<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 June 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 JULY 31, 1999 THERE WERE 37,833,420 SHARES OF THE REGISTRANT'S COMMON
SHARES, NO PAR VALUE PER SHARE, OUTSTANDING.
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INDEX
<TABLE>
<CAPTION>
<S> <C> <C>
PART I. FINANCIAL INFORMATION PAGE
(DEVELOPMENT STAGE ENTERPRISE)
Item 1. Condensed Consolidated Balance Sheets as of June
30, 1999 (Unaudited) and December 31,
1998..............................................................2
Condensed Statements of Consolidated Operations and
Accumulated Deficit for the six months and three
months ended June 30, 1999 and 1998 and 3 and 1998
and the Cumulative Total from Inception (February
3, 1995) to June 30, 1999
(Unaudited).......................................................3
Condensed Statements of Consolidated Cash Flows for
the six months ended June 30, 1999 and 1998 and the
Cumulative Total from Inception (February 3, 1995)
to June 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......................................................13
PART II. OTHER INFORMATION.....................................................14
Item 4 Submission of Matters to a Vote of Security Holders..............14
Item 6 Exhibits and Reports on Form 8-K.................................14
</TABLE>
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SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
December 31,
JUNE 30, 1999 1998
------------- ------------
ASSETS (Unaudited)
<S> <C> <C>
CURRENT
Cash and cash equivalents $ 28,641 $ 38,147
Short-term investments -- 6,399
Restricted short-term investments 13,305 13,244
Accounts receivable 5,524 6,562
Interest receivable 178 532
Inventory 1,121 1,316
Prepaids and other 104 225
------------ ------------
48,873 66,425
Notes receivable from employees 435 200
Restricted long-term investments 12,611 18,658
Land 1,064 1,257
Evaluated oil and gas interests, full-cost method 77,627 74,993
Unevaluated oil and gas interests, full-cost method 113,241 113,116
Fixed assets, net of accumulated depreciation of $425 at June 30, 1999
and $232 at December 31, 1998 1,257 1,357
Other assets, net of accumulated amortization of $765 at June 30, 1999
and $461 at December 31, 1998 3,590 3,894
------------ ------------
TOTAL ASSETS $ 258,698 $ 279,900
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT
Accounts payable $ 3,672 $ 10,058
Interest payable 1,719 1,719
Other accrued liabilities 97 580
------------ ------------
5,488 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 June 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 June 30, 1999 -- 3,093
and December 31, 1998, respectively
Deficit accumulated during development stage (107,327) (102,442)
Treasury stock, 29 shares held at June 30, 1999 and December 31, 1998 -- --
------------ ------------
Total Stockholders' Equity 118,478 123,098
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 258,698 $ 279,900
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
2
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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,
1995) TO
SIX MONTHS ENDED JUNE 30, THREE MONTHS ENDED JUNE 30, JUNE 30,
1999 1998 1999 1998 1999
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUE
Crude oil sales $ 185 $ 91 $ 95 $ 91 $ 1,214
Interest income 1,698 1,143 792 959 6,760
------------ ------------ ------------ ------------ ------------
1,883 1,234 887 1,050 7,974
EXPENSES
General and administrative 4,624 2,545 3,054 1,425 26,625
Oil and gas operating expenses 1,511 532 1,145 344 3,613
Depreciation and amortization 514 227 259 143 1,485
Writedown of proved oil & gas properties -- -- -- -- 129,789
Loss on sale of exploration properties 670 -- 670 -- 124
Dry hole and abandonment costs -- -- -- -- 1,145
Geological and geophysical -- -- -- -- 47
Other (income) expense 22 (30) 6 -- (100)
------------ ------------ ------------ ------------ ------------
7,341 3,274 5,134 1,912 162,728
NET LOSS BEFORE INCOME TAXES
AND MINORITY INTEREST (5,458) (2,040) (4,247) (862) (154,754)
