<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, 1999
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 of (I.R.S. Employer
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 OCTOBER 31, 1999 THERE WERE 37,833,420 SHARES OF THE REGISTRANT'S COMMON
SHARES, NO PAR VALUE PER SHARE, OUTSTANDING.
<PAGE> 2
INDEX
PART I. FINANCIAL INFORMATION
(DEVELOPMENT STAGE ENTERPRISE)
Item 1. Condensed Consolidated Balance Sheets as of
September 30, 1999 (Unaudited) and
December 31, 1998 ...................................... 2
Condensed Statements of Consolidated Operations and
Accumulated Deficit for the nine months and three
months ended September 30, 1999 and 1998 and the
Cumulative Total from Inception (February 3, 1995) to
September 30, 1999 (Unaudited) ......................... 3
Condensed Statements of Consolidated Cash Flows for
the nine months ended September 30, 1999 and 1998 and
the Cumulative Total from Inception (February 3, 1995)
to September 30, 1999 (Unaudited) ...................... 4
Notes to Condensed Consolidated Financial
Statements (Unaudited) ................................. 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations .................... 8
Item 3. Quantitative and Qualitative Disclosures about
Market Risk ............................................ 15
PART II. OTHER INFORMATION ................................................. 15
Item 6. Exhibits and Reports on Form 8-K ....................... 15
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SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
ASSETS (UNAUDITED)
<S> <C> <C>
CURRENT
Cash and cash equivalents $ 15,349 $ 38,147
Short-term investments 8,818 6,399
Restricted short-term investments 13,484 13,244
Accounts receivable 5,827 6,562
Interest receivable 90 532
Inventory 1,085 1,316
Prepaids and other 53 225
--------- ---------
44,706 66,425
Notes receivable from employees 436 200
Restricted long-term investments 12,785 18,658
Land 1,065 1,257
Evaluated oil and gas interests, full-cost method 82,018 74,993
Unevaluated oil and gas interests, full-cost method 113,267 113,116
Fixed assets, net of accumulated depreciation of $565 at
September 30, 1999 and $232 at December 31, 1998 1,141 1,357
Other assets, net of accumulated amortization of $916 at
September 30, 1999 and $461 at December 31, 1998 3,439 3,894
--------- ---------
TOTAL ASSETS $ 258,857 $ 279,900
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT
Accounts payable $ 1,670 $ 10,058
Interest payable 5,156 1,719
Other accrued liabilities 107 580
--------- ---------
6,933 12,357
Long-term debt 110,000 110,000
Deferred income taxes 24,732 24,732
Minority interest -- 9,713
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Share capital -
Authorized unlimited common shares without par value and
37,833,420 and 37,778,420 issued and outstanding common shares at
September 30, 1999 and December 31, 1998, respectively 225,805 222,447
Authorized unlimited Class A preferred shares without par value --
Warrants - none and 1,068,044 outstanding at September 30, 1999 -- 3,093
and December 31, 1998, respectively
Deficit accumulated during development stage (108,613) (102,442)
Treasury stock, 29 shares held at September 30, 1999 and
December 31, 1998 -- --
--------- ---------
Total Stockholders' Equity 117,192 123,098
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 258,857 $ 279,900
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
2
<PAGE> 4
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)
STATEMENTS OF 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,
---------------------------- ---------------------------- -------------
1999 1998 1999 1998 1999
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUE
Crude oil sales $ 308 $ 91 $ 123 $ -- $ 1,337
Interest income 2,403 2,574 705 1,431 7,465
------------ ------------ ------------ ------------ ------------
2,711 2,665 828 1,431 8,802
EXPENSES
General and administrative 6,234 5,761 1,610 3,442 28,235
Oil and gas operating expenses 1,662 804 151 46 3,764
Depreciation and amortization 806 446 292 219 1,777
Writedown of proved oil & gas properties -- -- -- -- 129,789
Loss (Gain) on sale of exploration properties 670 (577) -- (577) 124
Dry hole and abandonment costs -- -- -- -- 1,145
Geological and geophysical -- -- -- -- 47
Other (income) expense 73 (32) 51 (2) (49)
------------ ------------ ------------ ------------ ------------
9,445 6,402 2,104 3,128 164,832
NET LOSS BEFORE INCOME TAXES
AND MINORITY INTEREST (6,734) (3,737) (1,276) (1,697) (156,030)
------------ ------------ ------------ ------------ ------------
INCOME TAX EXPENSE 30 102 10 72 (45,688)
NET LOSS BEFORE MINORITY INTEREST (6,764) (3,839) (1,286) (1,769) (110,342)
------------ ------------ ------------ ------------ ------------
MINORITY INTEREST 593 370 -- 167 1,729
------------ ------------ ------------ ------------ ------------
NET LOSS $ (6,171) $ (3,469) $ (1,286) $ (1,602) $ (108,613)
============ ============ ============ ============ ============
DEFICIT ACCUMULATED DURING THE DEVELOPMENT
STAGE, BEGINNING OF PERIOD (102,442) (12,243) (103,546) (14,110) --
DEFICIT ACCUMULATED DURING THE DEVELOPMENT
STAGE, END OF PERIOD $ (108,613) $ (15,712) $ (104,832) $ (15,712) $ (108,613)
============ ============ ============ ============ ============
BASIC AND DILUTED NET LOSS PER COMMON SHARE $ (0.16) $ (0.10) $ (0.03) $ (0.04) $ (4.27)
============ ============ ============ ============ ============
WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 37,806,072 35,706,779 37,883,420 36,724,401 25,408,553
============ ============ ============ ============ ============
</TABLE>
3
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SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited; In thousands)
<TABLE>
<CAPTION>
CUMULATIVE
TOTAL FROM
INCEPTION
(FEBRUARY 3,
1995) TO
NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30,
1999 1998 1999
-------------- ------------- -------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net loss $ (6,171) $ (3,469) $(108,603)
Add (subtract) items not requiring (providing) cash:
Compensation expense -- -- 2,140
Minority interest (593) (370) (1,729)
Common stock contribution to 401(k) retirement plan -- -- 79
Depreciation and amortization 806 449 1,782
Writedown of proved oil & gas properties -- -- 129,789
Loss on sale of exploration property 670 (577) 124
Dry hole and abandonment costs -- -- 1,140
Gain on sale of marketable securities -- (6) (6)
Deferred income taxes benefit -- -- (45,727)
Amortization of investments (1,048) -- (1,048)
Changes in working capital excluding changes to cash and cash
equivalents:
Accounts receivable 2,115 867 (3,565)
Interest receivable 442 (495) (90)
Inventory 27 -- (1,289)
Prepaids and other, net 172 53 (53)
Accounts payable (13,587) (5,299) (7,877)
Other accrued liabilities (223) 339 346
-------- -------- ---------
Cash Flow Used in Operating Activities (17,390) (8,508) (34,587)
-------- -------- ---------
INVESTING ACTIVITIES
Exploration of oil and gas properties (10,353) (24,324) (82,698)
Purchase of land (1) (1,591) (1,258)
Purchase of investments (8,818) (56,069) (47,119)
Proceeds from acquisition -- -- 630
Payment to withdraw from property (250) 1,163 997
Proceeds from sale of marketable securities -- 50 50
Proceeds from sale of investments 13,080 -- 13,080
Notes receivable from employees (236) -- (436)
Other asset additions (216) (1,150) (1,972)
-------- -------- ---------
Cash Flow Used in Investing Activities 6,794 (81,921) (118,726)
-------- -------- ---------
FINANCING ACTIVITIES
Proceeds from special warrants issued -- 284 12,393
Proceeds from share capital issued -- 2,619 15,466
Proceeds from additional paid-in capital contributed -- -- 1
Proceeds from issuance of long-term debt -- 110,000 135,000
Costs of issuing long-term debt -- (4,248) (5,821)
Contributions by minority interest 1,386 5,416 11,623
-------- -------- ---------
Cash Flow Provided by Financing Activities 1,386 114,071 168,662
-------- -------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (22,798) 23,642 15,349
Cash and cash equivalents, beginning of period 38,147 18,067 --
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 15,349 $ 41,709 $ 15,349
======== ======== =========
</TABLE>
Supplemental disclosures of cash flow information:
The Company incurred interest costs of $10.3 million and $7.0 million for
the nine month periods ended September 30, 1999 and 1998, respectively. Such
amounts were capitalized during the respective periods.
Cash paid for interest for the nine month periods ended September 30, 1999
and 1998 was $6.9 million, $0.9 million, respectively.
The Company paid zero and $30,000 for estimated income taxes during the nine
month periods ended September 30, 1999 and 1998, respectively. The accompanying
notes are an integral part of these financial statements.
4
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SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. DEVELOPMENT STAGE OPERATIONS
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, primarily 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. Since inception through
September 30, 1999, the Company incurred cumulative losses of $108.6 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.
As of September 30, 1999, the Company has spent $242.2 million to acquire
and $71.6 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, 1999, the Guaduas Field had produced a cumulative
volume of approximately 435,000 barrels of oil during various testing
procedures. Except for additional production testing for further reservoir
evaluation and the production planned to be trucked, continuous production of
the Guaduas Field will not commence prior to installation of the necessary
infrastructure.
In September 1999, we signed an agreement with Ecopetrol agreeing to a
schedule for further long term production tests, the drilling of an additional
well, and other important issues leading to commercial production from the
Guaduas field. The Company anticipates exploring the west side of the Guaduas
Field structure and a deeper subthrust structure below the Guaduas field
discovery through the drilling and re-drilling of three additional wells and
continue to further delineate and develop the Guaduas Field in increments
designed to optimize cash flows that can be reinvested into further delineation
and development of the field. These planned increments, starting with an
approximate 5,000 Bbls/d portable trucking facility (expected to be in operation
in early-2000) followed by an approximate 25,000 Bbls/d pipeline facility
(expected to be operational by early-2001) and culminating with an approximate
250,000 Bbls/d pipeline facility (expected to be in operation in early-2005)
would be phased in as capital is available to fund the necessary delineation and
development drilling, production facility and transportation facility
expenditures.
