidated financial statements of the Company
for the periods indicated herein have been prepared by the Company pursuant to
the rules and regulations of the United States Securities and Exchange
Commission, accordingly, they do not include all of the information and
footnotes required by generally accepted accounting principles for complete
financial statements. In the opinion of management, all adjustments, consisting
of normal recurring accruals, necessary to present fairly the information in the
accompanying condensed consolidated financial statements have been included.
Interim period results are not necessarily indicative of the results of
operations or cash flows for a full year period. The condensed financial
statements included herein should be read in conjunction with the audited
financial statements and notes thereto included in the Company's Annual Report
on Form 10-K for the year ended December 31, 1999.

    Certain reclassifications have been made to prior years amounts to conform
to current reporting practices.



                                       7
<PAGE>   8
3. OPERATIONS BY GEOGRAPHIC AREA

    The Company has one operating and reporting segment. Information about the
Company's operations for the nine-month and three-month periods ended September
30, 2000 and 1999 and by geographic area is shown below (In thousands):

<TABLE>
<CAPTION>

                                                                              OTHER
                                                    UNITED                   FOREIGN
                                          CANADA    STATES      COLOMBIA      AREAS      TOTAL
                                          ------    ------      --------     -------   ---------
<S>                                      <C>        <C>         <C>           <C>      <C>
Nine months ended September 30, 2000
  Revenues...........................    $  1,361   $     9     $   1,986     $  --    $   3,356
  Operating Loss.....................        (429)   (1,835)       (2,278)      (15)      (4,557)
  Capital Expenditures...............          --       108         3,438        --        3,846
  Identifiable Assets................      64,439       833       188,854        63      254,189
  Depletion, Depreciation and
   Amortization......................         455       223           416        --        1,094

Nine months ended September 30, 1999
  Revenues...........................    $  2,311   $     9     $     391     $  --    $   2,711
  Operating Income (Loss)............       1,124    (2,569)       (4,599)     (690)      (6,734)
  Capital Expenditures...............          --        61         8,822       250        9,133
  Identifiable Assets................      74,453     1,080       183,243        81      258,857
  Depreciation and Amortization......         455       251           100        --          806

Three months ended September 30, 2000
  Revenues...........................    $    387   $     3     $   1,944     $  --    $   2,334
  Operating Income (Loss)............        (212)     (465)          456        (1)        (222)
  Capital Expenditures...............          --        38           (65)       --          (26)
  Identifiable Assets................      64,439       833       188,854        63      254,189
  Depletion, Depreciation and
   Amortization......................         152        63           366        --          581

Three months ended September 30, 1999
  Revenues...........................    $    682   $     3     $     143     $  --    $     828
  Operating Income (Loss)............         381      (901)         (752)       (4)      (1,276)
  Capital Expenditures...............          --         3           966        --          969
  Identifiable Assets................      74,453     1,080       183,243        81      258,857
  Depreciation and Amortization......         151        84            57        --          292
</TABLE>


4. CONTINGENCIES

COLOMBIAN FOREST RESERVE

         Two mutually overlying forest reserves existed in an area corresponding
to the Dindal Association Contract, one prior to and another subsequent to the
signing of this contract. The first one corresponds to a national reserve
declared in 1981 and enlarged in 1985, that sets limits to economic activities
other than the rational use of forests.

         The second one corresponds to a reserve declared by the municipality of
Guaduas in 1998, forbidding oil-related activity in the mentioned reserve's
area. The Municipal City Hall recently revoked this reserve through the Land Use
Plan that adopted the national forest reserve as the only existing reserve.

         The Colombian environmental legislation foresees the form for the
subtraction of areas located in forest reserves for the development of economic
activities other than the rational use of forests that are also for the benefit
of the public or of social interest. Consequently, in order to conduct
oil-related activities within the reserve area, GHK Company Colombia has started
the process before the Ministry of the Environment to achieve the subtraction of
the area corresponding to the project.


ENVIRONMENTAL PENALTIES

         On June 8, 1998, the Ministry of Environment required our subsidiary,
GHK Company Colombia, to perform some remedial work on the El Segundo 6-E
location and access road. GHK Company Colombia performed the work and thereafter
reported to the Ministry of Environment that all the work had been completed. In
various site visits, ministry officials have confirmed that the alleged
violations have been properly remedied. On July 8, 1999, GHK Company Colombia
filed all the documentation which confirmed total compliance to the
requirements.


                                       8
<PAGE>   9

         On August 30, 1999, the Ministry of Environment issued a resolution
against GHK Company Colombia, declaring it in violation of a 1997 decree in
connection with the construction of the El Segundo 7-E well location. The
resolution imposed a fine of approximately $217,000, which we paid in March
2000. We have filed an appeal for a reversal of the resolution. We believe that
we have corrected the environmental violations claimed by the Ministry of
Environment; however, the appeal process can take up to two years. The El
Segundo 7 location has been restored and we currently have no drilling
activities planned at this location.

CONTRACT AREAS

    The Dindal Association Contract was issued in March 1993 and provides for a
maximum six-year exploration period followed by a maximum 22-year production
period, with partial relinquishment of acreage, excluding commercial fields and
a five kilometer buffer zone, required at the end of the sixth year of the
Association Contract. The exploration period under the Dindal Association
Contract was extended to September 23, 2000, since the Associates committed
to an additional $2.0 million of exploration work in accordance with the
memorandum of understanding signed with Ecopetrol in September 1999. Together
with our partners in the Guaduas field, we recently accepted an offer from
Ecopetrol to formally apply for an "on-top" contract that will provide improved
fiscal and contract terms for the subthrust Dindal prospect. An "on-top"
contract will effectively be an amendment to the Dindal association contract,
and should enable us to retain the entire acreage in the Dindal block for the
subthrust structure. Concurrent with our application for an "on-top" contract,
we also applied for an extension of the exploration period under the Dindal
association contract to avoid having to relinquish a part of the Dindal
association contract at this time. However, Ecopetrol has not made a final
decision, and the Company may be required to relinquish some of the contract
area once a final decision has been made.