------------ ------------ ------------ ------------ ------------
INCOME TAX EXPENSE 20 30 14 15 (45,698)
NET LOSS BEFORE MINORITY INTEREST (5,478) (2,070) (4,261) (877) (109,056)
------------ ------------ ------------ ------------ ------------
MINORITY INTEREST 593 203 480 125 1,729
------------ ------------ ------------ ------------ ------------
NET LOSS $ (4,885) $ (1,867) $ (3,781) $ (752) $ (107,327)
============ ============ ============ ============ ============
DEFICIT ACCUMULATED DURING THE DEVELOPMENT
STAGE, BEGINNING OF PERIOD (102,442) (12,243) (103,546) (13,358) --
DEFICIT ACCUMULATED DURING THE DEVELOPMENT
STAGE, END OF PERIOD $ (107,327) $ (14,110) $ (107,327) $ (14,110) $ (107,327)
============ ============ ============ ============ ============
BASIC AND DILUTED NET LOSS PER COMMON SHARE $ (0.13) $ (0.05) $ (0.10) $ (0.02) $ (4.35)
============ ============ ============ ============ ============
WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 37,806,072 35,189,534 37,833,420 35,343,910 24,698,120
============ ============ ============ ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
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
SIX MONTHS ENDED JUNE 30, JUNE 30,
------------------------
1999 1998 1999
--------- --------- ---------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net loss $ (4,885) $ (1,867) $(107,327)
Add (subtract) items not requiring (providing) cash:
Compensation expense -- -- 2,140
Accretion of interest on zero coupon bonds -- (175) (175)
Minority interest (593) (203) (1,729)
Common stock contribution to 401(k) retirement plan -- 79
Depreciation and amortization 514 227 1,490
Writedown of proved oil & gas properties -- -- 129,789
Loss on sale of exploration property 670 -- 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 (695) -- (695)
Changes in working capital excluding changes to cash and cash
equivalents:
Accounts receivable 2,418 1,255 (3,262)
Interest receivable 354 (343) (178)
Inventory (9) -- (1,325)
Prepaids and other, net 121 11 (104)
Accounts payable (10,273) (1,439) (4,563)
Other accrued liabilities (233) (92) 346
--------- --------- ---------
Cash Flow Used in Operating Activities (12,611) (2,632) (29,983)
--------- --------- ---------
INVESTING ACTIVITIES
Exploration of oil and gas properties (10,685) (20,759) (83,030)
Purchase of land -- (1,139) (1,257)
Purchase of investments -- (37,827) (38,301)
Proceeds from acquisition -- -- 630
Payment to withdraw from property (250) -- 997
Proceeds from sale of marketable securities -- 50 50
Proceeds from sale of investments 13,080 -- 13,080
Notes receivable from employees (235) -- (435)
Other asset additions (191) (135) (1,947)
--------- --------- ---------
Cash Flow Used in Investing Activities 1,719 (59,810) (110,213)
--------- --------- ---------
FINANCING ACTIVITIES
Proceeds from special warrants issued -- -- 12,393
Proceeds from share capital issued -- 2,279 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 -- (4,195) (5,821)
Contributions by minority interest 1,386 4,140 11,623
--------- --------- ---------
Cash Flow Provided by Financing Activities 1,386 112,224 168,662
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (9,506) 49,782 28,466
Cash and cash equivalents, beginning of period 38,147 18,067 --
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 28,641 $ 67,849 $ 28,466
========= ========= =========
</TABLE>
Supplemental disclosures of cash flow information:
The Company incurred interest costs of $6.9 million and $2.8 million for the
six month periods ended June 30, 1999 and 1998, respectively, and $9.8 million
for the year ended December 31, 1998. Such amounts were capitalized during the
respective periods.
Cash paid for interest for the six month periods ended June 30, 1999 and
1998 and for the year ended December 31, 1998 was $6.9 million, $0.8 million,
and $8.1 million, respectively.
The Company paid zero and $30,000 for estimated income taxes during the six
month periods ended June 30, 1999 and 1998, respectively.
The accompanying notes are an integral part of these financial statements.