These plans are dependent upon the timing of a global operating license
allowing development in the Association Contract areas; environmental and
rights-of-way permits for production and transportation facilities; cost and
timeliness of construction activities; availability of transportation on third
party pipeline systems; and the timing of a commerciality agreement with
Ecopetrol. Approval of commerciality by Ecopetrol is a critical part of the
Company's strategy as Ecopetrol will bear fifty percent of all costs for
development and production subsequent to the date commerciality is declared.
Although the Company has reason to believe that a commerciality agreement can be
reached with Ecopetrol, if the commerciality agreement is not in place before
April 1, 2000 the Company may not be able to proceed as planned.
As of September 30, 1999, the Company had unrestricted cash resources,
including short-term investments, of $24.2 million and commitments under
existing oil and gas agreements of $3.8 million in 1999. Based on available
capital resources, the Company believes that it will be able to make its
commitments and fund its exploration plan through 1999. To the extent the
Company experiences delays or cost overruns in the exploration plan, the Company
will be required to seek additional financing to meet its commitments and to
carry out its exploration and development plan through 2000. The continued
exploration and development of the Company's current properties is expected to
require substantial amounts of 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 unsuccessful 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.
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'
5
<PAGE> 7
prospects are uncertaities 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.
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 Securities and Exchange Commission and in
accordance with generally accepted accounting principles (GAAP) for interim
financial reporting. Accordingly, they do not include all of the information and
footnotes required by GAAP 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 10K for the year ended December 31, 1998.
Certain minor reclassifications have been made in prior years to conform to
current reporting practices.
3. OPERATIONS BY GEOGRAPHIC AREA:
The Company has one operating and reporting segment. Information about the
Company's operations for the nine months ended September 30, 1999 and 1998 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, 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
Nine months ended September 30, 1998
Revenues.............................. $ 2,481 $ 9 $ 175 $ -- $ 2,665
Operating Income (Loss)............... 1,861 (3,729) (2,432) 563 (3,737)
Capital Expenditures.................. -- 937 27,415 54 28,406
Identifiable Assets................... 106,152 1,384 299,257 469 407,262
Depreciation and Amortization......... 334 80 32 -- 446
</TABLE>
4. NOTES RECEIVABLE FROM EMPLOYEES
In April 1999, the Company loaned funds totaling $0.2 million to several
non-executive employees for the purpose of purchasing the Company's common
shares. These notes bear a 4.99% interest rate and are due 36 to 44 months from
origination. The Company recognized interest income of $4,000 for the nine
months ended September 30, 1999.
5. MINORITY INTEREST
In June 1999, Seven Seas Petroleum Inc. ("SSPI") completed the
reorganization of certain of its subsidiaries, three of which owned working
interests in the Dindal and Rio Seco Association Contracts, through a series of
tax-free transactions. Prior to these transactions, Seven Seas Petroleum
Holdings Inc (SSPH), a wholly owned subsidiary of SSPI, owned 100% of the stock
of Seven Seas Petroleum Colombia Inc. ("SSPC") and 50% of Esmeralda L.L.C. SSPC
owned the remaining 50% of Esmeralda L.L.C. and 62.963% of Cimarrona L.L.C with
MTV Investments Ltd. ("MTV"), the minority interest owner in Cimarrona L.L.C.,
owning the remaining 37.037%. In the reorganization transactions, SSPH first
assigned its membership interest in Esmeralda L.L.C. to SSPC as a capital
contribution, giving SSPC 100% ownership of Esmeralda L.L.C. Next, Esmeralda
L.L.C. was merged into Cimarrona L.L.C. SSPH continued to own 100% of the stock
of SSPC. Cimarrona L.L.C. and its members, MTV and SSPC, entered into an
agreement whereby the assets, obligations, and liabilities of Cimarrona L.L.C.
which were proportionately attributable to SSPC (through the
6
<PAGE> 8
Company's interests in Esmeralda L.L.C. and Cimarrona L.L.C.) were merged into
SSPC in exchange for SSPC's interest in Cimarrona L.L.C. As a result, MTV became
the sole member of Cimarrona L.L.C. and accordingly, Cimarrona L.L.C. is no
longer a consolidated subsidiary of the Company. MTV maintained its
proportionate interest in the Dindal and Rio Seco Association Contracts as a
working interest owner and Seven Seas' net interest in the Association Contracts
was not changed.
6. CONTINGENCIES
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.
Colombian forest reserve
Inderena, the predecessor to the current Ministry of Environment,
declared a forest reserve in the 1980's in an area that includes a portion of
the Dindal and Rio Seco Association Contracts. The existence of this reserve may
make obtaining permits for drilling wells and building facilities more
difficult, but does not preclude oil and gas activity. In fact, we were granted
an envirionmental permit and drilled the Escuela 1 well on this area in 1993.