    The Rio Seco Association Contract was issued in August 1995 and provides for
a maximum six-year exploration period followed by a maximum 22-year production
period, with partial relinquishment of acreage, excluding commercial fields,
required commencing at the end of the sixth year of the Association Contract.
The exploration period under the Rio Seco Association Contract ends in August
2001. We are obligated to drill one additional exploratory well before the
exploration period ends.

Seven Seas has tentatively reached agreement with Ecopetrol to substitute one
well with logs and coring for the second year seismic obligation for the
Montecristo Association Contract Area and to satisfy the third year well
obligation for the Rosablanca Association Contract Area. As part of the
agreement, Seven Seas will relinquish Montecristo Contract area. The well must
be started before February 28, 2001. In order to comply with the Rosablanca
association contract terms, we will reduce the contract area by 30,000 hectares.
On November 8, 2000, we notified Potomac Energy Corporation (Potomac), a 25%
working interest partner in both the Rosablanca and Montecristo association
contracts, that they are in default of approximately $0.4 million of their
share of costs under the Joint Operating Agreement. Potomac must remedy the
default within 30 days.

In the Central Llanos basin, 40 miles east of the Cusiana Field, we own an
11.875% initial working interest in the 116,795 acre Tapir association contract
area, which is operated by Mohave Colombia Corporation (Mohave). In August 2000,
we signed a purchase and sale agreement with Solana Petroleum Exploration
Colombia (Solana) to sell our 11.875% interest in the Tapir association contract
for 3,000,000 common shares of Solana Colombia's parent corporation, Solana
Petroleum Corporation. The transfer of our interest is pending approval from the
Canadian Venture Exchange. Upon receiving approval, Solana is contractually
obligated to reimburse us for our costs attributable to the Tapir block since
August 1, 1999, which total approximately $0.4 million. Solana Petroleum
Exploration Colombia is currently in default for failure to pay its
participating share of Joint Account expenses and it is unlikely that they will
be able to close on the purchase of our 11.875% interest.

In January 2001, Mohave will begin the sixth year work program. The proposed
program includes construction of an all-weather road, production testing the
Mateguafa 1 and 2 wells, and drilling an exploratory well. In the event that
Solana is unable to close on the purchase of our interest, we will be
responsible for our proportionate share of the costs of sixth year work program,
estimated to be $2.129 million. We will continue to look for a potential
purchaser for our interest.

SURFACE LOCATION

    A lawsuit has been filed by the landowners of the El Segundo 1 surface
location to cancel our surface lease. Our Colombian legal counsel, Gamba,
Barrera, Arriaga y Asociados, has advised us that, on the basis of the claims
asserted, we should win the lawsuit. We responded to this claim on November 4,
1999, and plan to vigorously defend this claim.


                                       9
<PAGE>   10
NOTEHOLDER CLAIM

    A claim has been brought against Seven Seas by one of the noteholders in
connection with the Special Notes issued on August 7, 1997. The claim, which is
against Seven Seas and Yorkton Securities Inc., alleges that the noteholder was
not initially advised of the right of Seven Seas to convert the debentures into
units of common shares and warrants. The claim also alleges that there were
errors in the methodology of effecting conversion pursuant to the indenture
between Seven Seas and Montreal Trust Company of Canada dated August 7, 1997
such that the conversion was not effective. The plaintiff in the claim is
seeking damages against Seven Seas in the amount of $340,000 for negligent
misrepresentation and breach of contract or alternatively, for an order
directing Seven Seas to exchange the units currently held by the plaintiff into
a note in the amount of $340,000 payable on July 24, 2002 with interest payable
thereon at a rate of 6% per annum or directing Seven Seas to reimburse the
plaintiff in the amount of $340,000 for the purchase price of the Special Notes.
Seven Seas believes it has meritorious defenses and intends to take appropriate
steps to defend the action vigorously.

    The Company is, from time to time, party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a material adverse effect on the financial position or results of
operations or cash flows of the Company.

FORMER MANAGEMENT

   The Company and two of its officers and directors, Robert A. Hefner, III,
and Larry Ray, and one of its former directors, Breene M. Kerr, have been sued
by four former officers and directors of the Company in DeCort, et al. v. Seven
Seas Petroleum, Inc., et al., Cause No. 2000-50498, District Court of Harris
County, Texas, 133rd Judicial District. Plaintiffs allege that the Company
failed to obtain extensions of time in which plaintiffs could exercise certain
stock options granted to them, and that all defendants induced them to enter
into separation agreements with the Company that they would not have entered
into but for the Company's agreement to obtain an extension of the time for
plaintiffs to exercise their stock options. The case was filed October 2, 2000,
and the Company has not yet responded to plaintiff's allegations. The Company
intends to vigorously defend the case.

5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

    In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities. The Statement, as amended by SFAS 137 and
SFAS 138, establishes accounting and reporting standards requiring that every
derivative instrument, including certain derivative instruments embedded in
other contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair value. The Statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting.

    The Company will adopt this Statement on January 1, 2001 and SFAS 133 will
not have a material impact the Company's disclosure or reporting.

    In the first quarter of 2000, the FASB issued Interpretation No. 44
"Accounting for Certain Transactions involving Stock Compensation - an
interpretation of APB No. 25" ("the Interpretation") which clarifies the
application of APB 25 for certain issues associated with accounting for the
issuance or subsequent modification of stock compensation and is effective July
1, 2000. For certain modifications, including stock option repricings made
subsequent to December 15, 1998, the Interpretation requires that variable plan
accounting be applied to those modified awards prospectively from July 1, 2000.
In January and November, 1999, the Company repriced certain employee stock
options for 706,000 share of stock at a weighted average exercise price of
$14.47 to a new exercise price of $9.00 through the cancellation of existing
options and issuance of new options at or above current market prices. Upon
adoption of this statement, the exercise price of the repriced options exceeded
the Company's stock price resulting in no compensation expense to be recognized
over future vesting. Subsequent to the adoption of the interpretation, the
Company may be required to record the effects of the changes in its stock price
and the corresponding change in intrinsic value of the repriced options in its
results of operations as compensation expense.