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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 collectively 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") and covers 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 June 30, 1999, the Company incurred cumulative losses of
$107.3 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 June 30, 1999, the Company has spent $242.2 million to acquire and
$70.6 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 1,666 to 13,123 Bbls per day. Four of the twelve
did not produce commercial amounts of oil and gas during testing and two remain
to be tested. As of June 30, 1999, the Guaduas Field had produced a cumulative
volume of approximately 385,000 barrels of oil during various testing
procedures. Except for additional production testing and further reservoir
evaluation, continuous production of the Guaduas Field will not commence prior
to installation of the infrastructure necessary to produce and transport
continuous oil production.
The Company anticipates exploring and developing 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 year-end 2000) 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 further 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
mid - February 2000 the Company will not be able to proceed as planned.
As of June 30, 1999, the Company had cash and cash equivalents of $28.6
million and commitments under existing oil and gas agreements of $2.4 million in
1999. Based on available capital resources, the Company believes that it will be
able to make its commitments and fund its exploration and development plan
through 1999. To the extent the Company experiences delays or cost overruns in
the development 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 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' prospects are uncertainties inherent in
estimating oil and gas reserves and future hydrocarbon production and cash
flows, particularly
5
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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; 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 six months ended June 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>
Six months ended June 30, 1999
Revenues ........................ $ 1,629 $ 6 $ 248 $ -- $ 1,883
Operating Income (Loss) ......... 743 (1,668) (3,847) (686) (5,458)
Capital Expenditures ............ -- 57 7,856 250 8,163
Identifiable Assets ............. 74,068 1,147 183,402 81 258,698
Depreciation and Amortization ... 303 167 44 -- 514
Six months ended June 30, 1998
Revenues ........................ $ 1,093 $ 6 $ 135 $ -- $ 1,234
Operating Income (Loss) ......... 752 (1,559) (1,221) (12) (2,040)
Capital Expenditures ............ -- 72 18,415 19 18,506
Identifiable Assets ............. 110,981 452 291,002 1,013 403,448
Depreciation and Amortization ... 181 25 21 -- 227
</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 $1,000 for the six months
ended June 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
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liabilities of Cimarrona L.L.C. which were proportionately attributable to SSPC
(through the 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 Sea's 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.
The Ministry of Environment by resolution has decided to open a list of
charges against GHK Company Colombia based on alleged environmental damages,
originating from the location that has been constructed for the proposed El
Segundo 7-E well. The Company has experienced difficulty trying to stabilize the
slopes of this location, and as a result, sediments from the location were
entering a creek. At this time, remediation efforts are underway and should be
completed soon. The Company has been notified that it will likely be assessed a
fine for the alleged environmental damages at the El Segundo 7-E location. The
Company believes that the amount accrued will be sufficient to cover remediation
costs and potential fines assessed as a result of El Segundo 7-E operations.
Commercial relations between the Company and International Technical
Solutions Inc. (ITS), a consulting engineering firm, were terminated by the
Company's operating subsidiary, GHKCC as of January 1999. ITS states that there
were unfair causes for termination. The Company and ITS have reached an
agreement on the majority of the issues surrounding this claim and the Company
is continuing to work with ITS to settle the remaining claim. The Company's
legal counsel is of the opinion that the likelihood of any substantial payments
other than valid existing accounts payable to ITS as a result of an ordinary
lawsuit are remote.
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 had previously been extended and, unless further extended
by Ecopetrol, the exploration period under the Dindal Association Contract will
expire in September 1999, at which time the Company 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. The Company has requested an
extension of the exploration period.
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 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.
8. SUBSEQUENT EVENTS
The Company signed a letter of intent to sell its 11.875% interest in the
Tapir Association Contract in Colombia, South America to Solana Petroleum
Exploration Colombia Limited ("Solana Colombia") for 3,000,000 shares of common
stock of Solana Colombia's parent corporation, Solana Petroleum Corporation
("Solana"). The transaction has been valued at US$1.4 million, and the sale is
subject to the preferential right of the other Tapir Association participant to
buy their share of Seven Seas' 11.875% interest. If the other participant
exercise their full participation rights the number of Solana shares will be
reduced accordingly and Seven Seas will
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<PAGE> 9
receive a proportionate part (up to US$0.8 million) of the sale in cash. The
sale is further subject to the execution of a mutually acceptable purchase and
sale agreement, approval of the companies' respective Board of Directors,
approval of Solana shareholders and also the appropriate regulatory and exchange
consents. The transaction is expected to close by the end of the third quarter
of 1999.