More recently, the Guaduas municipality has, independently of the Ministry of
Environment, declared a forest reserve in the same area. This latest reserve
proclamation would prohibit drilling. Colombian counsel has advised us that the
right to declare forest reserves is the exclusive right of the Ministry of
Environment. We intend to discuss this matter with representatives of the
municipal council and the mayor. In the event we do not obtain satisfactory
results, we have also engaged Colombian counsel to proceed before an appropriate
tribunal to have the municipal declaration ruled invalid. We are advised that
the resolution could take from 12 to 18 months. We will also seek an order from
the tribunal suspending the municipal declaration until final resolution. We are
advised that this process would take four to six months. The earliest we would
otherwise intend to drill in this area would be June 2000.
The forest reserve includes approximately 6,250 acres of our 109,000
total acreage under the Rio Seco and Dindal association contracts. The forest
reserve should not preclude us from recovering our proved oil and gas reserves.
There is a surface location for the deeper subthrust structure well that can
be drilled outside the forest reserve. Further, the existence of the forest
reserve will not impede our development of the shallow Cimarrona reservoir
of the Guaduas field.
Environmental penalties
On June 8 1998 the Ministry of Environment required our subsidiary, GHK
Company Colombia, to perform some remedial works on the El Segundo 6-E location
and access road. GHK Company Colombia performed the works, and thereafter
reported to the Ministry of Environment that all the works had duly been
completed. In various site visits, ministry officials have confirmed that
the alleged violations have been properly remedied. On July 8th 1999 GHK Company
Colombia filed all the documentation which confirmed total compliance to the
requirements. Although we cannot be certain, we do not expect any fines or
penalties to be imposed in connection with the alleged El Segundo 6-E
environmental violations.
On August 30, 1999, the Ministry of Environment issued a resolution
against our subsidiary, GHK Company Colombia, declaring it in violation of a
1997 decree in connection with the construction of the El Segundo 7-E well. The
resolution imposed a fine of approximately $215,000. We have filed an appeal for
a reversal of the resolution, including 379 pages of documentary evidence
supporting our position. We believe that we have corrected the environmental
violations claimed by the Ministry of Environment and that the fine may be
reduced or eliminated. However, the appeal process can take up to two years. The
El Segundo No. 7 well has been restored and we do not currently have any
drilling activities planned at this location.
Contract area
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,
required commencing at the end of the sixth year of the Association Contract.
The exploration period under the Dindal Association Contract will be extended to
September 23, 2000, provided the Associates commit to an additional $2.0 million
of exploration work. In September 2000, we must relinquish 50% of the contract
area or all lands that fall outside a five kilometer buffer zone around the area
designated to be the commercial field or negotiate another one year extension by
committing to additional exploration work, if applicable.
7
<PAGE> 9
Surface location
A lawsuit has been filed by the landowners for the El Segundo 1 surface
location to cancel our surface lease. Our Colombian legal counsel has advised us
that, on the basis of the claims asserted, we should win the lawsuit. We plan to
rigorously defend this claim.
7. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. ("SFAS") 133, Accounting for Derivative
Instruments and Hedging Activities (the "Statement"). The Statement 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.
SFAS 133, as amended by SFAS 137, is effective for fiscal years beginning
after January 1, 2001. A company may also implement the Statement as of the
beginning of any fiscal quarter after issuance. Statement No. 133 cannot be
applied retroactively. Statement No. 133 must be applied to (a) derivative
instruments and (b) certain derivative instruments embedded in hybrid contracts
that were issued, acquired, or substantively modified after December 31, 1998
and, at the company's election, before January 1, 1999. Statement No. 133 will
not currently impact the Company's disclosure or reporting.
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,
1998.
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.
8
<PAGE> 10
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, 1998, Ryder Scott Company Petroleum Engineers
estimated total proved recoverable reserves for the Guaduas field of 163,303,000
barrels of oil, of which 38,719,235 barrels of oil were attributable to our
interest.
We had working capital, net of restricted investments, of $24.3 million, and
unrestricted cash resources, including short-term investments, of $24.2 million
as of September 30, 1999. Our non-discretionary capital commitments for the
remainder of 1999, as of September 30, 1999, are approximately $3.8 million.
In September 1999, we signed an agreement with Ecopetrol agreeing to a
schedule for further long term production tests, the drilling of an additional
well, and other important issues leading to commercial production from the
Guaduas field. The principal points of the agreement with Ecopetrol include:
O The Associates agree to continue extensive production tests on four
wells and drill the El Segundo 4 well, an up-structure well to test a
possible gas cap for the field. The production test and El Segundo 4
should be completed near year-end 1999 and we estimate total costs to
drill and complete the well will be approximately $6.2 million gross
($3.4 million net).
O Subsequent to this production testing and the completion of the El
Segundo 4 well, we will make a formal application to Ecoeptrol for the
commercial development of the Guaduas field.