                                       10
<PAGE>   11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
        RESULTS OF OPERATIONS

INTRODUCTION

    The following discussion and analysis should be read in conjunction with the
unaudited condensed consolidated financial statements included elsewhere and
with the Company's Annual Report on Form 10-K for the year ended December 31,
1999.

    From time to time, Seven Seas may make certain statements that provide
stockholders and the investing public with "forward-looking" information (as
defined in the Private Securities Litigation Reform Act of 1995). Words such as
"anticipate," "assume," "believe," "estimate," "project," and similar
expressions are intended to identify such forward-looking statements.
Forward-looking statements may be made by management orally or in writing,
including, but not limited to, in press releases, as part of this "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
section and as part of other sections of the Company's filings with the SEC
under the Securities Act and the Securities Exchange Act. Such forward-looking
statements may include, but not be limited to, statements concerning estimates
of current and future results of operations, financial position, reserves, the
timing and commencement of wells and development plans, drilling results as
indicated by log analysis, core samples, examination of cuttings, hydrocarbons
shows while drilling and production estimates from wells drilled based upon
drill stem tests and other test data, future capacity under credit arrangements,
future capital expenditures, liquidity requirements, liquidity sufficiency and
year 2000 compliance.

    Such forward-looking statements are subject to certain risks, uncertainties
and assumptions, including without limitation, those defined below. Should one
or more of these risks or uncertainties materialize, or should any of the
underlying assumptions prove incorrect, actual results of current and future
operations may vary materially from those anticipated, estimated or projected.

    Among the factors that have a direct bearing on Seven Seas' results of
operations and the oil and gas industry in which it operates are uncertainties
inherent in estimating oil and gas reserves and future hydrocarbon production
and cash flows, particularly with respect to wells that have not been fully
tested and with wells having limited production testing histories; access to
additional capital; changes in the price of oil and natural gas, services and
equipment; the limited exploration of the concessions; the status of existing
and future contractual relationships with Ecopetrol; foreign currency
fluctuation risks; Seven Seas' substantial indebtedness, the presence of
competitors with greater financial resources and capacity; and difficulties and
risks associated with operating in Colombia.

OVERVIEW

    Our principal asset is a 57.7% interest (before participation by Ecopetrol,
the Colombian state oil company) in the Dindal and Rio Seco association
contracts. As of December 31, 1999, Ryder Scott Company Petroleum Consultants
estimated total proved recoverable reserves for the Guaduas field of 154.0
million barrels of oil, of which 34.9 million barrels of oil were attributable
to our interest. This reserve estimate was based on several assumptions, one of
which was Ecoptrols's immediate participation in the development in the Guaduas
field. In May 2000, Ecopetrol advised us that it opted not to participate in the
Guaduas field development at this time, and authorized us to proceed with the
development of the field on a sole-risk basis.

    Our current plans for the use of available capital are set forth under
"-- Go Forward Strategy." Whether we can achieve our objectives on schedule and
with our existing capital resources depends on a number of factors, many of
which are not within our control. Factors include timely environmental
permitting, securing pipeline rights of way, timely payments by the association
contract partners of their share of these costs and the market price of oil
field equipment and services. We will seek other sources of financing, including
project financing, industry joint ventures or arrangements with industry service
companies, commercial bank borrowings and traditional debt and equity financing.

REVIEW OF OUR PROGRESS

    In our December 31, 1998 10-K, we outlined our plan for developing the
Guaduas field during 1999 and 2000. Specifically, we estimated that we would
commence field production with Increment I, the trucking production scenario, in
early 2000 at production rates between 4,000 Bbls/d to 6,000 Bbls/d. We also
estimated that we would start Increment II, the early pipeline production
scenario, by year-end 2000. Meeting our original deadlines depended on: (1)
receiving a global operating license from the Colombian Ministry of Environment,
permitting development activity within the Dindal and Rio Seco association
contract areas; (2) receiving an environmental pipeline permit to contract the
36-mile pipeline necessary for completion of Increment II; and (3) approval of
commerciality by Ecopetrol by December 1999.


                                       11
<PAGE>   12
    Originally, we anticipated concluding negotiations with Ecopetrol in June
1999 for an agreement that would lead to a final decision on commerciality; in
which case a date would be established prior to December 31, 1999 by which
Ecopetrol would be contractually obligated to make a decision on commerciality.
Instead, due principally to factors beyond our control, the negotiations
continued for an additional four months, during which time we focused on
negotiating the agreement with Ecopetrol and also conducted the environmental
studies that were required to request the global operating license and the
environmental pipeline permit from the Colombian Ministry of Environment.

    After the agreement with Ecopetrol was signed on September 23, 1999, we
began conducting a long-term production test and drilling the El Segundo 4-E
well to test for a gas cap in the Guaduas filed, as required by the agreement.
After more than four months of production at an average daily rate of 3,183
barrels, over 400,000 barrels of oil were produced, bringing the total number of
barrels produced from the Guaduas field to 790,800 (272,000 net to Seven Seas)
as of December 31, 1999.

    As part of the long-term production test, we shut-in the four wells that had
been tested to measure the pressure build-up of the Guaduas field over an
extended period of 30 days. The shut-in period ended in late January 2000. The
drilling and initial test results of the El Segundo 4-E were also completed by
late January 2000, providing the required data to Ecopetrol's technical
personnel for its decision on commerciality. During May 2000, we were informed
that Ecopetrol would not be participating in the development of the Guaduas
field.

