<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, 2000
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________to__________
Commission File No. 0-22483
---------------
SEVEN SEAS PETROLEUM INC.
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
YUKON TERRITORY 73-1468669
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
</TABLE>
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 August 10, 2000 there were 37,836,420 shares of the registrant's common
shares, no par value per share, outstanding.
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INDEX
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<CAPTION>
PART I. FINANCIAL INFORMATION PAGE
(DEVELOPMENT STAGE ENTERPRISE)
<S> <C>
Item 1. Condensed Consolidated Balance Sheets as of June 30, 2000
(Unaudited) and December 31, 1999 ...................................... 3
Condensed Statements of Consolidated Operations and Accumulated
Deficit for the six months and three months ended June 30,
2000 and 1999 and the Cumulative Total from Inception (February
3, 1995) to June 30, 2000 (Unaudited) .................................. 4
Condensed Statements of Consolidated Cash Flows for the six months
and three months ended June 30, 2000 and 1999 and the Cumulative
Total from Inception (February 3, 1995) to June 30, 2000
(Unaudited) ............................................................ 5
Notes to Condensed Consolidated Financial Statements (Unaudited) ....... 6
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations .................................................. 11
Item 3. Quantitative and Qualitative Disclosures about Market Risk ........ 18
PART II. OTHER INFORMATION ................................................... 18
Item 6. Exhibits and Reports on Form 8-K .................................. 18
</TABLE>
2
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SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
--------- ------------
<S> <C> <C>
ASSETS (UNAUDITED)
CURRENT ASSETS
Cash and cash equivalents $ 11,840 $ 22,447
Short-term investments 1,454 --
Restricted short-term investments 13,304 13,312
Accounts receivable 6,364 9,821
Interest receivable 45 243
Inventory 764 764
Prepaids and other 156 288
--------- ------------
33,927 46,875
Notes receivable from employees 215 435
Restricted long-term investments -- 6,391
Land 1,065 1,065
Evaluated oil and gas interests, full-cost method, net of accumulated
depletion of $768 at June 30, 2000 and $764 at December 31, 1999 105,529 96,244
Unevaluated oil and gas interests, full-cost method 106,814 105,725
Fixed assets, net of accumulated depreciation of $874 at June 30, 2000
and $669 at December 31, 1999 925 1,060
Other assets, net of accumulated amortization of $1,371 at June 30,
2000 and $1,068 at December 31, 1999 2,984 3,287
--------- ------------
TOTAL ASSETS $ 251,459 $ 261,082
========= ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 1,884 $ 7,917
Interest payable 1,719 1,719
Other accrued liabilities 821 78
--------- ------------
4,424 9,714
Long-term debt 110,000 110,000
Deferred income taxes 24,794 24,794
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Share capital
Authorized unlimited common shares without par value, 37,836,420
and 37,833,420 issued and outstanding common shares at June 30, 2000
and December 31, 1999, respectively 225,807 225,805
Authorized unlimited Class A preferred shares without par value -- --
Deficit accumulated during development stage (113,566) (109,231)
Treasury stock, 29 shares held at June 30, 2000 and December 31, 1999 -- --
--------- ------------
Total Stockholders' Equity 112,241 116,574
--------- ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 251,459 $ 261,082
========= ============
</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 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,
2000 1999 2000 1999 2000
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUE
Crude oil sales $ 16 $ 185 $ -- $ 95 $ 3,306
Interest income 1,006 1,698 454 792 9,120
------------ ------------ ------------ ------------ ------------
1,022 1,883 454 887 12,426
EXPENSES
General and administrative 3,733 4,624 1,280 3,054 33,417
Oil and gas operating expenses 954 1,511 352 1,145 5,547
Depletion, depreciation and amortization 513 514 252 259 3,309
Writedown of proved oil & gas properties -- -- -- -- 129,789
Loss (Gain) on sale of exploration properties -- 670 -- 670 124
Dry hole and abandonment costs -- -- -- -- 1,145
Geological and geophysical -- -- -- -- 47
Other (income) expense 157 22 100 6 (1)
------------ ------------ ------------ ------------ ------------
5,357 7,341 1,984 5,134 173,377
NET LOSS BEFORE INCOME TAXES
AND MINORITY INTEREST (4,335) (5,458) (1,530) (4,247) (160,951)
------------ ------------ ------------ ------------ ------------
INCOME TAX EXPENSE -- 20 -- 14 (45,656)
NET LOSS BEFORE MINORITY INTEREST (4,335) (5,478) (1,530) (4,261) (115,295)
------------ ------------ ------------ ------------ ------------
MINORITY INTEREST -- 593 -- 480 1,729
------------ ------------ ------------ ------------ ------------
NET LOSS $ (4,335) $ (4,885) $ (1,530) $ (3,781) $ (113,566)
============ ============ ============ ============ ============
DEFICIT ACCUMULATED DURING THE DEVELOPMENT STAGE,
BEGINNING OF PERIOD (109,231) (102,442) (112,036) (103,546) --
DEFICIT ACCUMULATED DURING THE DEVELOPMENT STAGE,
END OF PERIOD $ (113,566) $ (107,327) $ (113,566) $ (107,327) $ (113,566)
============ ============ ============ ============ ============
BASIC AND DILUTED NET LOSS PER COMMON SHARE $ (0.11) $ (0.13) $ (0.04) $ (0.10) $ (4.19)
============ ============ ============ ============ ============
WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 37,834,431 37,806,072 37,834,431 37,833,420 27,126,932
============ ============ ============ ============ ============
</TABLE>
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)