O Within 90 days from filing the commercial development plan, Ecopetrol
is required to advise us if it will participate and begin paying its
50% share of future development costs or will allow the Associates to
proceed with the development of the Guaduas field on a sole risk basis,
which would enable the Associates to recoup 200% of their future
development costs before Ecopetrol receives its share of production.
O Ecopetrol agreed to dedicate both the 20% royalty share and its share
of oil from the Guaduas field to a proposed pipeline. If Ecopetrol does
not participate in the pipeline, it will agree to a tariff for the
transportation of its oil on or before the final decision concerning
Commericality.
O The six year exploration period under the Dindal Association Contract
will be extended until Ecopetrol responds to the Commericalty request
and, at the Associate's option, can be further extended to September
23, 2000, provided the Associates expend an additional $2.0 million of
exploration work.
O The period for relinquishment of land will also be extended until the
last to occur of 1) the Commericaity decision by Ecopetrol or 2)
September 23, 2000, by the $2.0 million additional work commitment.
Due to the time required for concluding the agreement with Ecopetrol, the
changing conditions of the oil and gas industry and the possibility of obtaining
the new contract terms disclosed by Ecopetrol for new exploration on existing
contracts, our priorities have changed. Assuming timely payment by our
co-participants of their share of costs, we intend to use our available capital
to:
O Drill the Tres Pasos No. 16 well, an exploration well on the west side
of the Guaduas field structure. We expect this well to be completed by
mid year 2000, and we estimate total costs to drill and complete the
well will be approximately $6.7 million gross ($3.7 million net).
O Drill a deeper subthrust structure exploratory well below the Guaduas
field to test the repeated Hoyon (Tertiary) formation and the repeated
Cimarrona (Cretaceous) formation. If we get the new contract terms
timely, we expect this well to be completed by the end of the first
quarter of 2001. We estimate the total cost will be approximately $25.5
million gross ($12.5 million net).
O Reenter and redrill and test the El Segundo 6-E or El Segundo 3-E. We
expect this re-entry to be completed by mid- 2000, and estimate total
cost for this well will be approximately $2.5 million gross ($1.4
million net).
We plan to use our available cash and cash from production tests to
complete the foregoing.
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<PAGE> 11
If additional funds become available from borrowings or otherwise, we would
next drill exploration wells on the multiple prospects within the Rosablanca and
Montecristo blocks, which we operate.
Subject to obtaining adequate additional funding, our next priority is to
continue to delineate and develop our principal property in the Guaduas field.
The Company plans to focus its resources on placing the Guaduas field on
production by increments in order to achieve cash flow as soon as possible.
First production from the Guaduas field, Increment I, should be achieved through
the construction of a Portable Trucking Facility ("PTF" -- subsequently to
become part of the permanent facilities) for the trucking of between 4,000
Bbls/d and 6,000 Bbls/d to a local refinery located approximately 80 miles from
the Guaduas field. The estimated net capital cost to the Company for these
facilities is approximately $1.0 million. The Company estimates that it can
commence PTF production in early 2000. Increment II, Early Pipeline Production,
includes the construction of facilities for the production of 20,000 Bbls/d to
30,000 Bbls/d and is scheduled to go on line in early-2001. Increment II
facilities will include the construction of a 36-mile pipeline that will connect
with the existing regional OAM pipeline. Contemporaneously, the Company will
drill additional development wells and one gas injection well. The Company
estimates that the net capital cost of the pipeline, the production facilities
and drilling the necessary wells will be approximately $12.6 million. The net
cost of the pipeline will range from $4.3 million to $6.1 million, depending on
the size. Whether the Company can achieve the Increment I and II objectives on
schedule and with the Company's existing capital resources is dependant upon a
number of factors, many of which are not within its control, such as timely
environmental permitting, securing pipeline rights-of-way, obtaining Ecopetrol's
agreement to commerciality under the Association Contracts and timely payments
by the co-participants of their share of these costs as well as the market price
of oil field equipment and services. If the Company experiences delays or cost
overruns, which must be considered possible, the Company will seek other sources
of financing, including project financing, industry joint ventures or like
arrangements with industry service companies, commercial bank borrowings and
traditional debt and equity financing. The Company's expenditures for Increment
II, Early Pipeline Production, may be substantially reduced by having a third
party construct the Guaduas pipeline (connecting to the OAM regional pipeline),
in which case the Company may have little or no equity, thereby obligating the
Company to pay only a per barrel tariff on its oil transported through the
pipeline and none of the capital expenditures that are currently budgeted by the
Company for the construction of the pipeline.
Furthermore, the Company will be required to obtain additional sources of
financing to meet its other, multiple objectives of accelerating incremental
production from the Guaduas field beyond Increment II and delineation and
exploratory drilling. Each additional increment of field production (Increments
III through V) will require additional production facilities, a pipeline
expansion, and the expansion of proved oil reserves through successful
development and delineation drilling of the shallow Cimarrona reservoir.