    Based on the new information obtained from drilling the El Segundo 4-E and
the long-term production testing, our independent engineers, the Ryder Scott
Company Petroleum Consultants and Servipetrol Ltd., studied the data from the
Guaduas field for a third consecutive year and Ryder Scott re-affirmed its
estimates of the Guaduas field's oil reserves. Specifically, Ryder Scott
estimated the Guaduas field's total proved reserves to be 154.0 million barrels
as of December 31, 1999, a slight decrease from the December 31, 1998 estimate
of 163.3 million and an increase from the December 31, 1997 estimate of 132.0
million barrels. The December 31, 1999 estimate of the Guaduas field's net
reserves to Seven Seas was 34.9 million, a slight decrease form the December 31,
1998 estimate of 38.7 million and an increase from the December 31, 1997
estimate of 32.2 million barrels. Proved reserves decrease between December 31,
1999 and December 31, 1998 primarily as a result of not encountering the
Cimarrona reservoir up-dip in the El Segundo 4-E well. Despite the decrease in
proved reserves, the pre-tax net present value of our proved oil reserves,
discounted at 10 percent, increase to $311.4 million in the December 31, 1999
report from the $115.9 million in our December 31, 1998 report due to an
increase in oil prices from $12.05 to $25.60. This reserve estimate was based
on several assumptions, one of which was Ecopetrol's immediate participation in
the development in the Guaduas field. In May 2000, Ecopetrol advised us that it
opted not to participate in the Guaduas field development at this time, and
authorized us to proceed with the development of the field on a sole-risk
basis.

CHANGES IN OUR STRATEGY
    Three potential scenarios

    After Ecopetrol informed us in May 2000 that it elected not to participate
in the development of the Guaduas field at this time, Seven Seas, Sipetrol, and
Cimarrona were authorized to proceed with development on a sole-risk basis. In
our 1999 Form 10-K, we contemplated proceeding on a sole-risk basis in our
discussion of the three potential scenarios under which we could proceed to
develop the Guaduas field, depending on Ecopetrol's decision on commerciality.
Proceeding sole-risk is "Scenario 2." Briefly, the three scenarios we originally
contemplated are as follows:

Scenario 1 - Ecopetrol elects to participate in the development of the Guaduas
field

    Provided that we (1) received the global operating license and the
environmental pipeline permit, and (2) were able to secure financing for our
share of the Scenario 1 development costs, we estimated that we would begin
transporting Guaduas field oil production through a pipeline approximately 12
months from the date Ecopetrol approved our commerciality request.

Scenario 2 - Ecopetrol does not elect to participate in the development of the
Guaduas field at that time and authorizes us to proceed with the development on
a sole-risk basis

    In this scenario, Seven Seas and our association contract partners, if they
participate, would pay 100% of the development costs and retain all revenue from
the production after the 20% Colombian royalty deduction. Ecopetrol would have
the right to start participating in development at any time, subject to our
right to 200% reimbursement of our post-commerciality development costs. (When
we say "post-commerciality," we mean after the date on which Ecopetrol informed
us of its decision whether to begin paying 50% of the development costs or to
allow us to proceed on a sole-risk basis.)

Scenario 3 - Ecopetrol does not elect to participate in developing the Guaduas
field and Seven Seas and our partners elect not to proceed on a sole-risk basis,
choosing instead to negotiate a modified agreement with Ecopetrol

    This scenario would likely have consisted of a development plan similar to
Increment I trucking, as described in our 1998 10-K, consisting of limited
production transported to a local refinery by trucking, and would likely have
resulted in the postponement of a


                                       12
<PAGE>   13
final decision on pipeline construction. Depending on oil prices, we anticipated
that Scenario 3 could have produced cash flow for Seven Seas that could have
funded our annual overhead. If we had proceeded under this scenario, our
immediate priority would have been to use our existing cash resources to test
the underlying formations of the subthrust Dindal structure and to further
explore the Rio Seco and Dindal association contract areas to increase the
reserve to the shallow Guaduas filed. We planned to finance this strategy with
our existing cash resources, but we would likely have sought additional
financing.

Proceeding under Scenario 2

    Because Ecopetrol informed us that it has elected not to participate in the
development of the Guaduas field at this time, Scenario 1, described above, is
no longer an option for us and we have decided not to pursue Scenario 3.

    We have elected to proceed under Scenario 2, to put the Guaduas field on
pipeline production on a sole-risk basis. Until the pipeline is completed and
put on production, we will sell oil to the Colombian market by transporting the
production by truck. We are currently selling, and expect to continue to sell by
this means, our share of approximately 5,000 Bbls/d. With current West Texas
Intermediate prices in excess of $30 per barrel, our share of the proceeds of
this production is approximately $1.4 million per month.

    We have commenced operations for the construction of a 36-mile pipeline,
which will connect the field to international oil markets by way of Colombia's
existing pipeline infrastructure. We have ordered the pipe and pumping units and
have commenced the acquisition of rights-of-way for the pipeline. The pipe and
pumping unit orders have been made in order to meet manufacturing and shipping
schedules consistent with our intention to complete pipeline construction by
mid-2001. We estimate that first pipeline production will occur in the summer of
2001.

    Sipetrol and Cimarrona collectively own 42.3% of the working interest under
the association contracts, but they have not decided whether to participate in
the pipeline. We could not agree with our association contract partners on a
comprehensive budget for the development of the Guaduas field, including
pipeline construction and a schedule for the drilling of additional development
wells. As a consequence, we have given Sipetrol and Cimarrona formal notice
under the operating agreement of our intention to proceed sole risk, even if
they do not participate. It is our position that Sipetrol and Cimarrona have now
forfeited their right to participate in the pipeline and are subject to the
penalty provision of our operating agreement which allows Seven Seas to retain
their share of production until we recoup our costs of construction of the
pipeline plus the applicable penalties. Sipetrol and Cimarrona dispute our
position. We are currently negotiating with Sipetrol and Cimarrona to resolve
the controversy. The matter may have to be resolved by arbitration under the
provisions of the operating agreement. In any event, Seven Seas is proceeding
with plans for the construction of the pipeline.