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.
OVERVIEW
Seven Seas' 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 ("Ryder Scott") estimated total proved recoverable reserves for the
Guaduas Field of 163,303,000 Bbls, of which 38,719,235 Bbls were attributable to
the Company's interest.
The Company currently 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 $9.4 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 by year-end-2000.
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 $14 million.
The net cost of the pipeline is approximately $6.1 million.
The Company's unrestricted cash resources, including short-term investments,
as of June 30, 1999 were $28.6 million and the Company has obligatory capital
expenditure commitments of $2.4 million through year end 1999 (see "-- Liquidity
and Capital
8
<PAGE> 10
Resources"). 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 the formation of
a separate company to construct the Guaduas pipeline (connecting to the OAM
regional pipeline) to be owned and financed by third parties and in which 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. If
external financing is obtained, the Company would anticipate drilling a
delineation well on the west flank of the Guaduas structure and an exploration
well to test the deep Guaduas Field structure, depending on certain actions by
Ecopetrol.
The Company also plans to conduct seismic operations on the Rosablanca and
Montecristo blocks during the remainder of 1999 at a net cost of $2.3 million.
LIQUIDITY AND CAPITAL RESOURCES
The Company had working capital net of restricted investments of $30.0
million, and unrestricted cash resources of $28.6 million as of June 30, 1999.
The Company's non-discretionary capital commitments for the remainder of 1999 as
of June 30, 1999 are approximately $2.4 million.
The Company's activities from its inception through June 30, 1999 were
funded primarily by the proceeds from private placements of the Company's
securities, including the Company's common shares, warrants and notes, resulting
in aggregate cash proceeds of $157.0 million. Such funding transactions are as
follows:
(i) Exchangeable Notes. In August 1997, the Company issued $25 million of 6%
Exchangeable Notes (the "Exchangeable Notes") in a private transaction with
institutional and accredited investors. The Exchangeable Notes accrued interest
at a rate of 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.
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. The warrants expired on
February 5, 1999. The Company received proceeds of $0.3 million from the
exercise of 18,913 warrants.
(ii) Senior Notes. In May 1998, the Company completed the offering of $110
million of 12 1/2% Senior Notes due May 15, 2005 (the "Senior Notes"), of which
approximately $25.9 million remains in escrow to provide for next two 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 Senior Notes mature on
May 15, 2005. The Senior Notes are redeemable at the option of the Company, 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, the Company may redeem up to 33
1/3% of the original aggregate principal amount of the Senior Notes 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 occurrence of such
redemption. The Senior Notes may also be redeemed at the option of the Company,
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 in the event of certain
changes affecting withholding taxes applicable to certain payments on the Senior
Notes. Upon the occurrence of a change of control, (i) unless the Company
redeems the Senior Notes as provided in clause (ii) below, the Company 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,
9
<PAGE> 11
if any, to the date of purchase, and (ii) the Company 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 the Company and rank pari passu
in right and priority of payment with all existing and future senior
indebtedness of the Company.
Colombia. In 1995, the Company acquired a 15% interest in the Dindal and Rio
Seco Association Contracts through its participation in El Segundo 1-E, the
Guaduas Field discovery well. In 1996, the Company acquired an additional 36.7%
in the Dindal and Rio Seco Association Contracts in Colombia in exchange for the
issuance of the Company's common shares valued at $153.1 million in the
aggregate at that time. In 1997, the Company acquired an additional 6% in the
Dindal and Rio Seco Association Contracts in Colombia in exchange for the
issuance of the Company's common shares valued at $18.6 million in the aggregate
at that time. From inception through June 30, 1999, the Company had capital
expenditures of $73.9 million for the acquisition, exploration, and development
of its oil and gas properties including $72.6 million with respect to its
interests in Colombia.