We are obligated to conduct seismic operations on the Rosablanca and
Montecristo blocks during 1999 at a net cost of $2.1 million.
LIQUIDITY AND CAPITAL RESOURCES
We had working capital, net of restricted investments, of $24.3
million, and unrestricted cash resources, including short-term investments, of
$24.2 million as of September 30, 1999. Our non-discretionary capital
commitments for the remainder of 1999, as of September 30, 1999, are
approximately $3.8 million.
Our activities from inception through September 30, 1999 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, commencing December 31, 1997. 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.
10
<PAGE> 12
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 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
has been 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, commencing November 15, 1998. 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.
Notwithstanding the foregoing, 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:
(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 rank pari
passu in right and priority of payment with all of our existing and future
senior indebtedness.
COLOMBIA
In 1995, we acquired a 15% interest in the Dindal and Rio Seco
association contracts through our participation in El Segundo 1-E, the Guaduas
field discovery well. In 1996, we acquired an additional 36.7% in the Dindal and
Rio Seco association contracts in exchange for the issuance of our common shares
valued at $153.1 million in the aggregate at that time. In 1997, we acquired an
additional 6% in the Dindal and Rio Seco association contracts in exchange for
the issuance of our common shares valued at $18.6 million in the aggregate at
that time. From inception through September 30, 1999, we had capital
expenditures of $74.9 million for the acquisition, exploration, and development
of oil and gas properties, including $73.6 million for our interests in
Colombia.
Our estimated capital expenditures assume that each of the associates
in the association contracts approves and pays its proportionate share of
capital expenditures. Under the terms of the association contracts, if a
commercially feasible discovery is made, Ecopetrol may acquire a 50% interest in
the property, and the interests of all other parties to the contract will be
reduced by 50%. Ecopetrol will bear 50% of the associated development costs and
will reimburse the other associates for 50% of certain exploration activities.
The association contracts require Ecopetrol's participation in the production
facilities. We expect that Ecopetrol will participate in the extent of 50% of
the pipeline and infrastructure costs. We cannot be sure, however, that an
agreement will be reached and we may be required to fund amounts greater than
the amounts presented as our net share. Ecopetrol retains the right not to
participate initially in the development. In this case, the associates can
develop the Guaduas field under a sole risk provision, and will be required to
invest 100% of the development costs. After the associates have recovered 200%
of the costs invested for development plus 50% of certain exploration costs,
Ecopetrol will become a participant in the project with a 50% interest.
To date, all oil revenues have been due to our share of crude oil
produced during production testing of our wells on the Guaduas field. Although
we intend to continue selling oil from production tests, significant commercial
production is not expected until we drill, or redrill and complete, additional
wells and construct production and pipeline transportation facilities.
We have contracted to acquire 100 kilometers of new 2-D seismic on the
Rosablanca association contract at a net cost of approximately $1.1 million. We
estimate the cost to conduct seismic operations on the Montecristo and
Rosablanca association
11
<PAGE> 13
contract areas in 1999 will be $2.1 million. We are negotiating with Ecopetrol
to substitute alternate work for the obligation to conduct seismic operations
over 100 kilometers under the Montecristo contract. We may assign part of our
interest to a third party who would pay these costs, which would result in a
reduction of our interest.
We signed a purchase and sale agreement to sell our 11.875% interest in
the Tapir association contract in Colombia, South America to Solana Petroleum
Exploration Colombia Ltd. for 3,000,000 shares of common stock of Solana
Colombia's parent corporation, Solana Petroleum Corporation. The transaction has
been valued at $1.4 million. The sale has been approved by the Solana
shareholders but is awaiting approval by the Alberta Stock Exchange and
Ecopetrol. The transaction is expected to close by the end of November 1999. If
this transaction is not completed, we will have estimated capital expenditures
of $0.3 million in 2000 to drill the Mateguafa 2 well.
AUSTRALIA
In June 1999, we paid $0.2 million to the operator for the right to
withdraw from our 20% interest in the Bass Strait Basin in offshore southeast
Australia. The withdrawal resulted in a $0.7 million loss. The operator assumed
all obligations related to the property in the future.
In 1998, we completed the sale of our 11.77% working interest in the
Perth Basin in Western Australia for approximately $0.9 million in cash and the
reimbursement of approximately $0.3 million for certain capital expenditures.
PAPUA NEW GUINEA
In February 1999, we entered into an agreement with ARCO Papua New
Guinea Inc. whereby ARCO funded our obligation for the twelve-month period ended
July 1998 for an 80% interest in the subject exploration permit. Subsequently,
we relinquished our rights in the property to ARCO, retaining a small production
payment. We have no remaining required capital expenditures.
ACCOUNTING POLICIES AND DEVELOPMENT STAGE ACCOUNTING
The consolidated financial statements and notes thereto included in
this prospectus have been prepared in accordance with generally accepted
accounting principles in the United States.
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 the 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 Condensed Consolidated Financial
Statements are required to identify the enterprise as development stage.