    We estimate that the pipeline (with a maximum throughput capacity of 40,000
Bbls/d) will cost $21 million, plus $3 million for flow lines and production
facilities to put the field on production at a rate of 10,000 Bbls/d. Additional
flow lines will be required to bring the pipeline to a production capacity of
25,000 Bbls/d. These additional facilities are estimated to cost $4 million.
During the 200% recoupment periods from Ecopetrol, our 57.7% share of monthly
revenue from the pipeline at 10,000 Bbls/d will be between $2.5 million and $3.3
million, net of transportation, quality adjustment sand lifting costs, based
upon West Texas Intermediate oil prices of $25 to $30 per barrel. We plan to pay
the initial cost of the pipeline and related equipment ($24 million) from
working capital on hand and secured borrowing.

    Together with our partners in the Guaduas field, we recently accepted an
offer from Ecopetrol to formally apply for an "on-top" contract that will
provide improved fiscal and contract terms for the subthrust Dindal prospect. An
"on-top" contract will effectively be an amendment to the Dindal association
contract, and should enable us to retain the entire acreage in the Dindal block
for the subthrust structure. The improvements to the fiscal and contract terms,
as proposed by Ecopetrol, would, upon Ecopetrol electing to participate in the
development of an oil discovery in the subthrust formations, increase the
associates' initial interest to 70%, as compared to an initial interest of 50%
under the current Dindal association contract. Furthermore, following the
production of certain volumes of oil, the associates' interest would gradually
reduce to 35% under the "on-top" contract terms, as opposed to 30% under the
current Dindal association contract. The final terms of the "on-top" contract
are subject to negotiations between the associates and Ecopetrol. Concurrent
with our application for an "on-top" contract, we also applied for an extension
of the exploration period under the Dindal association contract to avoid having
to relinquish a part of the Dindal association contract at this time. However,
Ecopetrol has not made a final decision, and the Company may be required to
relinquish some of the contract area once a final decision has been made.

    We plan to drill the subthrust exploration well in early 2001; however,
these plans are contingent upon (1) negotiations for the "on-top" contract with
Ecopetrol, and (2) our ability to secure financing to fund our share of the
well.

                                       13

<PAGE>   14
  Financing the Go Forward Strategy

    Our first priority will be to finance the pipeline. Preliminary discussions
with banks and other institutions lead us to believe we can borrow a substantial
amount of the cost of the pipeline necessary for the production at the rate of
10,000 Bbls/d, secured by our share of the property; however, we do not have any
legal commitments for such financing at this time. Furthermore,, we believe that
once the pipeline is built and is actually producing at the rate of 10,000
bbls/d, additional funds can be borrowed from the same or other lender(s) to
finance a significant portion of the field development costs necessary to bring
production up to 25,000 Bbls/d. At this time, we do not know what percent or how
much of our revenue will have to be dedicated to service the pipeline debt.

    Our next order of priority will be to finance the $6.9 million interest
payment that will be due November 15, 2001 on our $110 million senior notes. We
plan to arrange our pipeline financing, described above, in such a way that loan
proceeds and cash flow will be sufficient to meet this commitment.

    While we are currently re-drilling the El-Segundo 6-E pursuant to our
agreement with Ecopetrol, none of our capital plans, other than the pipeline,
drilling an exploratory well on the Rio Seco block, drilling the exploratory
well on the Rosablanca block, the Tapir work program, and the November 15, 2001
interest obligation, constitute legal commitments. The following table reflects
our currently planned capital expenditures through the year 2001.

<TABLE>
<CAPTION>
                                                 ESTIMATED COST
                                                 (IN THOUSANDS)
DESCRIPTION OF PROJECT\EXPENDITURE     GROSS        NET TO US                              STATUS
----------------------------------------------------------------  -------------------------------------------------
<S>                                       <C>          <C>       <C>
Redrill ES-6E well                        $  3,200      $ 1,760   The well is currently drilling
Pipeline and production facilities                                Pipe and compressors ordered; rights-of-way being
   @ 10,000 Bbls/d(1)                       24,000       13,848   acquired; financing is incomplete
Exploratory well - Rosablanca block(3)       1,000          750   Obligation
Exploratory well - Tres Paso 16W             5,500        3,025   Obligation
Tapir work program (2)                      11,094        2,129   Potential obligation
Senior Note Interest at 11/15/01             6,875        6,875   Due 11/15/01
                                       -------------------------
    Sub-Total                               51,669       28,387
Pipeline additions to 25,000 Bbls/d (1)      4,000        2,308   Discretionary expenditure subject to financing
8 development wells to bring
production to 25,000 Bbls/d (1)             32,000       18,464   Discretionary expenditure subject to financing
Subthrust exploration well (1)              18,400       10,120   Discretionary expenditure subject to financing
                                       -------------------------
   Total                                  $106,069      $59,279
</TABLE>

(1)  The cost and revenue sharing applicable to these projects are uncertain due
     to dispute with co-owners. We may elect to proceed sole risk on any one or
     more of these projects subject to financing.

(2)  In the event we are unable to assign our interest in the Tapir association
     contract, we will be obligated to participate in the work program.

(3)  Subject to the pending default resolution, we will be obligated to pay 100%
     of the costs.

     Due to the dispute with Sipetrol and Cimarrona, our share of these capital
projects is uncertain. Our financing objectives do not include paying for all
these projects on a sole risk basis by the end of the year 2001. However, we may
seek financing to pay our net share of all these items by the end of next year.
Possible sources of financing include:

     o  commercial bank borrowing;
     o  project financing the pipeline;
     o  industry joint ventures or similar arrangement with industry service and
        supplies companies;
     o  forward sales of oil; and
     o  debt and equity financing.