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,
---------------------------- ------------
2000 1999 2000
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net loss $ (4,335) $ (4,885) $ (113,566)
Add (subtract) items not requiring (providing) cash:
Compensation expense -- -- 2,140
Minority interest -- (593) (1,729)
Common stock contribution to 401(k) retirement plan -- -- 79
Depletion, depreciation and amortization 513 514 3,314
Writedown of proved oil & gas properties -- -- 129,789
Gain (loss) on sale of exploration property -- 670 124
Dry hole and abandonment costs -- -- 1,140
Gain on sale of marketable securities -- -- (6)
Deferred income tax benefit -- -- (45,665)
Amortization of investments (476) (695) (1,833)
Changes in working capital excluding changes to cash and cash
equivalents:
Accounts receivable 3,457 2,418 (4,102)
Interest receivable 198 354 (45)
Inventory -- (9) (968)
Prepaids and other, net 132 121 (156)
Accounts payable (4,430) (2,823) 571
Other accrued liabilities 743 (233) 1,070
------------ ------------ ------------
Cash Flow Used in Operating Activities (4,198) (5,161) (29,843)
------------ ------------ ------------
INVESTING ACTIVITIES
Exploration of oil and gas properties (11,982) (18,135) (112,195)
Purchase of land -- -- (1,258)
Purchase of investments (1,454) -- (39,755)
Proceeds from acquisition -- -- 630
(Payment to withdraw) proceeds from sale of property -- (250) 997
Proceeds from sale of marketable securities -- -- 50
Proceeds from sale of investments 6,875 13,080 26,830
Notes receivable from employees 220 (235) (215)
Other asset additions (70) (191) (2,065)
------------ ------------ ------------
Cash Flow Used in Investing Activities (6,411) (5,731) (126,981)
------------ ------------ ------------
FINANCING ACTIVITIES
Proceeds from special warrants issued -- -- 12,393
Proceeds from share capital issued 2 -- 15,468
Proceeds from additional paid-in capital contributed -- -- 1
Proceeds from issuance of long-term debt -- -- 135,000
Costs of issuing long-term debt -- -- (5,821)
Contributions by minority interest -- 1,386 11,623
------------ ------------ ------------
Cash Flow Provided by Financing Activities 2 1,386 168,664
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (10,607) (9,506) 11,840
Cash and cash equivalents, beginning of period 22,447 38,147 --
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 11,840 $ 28,641 $ 11,840
============ ============ ============
</TABLE>
Supplemental disclosures of cash flow information:
The Company incurred interest costs of $6.9 million and $6.9 million for the
six-month periods ended June 30, 2000 and 1999, respectively. Such amounts
were capitalized during the respective periods.
Cash paid for interest for the six month periods ended June 30, 2000 and
1999 was $6.9 million and $6.9 million, respectively.
The Company paid zero and zero for estimated income taxes during the
six-month periods ended June 30, 2000 and 1999, respectively.
The accompanying notes are an integral part of these financial statements.
5
<PAGE> 6
SEVEN SEAS PETROLEUM INC. AND SUBSIDIARIES
(A DEVELOPMENT STAGE ENTERPRISE)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. DEVELOPMENT STAGE OPERATIONS
FORMATION
Seven Seas Petroleum Inc. (a Yukon Territory, Canada corporation) was formed
on February 3, 1995. Seven Seas Petroleum Inc. and its subsidiaries
(collectively referred to as "Seven Seas" or the "Company") are a development
stage enterprise engaged in the exploration, development and production of oil
and natural gas in Colombia. The Company is the operator of an oil discovery,
known as the "Guaduas field," which is located in an area defined by the Rio
Seco and Dindal Association Contracts (the "Association Contracts") covering a
total of approximately 109,000 contiguous acres in central Colombia. The Company
owns a 57.7% working interest in the two Association Contracts before
participation by Empresa Colombiana de Petroleos ("Ecopetrol"), the Colombian
state oil company. The Company has no significant income producing properties
and its principal assets, its interests in the Association Contracts, are in the
early stage of exploration and development.
ACTIVITY TO DATE
As of June 30, 2000, the Company has spent $242.2 million to acquire and
$78.0 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 June 30, 2000, the Guaduas field had produced a cumulative volume
of approximately 793,000 (273,000 barrels net to the Company) barrels of oil
during various testing procedures. Except for additional production testing for
further reservoir evaluation and any production planned to be trucked,
continuous production of the Guaduas field will not commence prior to
installation of the necessary production facilities and pipeline.
Since inception through June 30, 2000, the Company incurred cumulative
losses of $113.6 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.
CURRENT STRATEGY
In late May 2000, Ecopetrol advised us that it opted not to participate in
the Guaduas field development at this time, and authorized us to proceed with
the development of the field on a sole-risk basis. Proceeding on a sole risk
basis will mean that Seven Seas, Sipetrol, and Cimarrona LLC will pay 100% of
the development costs. We will also retain all revenues from production after
the 20% Colombian royalty deduction. If we proceed on a sole-risk basis,
Ecopetrol can still participate in development, at any time, but that right is
subject to our right to 200% reimbursement of any costs we incur after
Ecopetrol's original decision not to participate in the field's development.
The Company's future plans are dependent, among other factors, on the
receipt of various permits and licenses from ministries of the Colombian
national government and local authorities and the availability of transportation
on third party pipelines.