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. As of December 31, 1996, unevaluated oil and gas interests
included capitalized general and administrative costs of $0.1 million. No
additional general and administrative costs were capitalized during 1997 and
1998. We capitalized interest of $10.3 million and $7.0 million for the nine
month periods ended September 30, 1999 and 1998, 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 are 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
12
<PAGE> 14
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, 1999 AND 1998
To date, oil revenues and lease operating expenses pertained solely to the
Company's share of crude oil produced during production testing of the Company's
wells in the Guaduas Field. Revenues from oil sales were $0.1 million and zero
for the quarter ended September 30, 1999 and 1998, respectively. Oil and gas
operating expenses were $0.2 million and $46,000 for the quarter ended September
30, 1999 and 1998, respectively. The 1999 costs related to the long term
production testing of the El Segundo 1-S well. The 1998 oil and gas operating
expenses represent such costs as tank rentals and other miscellaneous fixed
costs.
Oil production in Colombia (net to the Company) of 11,029 barrels and zero
for the quarter ended September 30, 1999 and 1998, respectively, pertaining
solely to the Company's share of oil produced from production testing, was sold
to Ecopetrol at an average price of $11.77 per barrel in 1999.
Interest income was $0.7 million and $1.4 million for the quarter ended
September 30, 1999 and 1998, respectively. The decrease from 1998 to 1999 was
the consequence of lower cash and investment balances resulting from use of
funds from the issuance of senior notes in May 1998.
General and administrative costs were $1.6 million and $3.4 million for the
quarter ended September 30, 1999 and 1998, respectively. The $1.8 million
decrease in general and administrative expenses from the three month period
ended June 30, 1998 to the three month period ended June 30, 1999 was primarily
attributable to the non-recurring charges incurred during the third quarter of
1998, including 0.8 million relating to costs incurred conducting a feasibility
study for the proposed pipeline and production facilities in Colombia, a $0.2
million retroactive adjustment to salary expense as well as professional service
costs associated with the conversion of the $25 million convertible debentures
and the registration of the stock and warrants attributable to it. This was
slightly offset by increases in general and administrative activities incurred
in an attempt to move the Company into initial sustained production levels.
Depreciation and amortization was $0.3 million and $0.2 million for the
quarter ended September 30, 1999 and 1998, respectively. The increase resulted
from higher depreciation costs relating to the increase in fixed assets. As of
September 30, 1999, the Company has not recorded depletion of its proved oil and
gas property as only insignificant quantities of oil have been produced during
its production testing plan.
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 three months ended September 30, 1999 and 1998, respectively.
The Company incurred net losses of $1.3 million and $1.6 million for the
quarter ended September 30, 1999 and 1998, respectively.
NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
To date, oil revenues and lease operating expenses pertained solely to the
Company's share of crude oil produced during production testing of the Company's
wells in the Guaduas Field. Revenues from oil sales were $0.3 million and $0.1
million for the nine months ended September 30, 1999 and 1998, respectively. Oil
and gas operating expenses were $1.7 million and $0.8 million for the nine
months ended September 30, 1999 and 1998, respectively. The 1999 costs related
to the long term production testing of the Tres Pasos 1-W Horizontal and the El
Segundo 1-S wells. The 1998 oil and gas operating expenses represent such costs
as tank rentals and other miscellaneous fixed costs.
Oil production in Colombia (net to the Company, including minority interest
through June 30, 1999) of 36,599 barrels and 1,997 for the nine months ended
September 30, 1999 and 1998, respectively, pertaining solely to the Company's
share of oil produced from production testing, was sold to Ecopetrol at an
average price of $9.12 per barrel in 1999 and $8.14 per barrel in 1998.
13
<PAGE> 15
Interest income was $2.4 million and $2.6 million for the nine months ended
September 30, 1999 and 1998, respectively. The decrease from 1998 to 1999 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 $6.2 million and $5.8 million for the
nine months ended September 30, 1999 and 1998, respectively. The quarter ended
September 30, 1998 included $0.8 million relating to costs incurred conducting a
feasibility study for the proposed pipeline and production facilities in
Colombia. The $0.4 million increase in general and administrative expenses from
to 1999 was primarily attributable to a $1.0 million increase in personnel costs
in both US and Colombia, $0.4 million in several costs, and increased
professional services and general and administrative activities incurred in an
attempt to move the Company into initial sustained production levels. However,
several non-recurring charges incurred during the third quarter of 1998, which
included a $0.8 million relating to costs incurred conducting a feasibility
study for the proposed pipeline and production facilities in Colombia and a $0.2
million retroactive adjustment to salary expense, somewhat offset the increase.
Depreciation and amortization was $0.8 million and $0.4 million for the nine
months ended September 30, 1999 and 1998, respectively. The increase from 1998
to 1999 was attributable to the amortization of costs incurred on the issue of
the senior notes in May 1998 (see "Liquidity and Capital Resources") and from
higher depreciation costs relating to the increase in fixed assets. As of
September 30, 1999, the Company has not recorded depletion of its proved oil and
gas property as only insignificant quantities of oil have been produced during
its production testing plan.