     All debt financing will be on a secured basis. Under the terms of our $110
     million senior notes, we are permitted to incur general indebtedness that
     can be senior to our senior notes not exceeding the greater of (i) $25
     million, or (ii) the sum of 100% of our cash and cash equivalents, plus
     100% of our receivable from Ecopetrol, and plus 30% of our discounted
     future net revenues from proved oil and gas reserves prepared in accordance
     with the rules of the United States Securities and Exchange Commission. The
     permitted amount was approximately $108.6 million at September 30, 2000. We
     are also authorized under the terms of the senior notes to borrow an
     additional $10 million for project financing, such as to pay the purchase
     price or construction costs of the pipeline and production facilities.
     Under these arrangements, we have plans to seek up to $45 million in new
     financing; however, there are no assurances that we will be successful.


                                       14
<PAGE>   15
LIQUIDITY AND CAPITAL RESOURCES

Working capital

     We had working capital, net of restricted investments and related interest
payable of $18.2 million, including unrestricted cash and short-term investments
of $15.2 million as of September 30, 2000. We plan to use our available cash as
set forth under "-- Financing the Go Forward Strategy."

Equity and financing activities

     As of November 10, 2000, we had 37,836,420 common shares, no par value,
outstanding, of which none are restricted. At September 30, 2000, we had
outstanding $110.0 million of 12 1/2% senior notes due May 15, 2005. In
accordance with the terms of the senior notes, we were required to hold in a
separate account or in escrow monies to provide for the first three years of
interest payable under the senior notes. We purchased $13.5 million in U.S.
government securities from the proceeds of the senior notes and deposited the
securities in a segregated account. The amount deposited into the segregated
account was enough to pay the first two interest payments. We also purchased and
pledged $25 million of U.S. government securities to ensure payment of the four
scheduled interest payments on the notes from November 15, 1999 through May 15,
2001. At September 30, 2000, after making four interest payments, we had $13.5
million in U.S. government securities remaining, which is sufficient to pay
interest on the senior notes through May 2001.

     Our activities from inception through June 30, 2000 were funded primarily
by the proceeds from private placements of our securities, including our common
shares, warrants and notes, resulting in aggregate cash proceeds of $157.0
million. Recent transactions include:

     o  Exchangeable Notes. In August 1997, we issued $25.0 million of 6%
        exchangeable notes in a private transaction with institutional and
        accredited investors. The exchangeable notes accrued interest at a rate
        of 6% per annum and were payable on December 31 and June 30 in each
        year. The exchangeable notes were scheduled to mature on August 7, 2003.

     o  Convertible Debentures. The exchangeable notes were exchanged for a like
        principal amount of 6% convertible debentures on August 5, 1998. The 6%
        convertible debentures were converted on August 6, 1998 into units
        consisting of 2,173,901 common shares and warrants exercisable for
        1,086,957 common shares.

     o  Purchase Warrants. On February 5, 1999, purchase warrants for $1.1
        million of our common shares expired without exercise. We received
        proceeds of $0.3 million from the exercise of 18,913 warrants. These
        purchase warrants had been issued in association with the exchange and
        conversion of our previously outstanding $25.0 million issue of 6%
        exchangeable notes.

     o  Senior Notes. In May 1998, we completed the offering of $110 million of
        12 1/2% senior notes due May 15, 2005 and received net proceeds of
        approximately $106 million. Approximately $37.8 million of the proceeds
        was held in a separate account or in escrow to provide for the first
        three years of interest payable under the senior notes. Interest on the
        senior notes is payable semi-annually on May 15 and November 15 of each
        year. The escrow account is sufficient to pay interest through May 2001.
        The senior notes mature on May 15, 2005. The senior notes are redeemable
        at our option, in whole or in part, at any time on or after May 15,
        2002, at the prescribed redemption price, plus accrued and unpaid
        interest, liquidated damages and additional amounts, if any, to the date
        of redemption.

         At any time prior to May 15, 2001, we may redeem up to 33 1/3% of the
original aggregate principal amount of the senior notes at a redemption price of
112.50% of the principal amount redeemed with a portion of the net proceeds of
an equity or strategic investor offering, provided that at least 66 2/3% of the
original aggregate principal amount of the senior notes remains outstanding
immediately after the redemption. In the event of certain changes affecting
withholding taxes applicable to certain payments on the senior notes, the senior
notes may be redeemed at our option, in whole but not in part, at any time at a
redemption price equal to 100% of the principal amount thereof plus accrued and
unpaid interest, liquidated damages and additional amounts, if any, to the
redemption date. Upon the occurrence of a change of control:


                                       15
<PAGE>   16

               (1) unless we redeem the senior notes as provided in (2) below,
               we will be required to offer to purchase the senior notes at a
               purchase price equal to 101% of the aggregate principal amount
               thereof, plus accrued and unpaid interest, liquidated damages and
               additional amounts, if any, to the date of purchase; and

               (2) we will have the option, at any time prior to May 15, 2002,
               to redeem the senior notes, in whole but not in part, at a
               redemption price equal to 100% of the principal amount thereof
               plus the applicable premium and accrued and unpaid interest,
               liquidated damages and additional amounts, if any, to the date of
               redemption.

     The senior notes are senior obligations of Seven Seas and are ranked
equally in right and priority of payment with all of our existing and future
senior indebtedness.

     If our cash flow from operations is not sufficient to pay principal and
interest on our debt when due, we would have to attempt to restructure or
refinance the debt or sell assets to obtain funds.

Capital spending

     From inception through September 30, 2000, we had cash expenditures for the
exploration of oil and gas properties of $111.2 million.

   Commitments

     Our non-discretionary capital commitments at September 30, 2000 are
approximately $3.2 million, of which $2.0 million will be used to re-drill and
test the El Segundo 6-E on the Guaduas field and $1.0 million to drill an
exploratory well on the Rosablanca block. In the event that we are unable to
assign our interest in the Tapir association contract, we will be responsible
for our proportionate share of the costs of the sixth year work program,
estimated to be $2.129 million.