The Company's estimated capital expenditures assume in each case 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, the Colombian national
oil company ("Ecopetrol") may acquire a 50% interest in the property, and the
interests of all other parties to the contract, including the Company, 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. The Company expects that Ecopetrol will participate to the extent of
50% of the pipeline and infrastructure costs. No assurances can be given,
however, that an agreement will be reached on these terms and the Company may be
required to fund amounts greater than the amounts presented as the Company's 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 at a 50% interest.
To date, all oil revenues have been due to the Company's share of crude oil
produced during production testing of the Company's wells on the Guaduas Field.
Although the Company intends to continue to sell oil resulting from production
tests, significant commercial production is not expected until further
development of the field through the drilling, well operations and construction
of production and pipeline transportation facilities. The Company has completed
plans for the construction of pipeline and production facilities at the Guaduas
Field. Permitting and the purchasing of equipment and supplies for pipeline and
production facilities is in process. Anticipated completion of Increment II at
20,000 Bbls/d to 30,000 Bbls/d is year-end 2000.
The Company plans to conduct seismic operations on the Montecristo and
Rosablanca Association Contract areas in 1999 for an estimated cost of $2.3
million.
The Company signed a letter of intent to sell its 11.875% interest in the
Tapir Association Contract in Colombia, South America to Solana Petroleum
Exploration Colombia Limited ("Solana Colombia") for 3,000,000 shares of common
stock of Solana Colombia's parent corporation, Solana Petroleum Corporation
("Solana"). The transaction has been valued at US$1.4 million, and the sale is
subject to the preferential right of the other Tapir Association participant to
buy their share of Seven Seas' 11.875% interest. If the other participant
exercise their full participation rights the number of Solana shares will be
reduced accordingly and Seven Seas will receive a proportionate part (up to
US$0.8 million) of the sale in cash. The sale is further subject to the
execution of a mutually acceptable purchase and sale agreement, approval of the
companies' respective Board of Directors, approval of Solana shareholders and
also the appropriate regulatory and exchange consents. The transaction is
expected to close by the end of the third quarter of 1999. If this transaction
is not completed, the Company will have estimated capital expenditures of $0.2
million to drill the Mateguafa 2 well.
Australia. In June 1999, the Company paid $0.2 million to the operator for
the right to withdraw from its 20% interest in the Bass Strait Basin in offshore
southeast Australia, resulting in a loss of $0.7 million. The operator will
assume all obligations related to the property in the future. In 1998, the
Company completed the sale of its 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.
10
<PAGE> 12
Papua New Guinea. The Company entered into an Agreement with ARCO Papua New
Guinea Inc. ("ARCO") for a farm out of its interest whereby ARCO funded the
Company's obligation for the twelve-month period ended July 1998 for an 80%
interest in the subject exploration permit. Subsequently, the Company
relinquished its rights in the property to ARCO, retaining a small production
payment. The Company has no remaining required capital expenditures.
ACCOUNTING POLICIES AND DEVELOPMENT STAGE ACCOUNTING
The Consolidated Financial Statements and Notes thereto included herein have
been prepared in accordance with generally accepted accounting principles in the
United States of America.
The Company's 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 the Company's inception. The
statement of cash flows shows inflows and outflows for each period presented and
from the Company's inception. In addition, the Notes to Consolidated Financial
Statements are required to identify the enterprise as development stage.
The Company follows 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. The Company capitalized interest of $9.8 million for the year ended
December 31, 1998 and $6.9 million for the six month period ended June 30, 1999.
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 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.
As of June 30, 1999, the Company's exploration and development activities
have not generated significant revenues. As a result, the Company's historical
results of operations have been presented as a development stage company; thus,
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
the Company will be highly dependent upon the success of the Company's Guaduas
Field operations.