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, 1999 and 1998, respectively.
The Company incurred net losses of $6.2 million and $3.5 million for the
nine months ended September 30, 1999 and 1998, respectively.
COLOMBIAN 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%.
YEAR 2000 DISCLOSURE
The "Year 2000 Issue" is a general phrase used to refer to certain business
implications of the arrival of the Year 2000. In simple terms, on January 1,
2000, all hardware and software systems which use the two-digit year convention
could fail completely or create erroneous data as a result of the system failing
to recognize the two digit internal date "00" as representing the Year 2000.
We do not believe that our internal systems and operations have any
material Year 2000 compliance problems, and we do not anticipate incurring
significant remediation costs, if any. We have a limited operating history and
are engaged solely in the exploration, development and production of oil and
natural gas in Colombia. As such, we engage in few transactions and have minimum
reliance on the hardware and software systems of third parties. Further, our
hardware and software systems are relatively new and widely utilized. We have
been advised that all of these systems are Year 2000 compliant. Our internal
dependence on information systems and other operating equipment that could
potentially require remedial action to become Year 2000 compliant is low.
Accordingly, the risk of operation disruptions and the corresponding risk of
liability for disruptions caused by non-Year 2000 compliant systems are not of
major concern to us.
One of the next phases in the development of the Guaduas field is the
transportation and marketing of crude oil to be produced from our properties. We
have retained Brown & Root Energy Services and Technivance Brown & Root S.A. to
conduct planning and engineering studies for the pipeline and associated
compression facilities from the Guaduas field. We intend for the technology
employed in the delivery systems to be Year 2000 compliant. We have also asked
these consultants to review any Year 2000 risks associated with the planned
interconnection of our delivery systems with other pipelines, and are reviewing
the Oleoducto Alto Magdelena delivery systems in conjunction with our current
negotiations with the operator of that pipeline. Seven Seas or the consultants
will review and, where necessary, rectify the Year 2000 risks associated with
interconnections to the pipelines. We are not currently aware of Year 2000
limitations that would compromise the computer systems. In addition, we would
not be responsible for remediation costs associated with such computer systems
should any technical problems arise. However, in the event a pipeline was
14
<PAGE> 16
rendered inoperable as a result of Year 2000 issues, we may be required to rely
on less efficient alternate delivery systems, such as tanker trucks, to
transport any oil production to market.
As we develop our infrastructure at the Guaduas field, we will continue to
monitor Year 2000 compliance issues relating to equipment supplied by our
vendors and contractors. Since we do not currently supply significant oil
production, and no supply contracts have been entered, we are unable to assess
the significance of Year 2000 issues affecting potential customers.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Seven Seas is exposed to market risk, including adverse changes in commodity
prices, interest rates and foreign currency exchange rates as discussed below.
Commodity Risk. The Company's exposure in the commodity pricing applicable
to its oil and natural gas production is currently minimal due to 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 the Company produces commercial
quantities of oil and gas.
Interest Rate Risk. The Company considers its interest rate risk exposure to
be minimal as a result of a fixed interest rate on the $110 million 12 1/2%
Senior Notes. The Company currently has no open interest rate swaps agreements.
Foreign Currency Exchange Rate Risk. The Company conducts business in
several foreign currencies and is subject to foreign currency exchange rate risk
on cash flows related to sales, expenses and capital expenditures. However,
because predominately all transactions in Seven Seas' 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 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 Form 8-K
None
15
<PAGE> 17
SIGNATURES
SEVEN SEAS PETROLEUM INC.
Date: November 16, 1999 By: Larry A. Ray
Executive Vice President,
Chief Operating Officer and
Chief Financial Officer
Sir Mark Thomson, Bt. President
15
<PAGE> 18
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
27 Financial Data Schedule
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEETS AND STATEMENTS OF CONSOLIDATED OPERATIONS AND
ACCUMULATED DEFICIT ON PAGES 2 AND 3 OF THE COMPANY'S FORM 10-Q FOR THE
QUARTERLY PERIOD ENDING JUNE 30, 1999, AND IS QUALIFIED IN ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1999
<CASH> 15,349
<SECURITIES> 22,302
<RECEIVABLES> 5,917
<ALLOWANCES> 0
<INVENTORY> 1,085
<CURRENT-ASSETS> 44,706
<PP&E> 197,491
<DEPRECIATION> 565
<TOTAL-ASSETS> 258,857
<CURRENT-LIABILITIES> 6,933
<BONDS> 110,000
0
0
<COMMON> 225,805
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 258,857
<SALES> 308
<TOTAL-REVENUES> 2,711
<CGS> 1,662
<TOTAL-COSTS> 9,445
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (6,734)
<INCOME-TAX> 20
<INCOME-CONTINUING> (6,764)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (6,171)
<EPS-BASIC> (0.16)
<EPS-DILUTED> (0.16)
</TABLE>