The continued development of the Company's evaluated properties and
evaluation of its unevaluated properties is expected to require additional
capital which the Company may be required to raise through debt or equity
financing, encumbering properties or entering into arrangements whereby certain
costs will be paid by others to earn an interest in the property. If the Company
is unsuccessful or delayed in its exploration and development plan, constructing
production and transportation facilities, increasing its proved reserves or
realizing future production from its properties, the Company may be unable to
pay existing or future debt or meet operating cash flow requirements and the
recoverability and classification of asset carrying amounts or the amount and
classification of liabilities may be impacted.
6
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CAPITAL AVAILABILITY AND LIQUIDITY
As of June 30, 2000, the Company had unrestricted cash and short-term
investments of $13.3 million and commitments under existing oil and gas
agreements of $3.2 million for the remainder of 2000. Management believes that
it has adequate cash resources to fund its existing commitments and operating
needs during 2000. However, if available capital is utilized as contemplated by
the current strategy, the Company will have to seek additional financing for
operations, including further exploratory drilling to extend the area of the
Guaduas field and to test the deeper formations of the subthrust structure on
the Dindal association contract area. Under the terms of the Company's $110
million senior notes, general indebtedness that can be senior to our senior
notes not exceeding the greater of a) $25 million, or b) the sum of 100% of our
cash and cash equivalents, 100% of our receivable from Ecopetrol, and 30% of our
discounted future net revenues from proved oil and gas reserves prepared in
accordance with the rules of the United States Securities Exchange Commission.
The Company is also allowed to borrow an additional $10 million for project
financing, e.g., pipeline and production facilities. Any additional financing
obtained by the Company to execute its business plans may result in a dilution
of current stakeholder interests.
Funds sufficient to meet interest payments for three years of the $110
million senior notes were placed into escrow upon issue of the senior notes. The
final interest payment under this escrow arrangement is May 2001. Seven Seas
cannot be certain that additional sources of financing will be available when
needed or will be available on acceptable terms. The Company has suffered
recurring losses from operations, has an accumulated deficit, has not generated
positive cash flow from operations, has significant unproved property balances,
is nearing the end of the exploration phase of its association contracts, is
dependant on the actions of Ecopetrol, and will likely require additional
capital to execute its business plans.
RISK FACTORS
Seven Seas is subject to several categories of risk associated with its
development stage activities. Oil and gas exploration and development is a
speculative business and involves a high degree of risk. Among the factors that
have a direct bearing on Seven Seas' prospects are uncertainties inherent in
estimating oil and gas reserves and future hydrocarbon production and cash
flows, particularly with respect to wells that have not been fully tested and
with wells having limited production testing histories; access to additional
capital; changes in the price of oil and natural gas, services and equipment;
the limited exploration of the concessions; the status of existing and future
contractual relationships with Ecopetrol; regulation in Colombia; lack of
significant income producing property; foreign currency fluctuation risks; Seven
Seas' substantial indebtedness, the presence of competitors with greater
financial resources and capacity; and difficulties and risks associated with
operating in Colombia.
2. BASIS OF PRESENTATION
The accompanying unaudited, condensed consolidated financial statements
include the accounts of Sevens Seas Petroleum Inc. and its subsidiaries after
elimination of intercompany balances and transactions.
The unaudited, condensed consolidated financial statements of the Company
for the periods indicated herein have been prepared by the Company pursuant to
the rules and regulations of the United States Securities and Exchange
Commission, accordingly, they do not include all of the information and
footnotes required by generally accepted accounting principles for complete
financial statements. In the opinion of management, all adjustments, consisting
of normal recurring accruals, necessary to present fairly the information in the
accompanying condensed consolidated financial statements have been included.
Interim period results are not necessarily indicative of the results of
operations or cash flows for a full year period. The condensed financial
statements included herein should be read in conjunction with the audited
financial statements and notes thereto included in the Company's Annual Report
on Form 10-K for the year ended December 31, 1999.
Certain reclassifications have been made to prior years amounts to conform
to current reporting practices.
7
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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, 2000 and 1999 and by
geographic area is shown below (In thousands):
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<CAPTION>
OTHER
UNITED FOREIGN
CANADA STATES COLOMBIA AREAS TOTAL
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Six months ended June 30, 2000
Revenues .......................... $ 974 $ 6 $ 42 $ -- $ 1,022
Operating Income (Loss) ........... (217) (1,370) (2,734) (14) (4,335)
Capital Expenditures .............. -- 70 3,503 -- 3,573
Identifiable Assets ............... 60,710 900 189,768 81 251,459
Depletion, Depreciation and
Amortization ..................... 303 160 50 -- 513
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
Three months ended June 30, 2000
Revenues...................... $ 442 $ 3 $ 9 $ -- $ 454
Operating Income (Loss)....... (219) (591) (716) (3) (1,529)
Capital Expenditures.......... -- 39 2,411 -- 2,450
Identifiable Assets........... 60,710 900 189,768 81 251,459
Depletion, Depreciation and 151 79 23 -- 253
Amortization....................
Three months ended June 30, 1999
Revenues...................... $ 734 $ 3 $ 150 $ -- $ 887
Operating Income (Loss)....... 235 (719) (3,094) (671) (4,249)
Capital Expenditures.......... -- 24 2,786 250 3,060
Identifiable Assets........... 74,068 1,147 183,402 81 258,698
Depreciation and Amortization. 151 85 23 -- 259
</TABLE>
4. CONTINGENCIES
COLOMBIAN FOREST RESERVE
The Guaduas municipality has, independently of the Colombian Ministry
of Environment, declared a forest reserve in an area that includes a portion of
the Guaduas field. This reserve would prohibit drilling. Colombian counsel has
advised us that the right to declare forest reserves is the exclusive right of
the Ministry of Environment.