RESULTS OF DEVELOPMENT STAGE OPERATIONS
THREE MONTHS ENDED JUNE 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 $0.1
million for the quarter ended June 30, 1999 and 1998, respectively. Oil and gas
operating expenses were $1.1 million and $0.3 million for the quarter ended June
30, 1999 and 1998, respectively. The 1999 costs related to the long term
production testing of the Tres Pasos 1-W Horizontal 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, including minority interest)
of 11,946 barrels and 1,997 barrels for the quarter ended June 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 $9.54 per
barrel in 1999 and $8.14 per barrel in 1998. The Tres Pasos 1-W Horizontal
production testing was completed in May 1999.
11
<PAGE> 13
Interest income was $0.8 million and $1.0 million for the quarter ended June
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 $3.1 million and $1.4 million for the
quarter ended June 30, 1999 and 1998, respectively. The $1.7 million increase 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
a $0.6 million increase in personnel costs, including salaries, benefits,
travel, rents, insurance, and security due to increased personnel in both US and
Colombia. In addition, severance costs relating to reduction in personnel was
approximately $0.4 million. The remaining increase is due to increased
professional services and 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 $0.1 million for the
quarter ended June 30, 1999 and 1998, respectively. The increase from 1998 to
1999 was primarily attributable to the amortization of costs incurred on the
issue of the Senior Notes in May 1998 (see "Liquidity and Capital Resources").
The remaining increase resulted from higher depreciation costs relating to the
increase in fixed assets. As of June 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 June 30, 1999 and 1998, respectively.
The Company incurred net losses of $3.8 million and $0.7 million for the
quarter ended June 30, 1999 and 1998, respectively.
SIX MONTHS ENDED JUNE 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 $0.2 million and $0.1
million for the six months ended June 30, 1999 and 1998, respectively. Oil and
gas operating expenses were $1.5 million and $0.5 million for the six months
ended June 30, 1999 and 1998, respectively. The 1999 costs related to the long
term production testing of the Tres Pasos 1-W Horizontal 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, including minority interest)
of 23,5464 barrels and 1,997 for the six months ended June 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 $8.66 per
barrel in 1999 and $8.14 per barrel in 1998. The Tres Pasos 1-W Horizontal
production testing was completed in May 1999.
Interest income was $1.7 million and $1.1 million for the six months ended
June 30, 1999 and 1998, respectively. The increase from 1998 to 1999 was the
consequence of higher cash and investment balances resulting from the issuance
of the Senior Notes in May 1998.
General and administrative costs were $4.6 million and $2.5 million for the
six months ended June 30, 1999 and 1998, respectively. The $2.1 million increase
in general and administrative expenses from the six month period ended June 30,
1998 to the six month period ended June 30, 1999 was primarily attributable to a
$0.8 million increase in personnel costs, including salaries, benefits, travel,
rents, insurance, and security due to increased personnel in both US and
Colombia. In addition, severance costs relating reduction in personnel was
approximately $0.4 million. The remaining increase is due to increased
professional services and general and administrative activities incurred in an
attempt to move the Company into initial sustained production levels.
Depreciation and amortization was $0.5 million and $0.2 million for the six
months ended June 30, 1999 and 1998, respectively. The increase from 1998 to
1999 was primarily attributable to the amortization of costs incurred on the
issue of the Senior Notes in May 1998 (see "Liquidity and Capital Resources").
The remaining increase resulted from higher depreciation costs relating to the
increase in fixed assets. As of June 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.
12
<PAGE> 14
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 six months ended June 30, 1999 and 1998, respectively.
The Company incurred net losses of $4.9 million and $1.9 million for the six
months ended June 30, 1999 and 1998, respectively.
COLOMBIAN TAXES
The Company's 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 term used to refer to certain business
implications of the arrival of the new millennium. 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.
The Company does not believe that its internal systems and operations have
any material issues with respect to Year 2000 compliance and does not anticipate
incurring significant remediation costs, if any. The Company has a limited
operating history and is engaged solely in the exploration, development and
production of oil and natural gas in Colombia. As such, the Company engages in
few transactions and has minimum reliance on the hardware and software systems
of third parties. Further, the Company's hardware and software systems are
relatively new, widely utilized and the Company has been advised that all of
these systems are Year 2000 compliant. The Company's 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 the
Company.