   Planned capital expenditures

     Our first priority will be to finance the pipeline. We estimate that the
pipeline (with a maximum throughput capacity of 40,000 Bbls/d) will cost $21.0
million, plus $3.0 million for flow lines and production facilities to put the
filed on production at a rate of 10,000 Bbls/d. Due to the dispute with Sipetrol
and Cimarrona, our share of these capital costs is uncertain. See "- Financing
the Go Forward Strategy."

   Debt service costs

     Under the terms of our 12 1/2% Senior Notes, we have to pay semi-annual
interest payments of $6.9 million on May 15 and November 15. The $110 million in
principal is due May 15, 2005.

ACCOUNTING POLICIES AND DEVELOPMENT STAGE ACCOUNTING

     The consolidated financial statements and notes thereto included in this
document have been prepared in accordance with generally accepted accounting
principles in the United States. The unaudited, condensed, consolidated
financial statements included herein have been prepared by Seven Seas pursuant
to the rules and regulations of the Securities and Exchange Commission,
accordingly, they do not include all of the information and footnotes required
by generally accepted accounting principles for complete financial statements.

    Our exploration and development activities have not generated a substantial
amount of revenue, thus requiring the financial statements to be presented as a
development stage enterprise. Accumulated losses are presented on the balance
sheet as "Deficit accumulated during development stage." The income statement
presents revenues and expenses for each period presented and also a cumulative
total of both amounts from our inception. Period-to-period comparisons of such
results and certain financial data may not be meaningful or indicative of future
results. In this regard, future results of Seven Seas will be highly dependent
upon the success of our Guaduas field operations. The statement of cash flows
shows inflows and outflows for each period presented and from our inception. In
addition, the Notes to Consolidated Financial Statements are required to
identify the enterprise as development stage.


                                       16
<PAGE>   17

    We follow the full-cost method of accounting for oil and natural gas
properties. Under this method, all costs incurred in the acquisition,
exploration and development of oil and gas properties, including unproductive
wells, are capitalized in separate cost centers for each country. Such
capitalized costs include contract and concession acquisition, geological,
geophysical and other exploration work, drilling, completing and equipping oil
and gas wells, constructing production facilities and pipelines, and other
related costs. No general and administrative costs were capitalized during 2000,
1999, and 1998. We capitalized interest of $10.3 million and $10.3 million for
the nine months ended September 30, 2000 and 1999, respectively.

    The capitalized costs of oil and gas properties in each cost center are
amortized on the composite units of production method based on future gross
revenues from proved reserves. Sales or other dispositions of oil and gas
properties are normally accounted for as adjustments of capitalized costs. Gain
or loss is not recognized in income unless a significant portion of a cost
center's reserves is involved. Capitalized costs associated with the acquisition
and evaluation of unproved properties are excluded from amortization until it is
determined whether proved reserves can be assigned to such properties or until
the value of the properties is impaired. If the net capitalized costs of oil and
gas properties in a cost center exceed an amount equal to the sum of the present
value of estimated future net revenues from proved oil and gas reserves in the
cost center and the lower of cost or fair value of properties not being
amortized, both adjusted for income tax effects, such excess is charged to
expense.

RESULTS OF DEVELOPMENT STAGE OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999

    Revenues from oil sales were $1.9 million and $0.1 million for the quarters
ended September 30, 2000 and 1999, respectively. Lease operating expenses were
$0.3 million and $0.2 million for the quarters ended September 30, 2000 and
1999, respectively. The revenue and costs for the quarter ended September 30,
2000 related to the testing of the El Segundo 1-S, Tres Pasos 1-E, and El
Segundo 2-E wells. The revenue and costs for the quarter ended September 30,
1999 related to the testing of the El Segundo 1-S well.

    Oil production in Colombia of 81,114 barrels and 11,029 barrels for the
quarters ended September 30, 2000 and 1999, respectively, pertaining solely to
our share of oil produced from production testing, was sold to Refinerie del
Nare at an average price of $24.91 and $11.77 per barrel in 2000 and 1999,
respectively.

    Interest income was $0.4 million and $0.7 million for the quarters ended
September 30, 2000 and 1999, respectively. The decrease from 1999 to 2000 was
the consequence of lower cash and investment balances resulting from the use of
funds from the issuance of the senior notes in May 1998.

    General and administrative costs were $1.7 million and $1.6 million for the
quarters ended September 30, 2000 and 1999, respectively.

    Depletion, depreciation and amortization were $0.6 million and $0.3 million
for the quarters ended September 30, 2000 and 1999, respectively. The quarter
ended September 30, 2000 includes $0.3 million in depletion. The Company began
recognizing depletion during the fourth quarter of 1999.

    As required under the full cost method of accounting, capitalized costs are
limited to the sum of (1) the present value of future net revenues, using
current unescalated pricing and discounted at 10% per annum from proved reserves
and (2) the lower of cost or estimated fair value of unevaluated properties, all
net of expected income tax effects. There was no write-down in 2000 or 1999.

    Seven Seas incurred net losses of $0.2 million and $1.3 million for the
quarters ended September 30, 2000 and 1999, respectively.

NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999

    Revenues from oil sales were $2.0 million and $0.3 million for the nine
months ended September 30, 2000 and 1999, respectively. Oil and gas operating
expenses were $1.2 million and $1.7 million for the nine months ended September
30, 2000 and 1999, respectively. The 2000 costs relate to the long term testing
program, primarily the El Segundo 4-E well, various pressure testing and
geologic studies of the reservoir, and the testing of the El Segundo 1-S, Tres
Pasos 1-E, and El Segundo 2-E wells. The 1999 costs related to the long-term
production testing of the Tres Pasos 1-W horizontal and the El Segundo 1-S
wells.


                                       17
<PAGE>   18
    Oil production in Colombia (net to the Company, including minority interest
through June 30, 1999) of 82,299 barrels and 36,599 for the nine months ended
September 30, 2000 and 1999, respectively, pertaining solely to the Company's
share of oil produced from production testing, was sold to Refinerie del Nare at
an average price of $24.75 per barrel in 2000 and $9.12 per barrel in 1999.