Seven Seas has proposed to the municipality and the environmental
authorities that the Land Use Plan be used to resolve the illegality and
inconveniences created by the municipality declaration. The Land Use Plan, which
is proposed by the Mayor of Guaduas and approved by the City Counsel, defines,
in the medium and long term, a municipal and district land use model, indicating
its basic structure and the territorial actions necessary for its proper
organization. The plan is still being prepared and will define the land use
preferences for the next nine years. Once complete, the Land Use Plan will be
conducted from both a land planning and a soil management perspective.
In order to eliminate the difficulties posed by the municipality's
declared forest reserve, under the Land Use Plan the municipality forest reserve
must be dismissed and the Plan itself must be limited to mandating compliance
with the prior reserve declaration made by Inderena, the predecessor to the
current Ministry of Environment. The prior reserve declaration by Inderena
includes an area that encompasses a portion of the Dindal and Rio Seco
association contracts, but it does not preclude oil and gas activity.
We have been discussing this matter with representatives of the
municipal council and the mayor. 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 using the Land Use Plan could take
from three to five months and the judicial resolution could take from 18 months
to two years.
The forest reserve includes approximately 6,250 acres of our 109,000
total acreage under the Rio Seco and Dindal association contracts. However, none
of our proved oil and gas reserves or our initial test wells of the deeper
subthrust structure should be affected by the forest reserve. Further, the
existence of the forest reserve should 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 work on the El Segundo 6-E
location and access road. GHK Company Colombia performed the work and thereafter
reported to the Ministry of Environment that all the work had been completed. In
various site visits, ministry officials have confirmed that the
8
<PAGE> 9
alleged violations have been properly remedied. On July 8, 1999, GHK Company
Colombia filed all the documentation which confirmed total compliance to the
requirements.
On August 30, 1999, the Ministry of Environment issued a resolution
against GHK Company Colombia, declaring it in violation of a 1997 decree in
connection with the construction of the El Segundo 7-E well location. The
resolution imposed a fine of approximately $217,000 which we paid in March 2000.
We have filed an appeal for a reversal of the resolution. We believe that we
have corrected the environmental violations claimed by the Ministry of
Environment; however, the appeal process can take up to two years. The El
Segundo 7 location has been restored and we currently have no drilling
activities planned at this location.
CONTRACT 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 and
a five kilometer buffer zone, required at the end of the sixth year of the
Association Contract. The exploration period under the Dindal Association
Contract will be extended to September 23, 2000, since the Associates committed
to an additional $2.0 million of exploration work in accordance with the
memorandum of understanding signed with Ecopetrol in September 1999. 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.
The Rio Seco Association Contract was issued in August 1995 and provides for
a maximum six-year exploration period followed by a maximum 22-year production
period, with partial relinquishment of acreage, excluding commercial fields,
required commencing at the end of the sixth year of the Association Contract.
The exploration period under the Rio Seco Association Contract ends in August
2001. We are obligated to drill one additional exploratory well before the
exploration period ends.
Seven Seas is discussing with Ecopetrol the substitution of a well in the
Rosablanca Association Contract area for the second year seismic obligation in
the Montecristo Association Contract area. If acceptable to Ecopetrol, the
Montecristo Association Contract area would be relinquished. Results from the
well would dictate whether the Rosablanca Association Contract area would be
relinquished or another well would be drilled in order to fulfill the third year
work obligation on the Rosablanca Association Contract.
SURFACE LOCATION
A lawsuit has been filed by the landowners of the El Segundo 1 surface
location to cancel our surface lease. Our Colombian legal counsel, Gamba,
Barrera, Arriaga y Asociados, has advised us that, on the basis of the claims
asserted, we should win the lawsuit. We responded to this claim on November 4,
1999, and plan to vigorously defend this claim.
NOTEHOLDER CLAIM
A claim has been brought against Seven Seas by one of the noteholders in
connection with the Special Notes issued on August 7, 1997. The claim, which is
against Seven Seas and Yorkton Securities Inc., alleges that the noteholder was
not initially advised of the right of Seven Seas to convert the debentures into
units of common shares and warrants. The claim also alleges that there were
errors in the methodology of effecting conversion pursuant to the indenture
between Seven Seas and Montreal Trust Company of Canada dated August 7, 1997
such that the conversion was not effective. The plaintiff in the claim is
seeking damages against Seven Seas in the amount of $340,000 for negligent
misrepresentation and breach of contract or alternatively, for an order
directing Seven Seas to exchange the units currently held by the plaintiff into
a note in the amount of $340,000 payable on July 24, 2002 with interest payable
thereon at a rate of 6% per annum or directing Seven Seas to reimburse the
plaintiff in the amount of $340,000 for the purchase price of the Special Notes.
Seven Seas believes it has meritorious defenses and intends to take appropriate
steps to defend the action vigorously.
The Company is, from time to time, party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a material adverse effect on the financial position or results of
operations or cash flows of the Company.
9
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5. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 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.
Statement No. 133, as amended by Statements No. 137 and 138, is effective
for fiscal years beginning after June 15, 2000. 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, as amended, will not currently impact the Company's
disclosure or reporting.
In the first quarter of 2000, the FASB issued Interpretation No. 44
"Accounting for Certain Transactions involving Stock Compensation - an
interpretation of APB No. 25" ("the Interpretation") which clarifies the
application of APB 25 for certain issues associated with accounting for the
issuance or subsequent modification of stock compensation and is effective July
1, 2000. For certain modifications, including stock option repricings made
subsequent to December 15, 1998, the Interpretation requires that variable plan
accounting be applied to those modified awards prospectively from July 1, 2000.