One of the next phases in the development of the Guaduas Field is the
transportation and marketing of crude oil to be produced from the Company's
properties, which is scheduled for completion by year end - 2000.. The Company
needs to construct its processing, storage and related facilities and a 36-mile
pipeline from the Guaduas Field to the existing Oleoducto Alto Magdalena ("OAM")
pipeline, which terminates at Vasconia. Beyond Vasconia, the Company's oil
production may be transported to the export terminal at Covenas via the existing
pipeline system, Oleducto de Colombia ("ODC"). The Company employed Brown & Root
Energy Services and Technivance Brown & Root S.A. to conduct certain planning
and engineering studies for its planned pipeline and associated compression
facilities from the Guaduas Field and intends that the technology employed in
its own delivery systems will be Year 2000 compliant. The Company is not
currently aware of Year 2000 limitations affecting the computer systems that
control these third party pipeline systems that would compromise the operation
of such systems. Moreover, the Company would not be responsible for remediation
costs associated with such computer systems should any technical problems arise.
However, in the event a pipeline was rendered inoperable as a result of Year
2000 issues affecting its operating systems, the Company may be required to rely
on less efficient alternate delivery systems, such as tanker trucks, to
transport any oil production to market.
As the Company develops its infrastructure at the Guaduas Field, it will
continue to monitor Year 2000 compliance issues as they relate to equipment
supplied by its vendors and contractors. Since the Company does not currently
supply significant oil production to its customers, and no supply contracts have
been entered into in respect of the Guaduas Field production, the Company is
unable to assess the significance of Year 2000 issues affecting potential
customers at this stage in its operations.
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.
13
<PAGE> 15
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 4. Submission of Matters to a Vote of Security Holders
The 1999 annual meeting (the "Annual Meeting") of the shareholders of the
Company was held on June 10, 1999. The purpose of the Annual Meeting was to
consider and vote upon the following proposals:
1. to elect directors to hold office until the next annual meeting of the
Company's shareholders;
2. to appoint the auditors of the Company for the ensuing year and to
authorize the directors to fix the remuneration to be paid to such
auditors;
The Company's Board of Directors is comprised of nine members. At the Annual
Meeting, each of the following individuals was elected to serve as a director of
the Company by proxy, with a total of 33,148,948 votes for the directors as a
group and 4,684,441 votes withheld: Robert A. Hefner III; Breene M. Kerr; Brian
F. Egolf; Sir Mark Thomson BT; Robert B. Panero; Gary F. Fuller; Robert M.D.
Cross; Larry A. Ray; William W. Daily.
The following votes were cast by proxy with respect to the ratification of the
selection of Arthur Andersen LLP as independent auditors of the Company for the
fiscal year ending December 31, 1999:
<TABLE>
<S> <C>
For: 36,275,913
Withheld: 1,557,476
</TABLE>
Item 6. Exhibits and Reports on 8-K
(a) Exhibits
27 Financial Data Schedule
(b) Reports on From 8-K
None
SIGNATURES
Seven Seas Petroleum Inc.
Date: August 16, 1999 By: Larry A. Ray
Executive Vice President, Chief Operating
Officer and Chief Financial Officer
Ray A. Housley
Treasurer and Controller
14
<PAGE> 16
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
27 Financial Data Schedule
</TABLE>
<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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 28,641
<SECURITIES> 13,305
<RECEIVABLES> 5,702
<ALLOWANCES> 0
<INVENTORY> 1,121
<CURRENT-ASSETS> 48,873
<PP&E> 192,125
<DEPRECIATION> 425
<TOTAL-ASSETS> 258,698
<CURRENT-LIABILITIES> 5,488
<BONDS> 110,000
0
0
<COMMON> 225,805
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 258,698
<SALES> 185
<TOTAL-REVENUES> 1,883
<CGS> 1,511
<TOTAL-COSTS> 7,341
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (5,458)
<INCOME-TAX> 20
<INCOME-CONTINUING> (5,478)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (4,885)
<EPS-BASIC> (0.13)
<EPS-DILUTED> (0.13)
</TABLE>