    Interest income was $1.4 million and $2.4 million for the nine months ended
September 30, 2000 and 1999, respectively. The decrease from 1999 to 2000 was
the consequence of lower cash and investment balances resulting from the use of
funds from the issuance of the senior notes in May 1998.

General and administrative costs were $5.4 million and $6.2 million for the nine
months ended September 30, 2000 and 1999, respectively. The $0.8 million
decrease in general and administrative expenses from the nine month period ended
September 30, 1999 to the nine month period ended September 30, 2000 was
primarily attributable to a $0.9 million decrease in personnel costs, including
salaries, benefits, travel, rents, insurance, and security due to decreased
personnel in both US and Colombia and a $0.7 million decrease in contractors,
security, and legal costs resulting from a reduction in oil and gas operations
in Colombia. These cost reductions were offset by $0.8 million in severance
payments made during the first quarter of 2000 in conjunction with the Company's
cost reduction program. The Company's cost reduction plan was aimed at
determining the proper number of people to handle the level of oil and gas
operations at this time. Accordingly, although this "right-sizing" plan was
implemented, the Company has no intentions of reducing the oil and gas
operations of the Company. The Company began this cost reduction in May 1999,
when 17 Colombian nationals, primarily administrative in nature, were released
at a cost of $0.2 million in severance payments. Subsequently, during the first
quarter of 2000, an additional 17 employees and 29 contractors were identified
for separation from the Company. As of September 30, 2000, all of the people had
been released. The reduction plan resulted in $0.8 million in severance expense
during the first quarter of 2000. The Company expects to recognize $0.5 million
in savings, after severance costs, from the reduced personnel during 2000. No
additional reductions are planned. In addition, severance costs relating to the
reduction in personnel were approximately $0.4 million during the second quarter
of 1999.

    Depletion, depreciation and amortization were $1.1 million and $0.8 million
for the nine months ended September 30, 2000 and 1999, respectively. The
nine-months ended September 30, 2000 includes $0.3 million in depletion. The
Company began recognizing depletion during the fourth quarter of 1999.

    As required under the full cost method of accounting, capitalized costs are
limited to the sum of the present value of future net revenues using current
unescalated pricing discounted at 10% related to estimated production of proved
reserves and the lower of cost or estimated fair value of unevaluated
properties, all net of expected income tax effects. No writedown was required
during the nine months ended September 30, 2000 and 1999, respectively.

    The Company incurred net losses of $4.6 million and $6.2 million for the
nine months ended September 30, 2000 and 1999, respectively.

TAXES

    Our net income, as defined under Colombian law, from Colombian sources, is
subject to Colombian corporate income tax at a rate of 35%. An additional
remittance tax is imposed upon remittance of profits abroad at a rate of 7%.

    The Company is also subject to income taxes in Canada and the United States,
where the statutory rates were 45% and 35% respectively.



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<PAGE>   19
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

    We are exposed to market risk, including adverse changes in commodity
prices, interest rates and foreign currency exchange rates as discussed below.

COMMODITY RISK

    We have faced minimal risk from commodity pricing because of the small
amounts of oil and gas produced to date. Realized commodity prices received for
such production are primarily driven by the prevailing worldwide price for crude
oil and spot prices applicable to natural gas. The effects of such pricing are
expected to be minor until such time as we produce commercial quantities of oil
and gas.

INTEREST RATE RISK

    We consider our interest rate risk exposure to be minimal as a result of a
fixed interest rate on the $110 million 12 1/2% Senior Notes. We currently have
no open interest rate swap agreements.

FOREIGN CURRENCY EXCHANGE RATE RISK

    We conduct business in several foreign currencies and are subject to foreign
currency exchange rate risk on cash flows related to sales, expenses and capital
expenditures. However, because predominately all transactions in our existing
foreign operations are denominated in U.S. dollars, the U.S. dollar is the
functional currency for all operations. Exposure from transactions in currencies
other than the U.S. dollars is not material.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

FORMER MANAGEMENT

   The Company and two of its officers and directors, Robert A. Hefner, III, and
Larry Ray, and one of its former directors, Breene M. Kerr, have been sued by
four former officers and directors of the Company in DeCort, et al. v. Seven
Seas Petroleum, Inc., et al., Cause No. 2000-50498, District Court of Harris
County, Texas, 133rd Judicial District. Plaintiffs allege that the Company
failed to obtain extensions of time in which plaintiffs could exercise certain
stock options granted to them, and that all defendants induced them to enter
into separation agreements with the Company that they would not have entered
into but for the Company's agreement to obtain an extension of the time for
plaintiffs to exercise their stock options. The case was filed October 2, 2000,
and the Company has not yet responded to plaintiff's allegations. The Company
intends to vigorously defend the case.

Item 6. Exhibits and Reports on 8-K

    (a) Exhibits

      3 -- Articles of Incorporation and By-laws

    *(A)-- The Amalgamation Agreement effective June 29, 1995 by and between
           Seven Seas Petroleum Inc., a British Columbia corporation; and Rusty
           Lake Resources Ltd.

    *(B)-- Certificate of Continuance and Articles of Continuance into the Yukon
           Territory

    *(C)-- By-Laws

     27 -- Financial Data Schedule

*    Incorporated herein by reference to like exhibit in Registration on Form 10
     (File No. 022483).

    (b) Reports on From 8-K

    None

    SIGNATURES

    Seven Seas Petroleum Inc.

Date: November 14, 2000                By:  Larry A. Ray, Executive
                                            Vice President, Chief Operating
                                            Officer, Chief Financial Officer,
                                            and Corporate Secretary
                                            Robert A. Hefner III, Chairman of
                                            the Board



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                                INDEX TO EXHIBITS


<TABLE>
    EXHIBIT NO.              DESCRIPTION
    -----------              -----------
<S>                          <C>
        27                   Financial Data Schedule
</TABLE>