In January and November, 1999, the Company repriced certain employee stock
options for 706,000 shares of stock at a weighted average exercise price of
$14.47 to a new exercise price of $9.00 through the cancellation of existing
options and issuance of new options with exercise prices at or above current
market prices. Upon adoption of this statement on July 1, 2000, the exercise
price of the repriced options exceeded the Company's stock price resulting in no
compensation expense to be recognized over future periods. Subsequent to the
adoption of the Interpretation, the Company may be required to record the
effects of the changes in its stock price and the corresponding change in
intrinsic value of the repriced options in its results of operations as
compensation expense.
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<PAGE> 11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
The following discussion and analysis should be read in conjunction with the
unaudited condensed consolidated financial statements included elsewhere and
with the Company's Annual Report on Form 10-K for the year ended December 31,
1999.
From time to time, Seven Seas may make certain statements that provide
stockholders and the investing public with "forward-looking" information (as
defined in the Private Securities Litigation Reform Act of 1995). Words such as
"anticipate," "assume," "believe," "estimate," "project," and similar
expressions are intended to identify such forward-looking statements.
Forward-looking statements may be made by management orally or in writing,
including, but not limited to, in press releases, as part of this "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
section and as part of other sections of the Company's filings with the SEC
under the Securities Act and the Securities Exchange Act. Such forward-looking
statements may include, but not be limited to, statements concerning estimates
of current and future results of operations, financial position, reserves, the
timing and commencement of wells and development plans, drilling results as
indicated by log analysis, core samples, examination of cuttings, hydrocarbons
shows while drilling and production estimates from wells drilled based upon
drill stem tests and other test data, future capacity under credit arrangements,
future capital expenditures, liquidity requirements, liquidity sufficiency and
year 2000 compliance.
Such forward-looking statements are subject to certain risks, uncertainties
and assumptions, including without limitation, those defined below. Should one
or more of these risks or uncertainties materialize, or should any of the
underlying assumptions prove incorrect, actual results of current and future
operations may vary materially from those anticipated, estimated or projected.
Among the factors that have a direct bearing on Seven Seas' results of
operations and the oil and gas industry in which it operates are uncertainties
inherent in estimating oil and gas reserves and future hydrocarbon production
and cash flows, particularly with respect to wells that have not been fully
tested and with wells having limited production testing histories; access to
additional capital; changes in the price of oil and natural gas, services and
equipment; the limited exploration of the concessions; the status of existing
and future contractual relationships with Ecopetrol; foreign currency
fluctuation risks; Seven Seas' substantial indebtedness, the presence of
competitors with greater financial resources and capacity; and difficulties and
risks associated with operating in Colombia.
OVERVIEW
Our principal asset is a 57.7% interest (before participation by Ecopetrol)
in the Dindal and Rio Seco association contracts. As of December 31, 1999, Ryder
Scott Company Petroleum Consultants estimated total proved recoverable reserves
for the Guaduas field of 154.0 million barrels of oil, of which 34.9 million
barrels of oil were attributable to our interest.
Our current plans for the use of available capital are set forth under "--
Go Forward Strategy." Whether we can achieve our objectives on schedule and with
our existing capital resources depends on a number of factors, many of which are
not within our control. Factors include timely environmental permitting,
securing pipeline rights of way, timely payments by the association contract
partners of their share of these costs and the market price of oil field
equipment and services. We will seek other sources of financing, including
project financing, industry joint ventures or arrangements with industry service
companies, commercial bank borrowings and traditional debt and equity financing.
GO FORWARD STRATEGY
In late May 2000, Ecopetrol informed us that it elected not to
participate in the development of the Guaduas field at this time and authorized
us to proceed with development on a sole-risk basis. In our 1999 Form 10-K, we
outlined three scenarios under which we planned to proceed to develop the
Guaduas field, depending on Ecopetrol's decision on commerciality. Briefly, the
three scenarios were as follows:
Scenario 1 - Ecopetrol elects to participate in the development of the Guaduas
field
Provided that we (1) received the global operating license and the
environmental pipeline permit, and (2) were able to secure financing for our
share of the development costs under Scenario 1, we estimated that we would
begin transporting Guaduas field oil production through a pipeline approximately
12 months from the date Ecopetrol approved our commerciality request.
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<PAGE> 12
Scenario 2 - Ecopetrol does not elect to participate in the development of the
Guaduas field at that time and authorizes us to proceed with the development on
a sole-risk basis
In this scenario, Seven Seas and our association contract partners
would pay 100% of the development costs and retain all revenues from production
after the 20% Colombian royalty deduction. Ecopetrol would have the right to
start participating in development at any time, subject to our right to 200%
reimbursement of our post-commerciality development costs. (When we say
"post-commerciality," we mean after the date on which Ecopetrol informed us of
its decision whether to begin paying 50% of the development costs or to allow us
to proceed on a sole-risk basis.)
To put the Guaduas field on pipeline production at 25,000 Bbls/d on a
sole-risk basis, could cost the partners approximately $61.6 million over the
course of one year or more, or $35.6 million net to Seven Seas. Of the
$61.6 million, approximately $29.7 million would be for additional development
wells, $10.5 million for production facilities, and $21.4 million for a
pipeline.
Scenario 3 - Ecopetrol does not elect to participate in developing the Guaduas
field and Seven Seas and our partners elect not to proceed on a sole-risk basis,
choosing instead to negotiate a modified agreement with Ecopetrol
This scenario would likely consist of a development plan similar to
Increment I trucking, as described in our 1998 Form 10-K, consisting of limited
production transported to a local refinery by trucking, and could result in the
postponement of a final decision on pipeline construction. Depending on oil
prices, Scenario 3 could produce cash flow for Seven Seas that could fund our
annual overhead. If we were to proceed under this scenario, our immediate
priority would be to use our existing cash resources to test the underlying
formations of the subthrust Dindal structure and to further explore the Rio Seco
and Dindal association contract areas to increase the reserves of the shallow
Guaduas field. We could possibly finance this strategy with our existing cash
resources, but we would likely seek additional financing as discussed in "--
Financing the Go Forward Strategy."
Proceeding under Scenario 2
Because Ecopetrol has informed us that it has elected not to
participate in the development of the Guaduas field at this time, Scenario 1,
described above, is no longer an option for us. Our next step is to determine,
with our Dindal and Rio Seco association contract partners, how to proceed under
Scenario 2. After determining how to proceed, we will have to finalize and
refine our development plan and our budget. Once we have a refined development
plan and a budget, we will attempt to secure financing for our share of the
development costs. Our plans to proceed under Scenario 2 will be subject to:
o an agreement with our partners on how to proceed on a
sole-risk basis, and
o our ability to secure financing for our share of the
development costs.
If Seven Seas and our association contract partners elect to proceed
with the development of the Guaduas field on a sole-risk basis, but we are
unable to finance all of our share of the development costs, we will seek to
proceed with the construction of a pipeline and postpone most of the development
drilling until we can pay our share of the development drilling out of cash flow
from production. We can fund our share of the pipeline construction with our
current working capital. Without any new development drilling, we expect the
Guaduas field to produce approximately 10,000 Bbls/d, or 4,600 Bbls/d net to
Seven Seas.
If Seven Seas and our contract partners elect not to proceed with the
development of the Guaduas field on a sole-risk basis, we will pursue Scenario
3.
In addition to the plans to develop the Guaduas field under Scenario 2,
we have tentative plans to drill the Tres Pasos 16 well on the west-side of the
Guaduas field. Pursuant to our agreement with Ecopetrol, we plan to re-drill the
El Segundo 6-E before September 2000.
We also have tentative plans to begin drilling the subthrust
exploration well in 2000 depending upon:
o the finalized and refined development plan and budget
that we agree upon with our association contract
partners for the Guaduas field,
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<PAGE> 13
o our ability to finance our share of the agreed
development costs and the subthrust exploration well
costs, and
o receiving a new contract from Ecopetrol that will
provide more favorable contract terms for the
subthrust Dindal prospect.
In July 2000 we received the required environmental pipeline permit and
the global operating license. In August 2000 the Colombian Ministry of Mines and
Energy granted the final approval that was required for commercial production.
Accordingly, during the first week in August 2000, we began producing from the
Guaduas field.
FINANCING THE GO FORWARD STRATEGY
If our partners agree with us to proceed under Scenario 2, we will have
to seek additional financing for our share of the Guaduas field development
costs, as well as for future operations, including exploratory drilling to test
the deeper formations of the subthrust structure and extending the area of the
Guaduas field. Sustained pipeline production of 20,000 Bbls/d to 30,000 Bbls/d
will require additional development drilling of the shallow Cimarrona reservoir,
additional production facilities and construction of a pipeline. We estimate
these costs to be approximately $61.6 million, or $35.6 million net to Seven
Seas over the course of one year or more. Possible additional sources of
financing are:
o project financing of the pipeline;
o industry joint ventures or other similar arrangements
with industry service or supply companies;
o commercial bank borrowing;
o debt and equity financing; and
o forward sale of oil.
Under the terms of our $110 million senior notes, we are allowed to
incur general indebtedness that can be senior to our senior notes not exceeding
the greater of a) $25 million, or b) the sum of 100% of our cash and cash
equivalents, 100% of our receivable from Ecopetrol, and 30% of our discounted
future net revenues from proved oil and gas reserves prepared in accordance with
the rules of the United States Securities Exchange Commission. We could, for
example, secure this additional indebtedness with our existing proved reserves.
We are also allowed to borrow an additional $10 million for project financing,
such as for the pipeline and production facilities.
In our 1999 Form 10-K, we indicated that it will be difficult, but not
impossible, for us to proceed "sole-risk" and finance the approximately $35.6
million needed to fund our net development costs. We believe we can proceed to
develop the Guaduas field under Scenario 2 for the following reasons:
o The $35.6 million of development costs will be spread
out over a period of one year or more;
o During the period in which we are incurring a portion
of the $35.6 million development costs, we will be
generating early cash flow by trucking from 4,000
Bbls/d to 6,000 Bbls/d; and
o To accommodate our financial needs, we can refine our
development plan in such a way that we can increase
production levels from the initial production rates
of 4,000 to 6,000 barrels a day with limited capital
requirements. We could, for instance, proceed with
the construction of the pipeline and delay drilling
any additional wells. With our current productive
wells, a newly constructed pipeline, and additional
production facilities, we estimate that we could
produce approximately 10,000 Bbls/d, generating
substantial cash flow to finance additional
development drilling in years two and three of
development.
Provided we can secure financing timely, we will proceed to develop the
Guaduas field as originally planned on a sole-risk basis, and estimate that we
can drill additional wells and achieve pipeline production of between 20,000
Bbls/d to 30,000 Bbls/d within approximately 12 months from the date we agree to
a development plan with the association contract partners and secure such
financing. We cannot be certain that additional sources of financing will be
available when needed or will be available on acceptable terms.
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<PAGE> 14
LIQUIDITY AND CAPITAL RESOURCES
Working capital
We had working capital, net of restricted investments and related
interest payable of $17.9 million, including unrestricted cash and short-term
investments of $13.3 million as of June 30, 2000. Our non-discretionary capital
commitments from June 30, 2000 are approximately $3.2 million, of which $1.0
million will be used to conduct seismic or substitute operations on the
Rosablanca block to satisfy the second year work obligation on the Montecristo
block. We also plan to use our available cash as set forth under "-- Financing
the Go Forward Strategy."
Equity and financing activities
As of August 10, 2000, we had 37,836,420 common shares, no par value,
outstanding, of which none are restricted. At June 30, 2000, we had outstanding
$110.0 million of 12 1/2% senior notes due May 15, 2005. In accordance with the
terms of the senior notes, we were required to hold in a separate account or in
escrow monies to provide for the first three years of interest payable under the
senior notes. We purchased $13.5 million in U.S. government securities from the
proceeds of the senior notes and deposited the securities in a segregated
account. The amount deposited into the segregated account was enough to pay the
first two interest payments. We also purchased and pledged $25 million of U.S.
government securities to ensure payment of the four scheduled interest payments
on the notes from November 15, 1999 through May 15, 2001. At June 30, 2000,
after making four interest payments, we had $13.3 million in U.S. government
securities remaining, which is sufficient to pay interest on the senior notes
through May 2001.
Our activities from inception through June 30, 2000 were funded
primarily by the proceeds from private placements of our securities, including
our common shares, warrants and notes, resulting in aggregate cash proceeds of
$157.0 million. Recent transactions include:
o Exchangeable Notes. In August 1997, we issued $25.0
million of 6% exchangeable notes in a private
transaction with institutional and accredited
investors. The exchangeable notes accrued interest at
a rate of 6% per annum and were payable on December
31 and June 30 in each year. The exchangeable notes
were scheduled to mature on August 7, 2003.
o Convertible Debentures. The exchangeable notes were
exchanged for a like principal amount of 6%
convertible debentures on August 5, 1998. The 6%
convertible debentures were converted on August 6,
1998 into units consisting of 2,173,901 common shares
and warrants exercisable for 1,086,957 common shares.
o Purchase Warrants. On February 5, 1999, purchase
warrants for $1.1 million of our common shares
expired without exercise. We received proceeds of
$0.3 million from the exercise of 18,913 warrants.
These purchase warrants had been issued in
association with the exchange and conversion of our
previously outstanding $25.0 million issue of 6%
exchangeable notes.
o Senior Notes. In May 1998, we completed the offering
of $110 million of 12 1/2% senior notes due May 15,
2005 and received net proceeds of approximately $106
million. Approximately $37.8 million of the proceeds
was held in a separate account or in escrow to
provide for the first three years of interest payable
under the senior notes. Interest on the senior notes
is payable semi-annually on May 15 and November 15 of
each year. The escrow account is sufficient to pay
interest through May 2001. The senior notes mature on
May 15, 2005. The senior notes are redeemable at our
option, in whole or in part, at any time on or after
May 15, 2002, at the prescribed redemption price,
plus accrued and unpaid interest, liquidated damages
and additional amounts, if any, to the date of
redemption.
At any time prior to May 15, 2001, we may redeem up to 33 1/3% of the
original aggregate principal amount of the senior notes at a redemption price of
112.50% of the principal amount redeemed with a portion of the net proceeds of
an equity or strategic investor offering, provided that at least 66 2/3% of the
original aggregate principal amount of the senior notes remains outstanding
immediately after the redemption. In the event of certain changes affecting
withholding taxes applicable to certain payments on the senior notes, the senior
notes may be redeemed at our option, in whole but not in part, at any time at a
redemption price equal to 100%
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<PAGE> 15
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 are ranked
equally in right and priority of payment with all of our existing and future
senior indebtedness.
If our cash flow from operations is not sufficient to pay principal and
interest on our debt when due, we would have to attempt to restructure or
refinance the debt or sell assets to obtain funds.
Capital spending
From inception through June 30, 2000, we had cash expenditures for the
exploration of oil and gas properties of $112.2 million.
Commitments
Our non-discretionary capital commitments since June 30, 2000 are
approximately $3.2 million, of which $2.0 million will be used to re-drill the
El Segundo 6-E on the Guaduas field and $1.0 million to conduct seismic or
substitute operations for the second year Montecristo block work obligation.
Planned capital expenditures
To put the Guaduas field on pipeline production at 25,000 Bbls/d, we
estimate capital expenditures will total $61.6 million ($35.6 million net to
Seven Seas). Additionally, we could drill exploration wells for an estimated
$23.9 million ($13.1 net to Seven Seas).
Our estimated capital expenditures assume that each of the associates
in the association contracts approves and pays its proportionate share of
capital expenditures.
Debt service costs
Under the terms of our 12 1/2% Senior Notes, we have to pay semi-annual
interest payments of $6.9 million on May 15 and November 15. The $110 million in
principal is due May 15, 2005.
ACCOUNTING POLICIES AND DEVELOPMENT STAGE ACCOUNTING
The unaudited, condensed, consolidated financial statements included herein
have been prepared by Seven Seas pursuant to the rules and regulations of the
Securities and Exchange Commission, accordingly, they do not include all of the
information and footnotes required by generally accepted accounting principles
for complete financial statements.
Our exploration and development activities have not generated a substantial
amount of revenue, thus requiring the financial statements to be presented as a
development stage enterprise. Accumulated losses are presented on the balance
sheet as "Deficit accumulated during development stage." The income statement
presents revenues and expenses for each period presented and also a cumulative
total of both amounts from our inception. Period-to-period comparisons of such
results and certain financial data may not
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<PAGE> 16
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. No general and administrative costs were capitalized during 2000,
1999, and 1998. We capitalized interest of $6.9 million and $6.9 million for the
six months ended June 30, 2000 and 1999, respectively.
The capitalized costs of oil and gas properties in each cost center are
amortized on the composite units of production method based on future gross
revenues from proved reserves. Sales or other dispositions of oil and gas
properties are normally accounted for as adjustments of capitalized costs. Gain
or loss is not recognized in income unless a significant portion of a cost
center's reserves 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.
RESULTS OF DEVELOPMENT STAGE OPERATIONS
THREE MONTHS ENDED JUNE 30, 2000 AND 1999
Revenues from oil sales were zero and $0.1 million for the quarters ended
June 30, 2000 and 1999, respectively. Lease operating expenses were $0.4 million
and $1.1 million for the quarters ended June 30, 2000 and 1999, respectively.
The lease operating costs recorded during the quarter ended June 30, 2000
related to various pressure testing and geologic studies of the reservoir. The
revenue and costs for the quarter ended June 30, 1999 related to the testing of
the Tres Pasos 1-W horizontal well.
Oil production in Colombia (net to us, including minority interest through
June 30, 1999) of zero barrels and 11,946 barrels for the quarters ended June
30, 2000 and 1999, respectively, pertaining solely to our share of oil produced
from production testing, was sold to Refinerie del Nare at an average price of
$9.54 per barrel in 1999.
Interest income was $0.5 million and $0.8 million for the quarters ended
June 30, 2000 and 1999, respectively. The decrease from 1999 to 2000 was the
consequence of lower cash and investment balances resulting from the use of
funds from the issuance of the senior notes in May 1998.
General and administrative costs were $1.3 million and $3.1 million for the
quarters ended June 30, 2000 and 1999, respectively. The $1.8 million decrease
in general and administrative expenses from the quarter ended June 30, 1999 to
the quarter ended June 30, 2000 was primarily attributable to a $0.4 million
decrease in personnel costs, including salaries, benefits, travel, rents,
insurance, and security due to decreased personnel in both the United States
and Colombia and a $0.6 million decrease in contractors, security,
environmental, and legal costs resulting from a reduction in oil and gas
operations in Colombia. In addition, severance costs relating reduction in
personnel were approximately $0.4 million during the second quarter of 1999.
Depletion, depreciation and amortization were $0.3 million and $0.3 million
for the quarters ended June 30, 2000 and 1999, respectively.
As required under the full cost method of accounting, capitalized costs are
limited to the sum of (1) the present value of future net revenues, using
current unescalated pricing and discounted at 10% per annum from proved reserves
and (2) the lower of cost or estimated fair value of unevaluated properties, all
net of expected income tax effects. There was no write-down to date in 2000
or 1999.
Seven Seas incurred net losses of $1.5 million and $3.8 million for the
quarters ended June 30, 2000 and 1999, respectively.
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<PAGE> 17
SIX MONTHS ENDED JUNE 30, 2000 AND 1999
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 $16,000 and $0.2
million for the six months ended June 30, 2000 and 1999, respectively. Oil and
gas operating expenses were $1.0 million and $1.5 million for the six months
ended June 30, 2000 and 1999, respectively. The 2000 costs relate to the long
term testing program, primarily the El Segundo 4-E well as well as various
pressure testing and geologic studies of the reservoir. The 1999 costs related
to the long term production testing of the Tres Pasos 1-W horizontal well.
Oil production in Colombia (net to the Company, including minority interest
through June 30, 1999) of 1,185 barrels and 23,564 for the six months ended June
30, 2000 and 1999, respectively, pertaining solely to the Company's share of oil
produced from production testing, was sold to Refinerie del Nare at an average
price of $13.76 per barrel in 2000 and $8.66 per barrel in 1999. The Tres Pasos
1-W horizontal production testing was completed in May 1999.
Interest income was $1.0 million and $1.7 million for the six months ended
June 30, 2000 and 1999, respectively. The decrease from 1999 to 2000 was the
consequence of lower cash and investment balances resulting from the use of
funds from the issuance of the senior notes in May 1998.
General and administrative costs were $3.7 million and $4.6 million for the
six months ended June 30, 2000 and 1999, respectively. The $0.9 million decrease
in general and administrative expenses from the six month period ended June 30,
1999 to the six month period ended June 30, 2000 was primarily attributable to a
$0.6 million decrease in personnel costs, including salaries, benefits, travel,
rents, insurance, and security due to decreased personnel in both the United
States and Colombia and a $0.7 million decrease in contractors, security, and
legal costs resulting from a reduction in oil and gas operations in Colombia.
These cost reductions were offset by $0.8 million in severance payments made
during the first quarter of 2000 in conjunction with the Company's cost
reduction plan. The Company's continuing cost reduction plan is aimed at
determining the proper number of employees to handle the current level of
operations; however, the Company has no intentions of reducing its oil and gas
operations as a result of this effort. The Company first began its continuing
cost reduction plan in May 1999, when 17 Colombian nationals, whose roles were
primarily administrative in nature, were released. This resulted in severance
payments of $0.2 million during the second quarter of 1999. In addition to these
severance payments, the Company incurred an additional $0.2 million in
termination payments to an executive in this period. During the first quarter of
2000, 17 employees and 29 contractors, working in administrative or support
roles in the Company's Bogota office, were identified for separation and
notified of the Company's intent. As of June 30, 2000, 45 of the 46 people had
been released. The reduction plan resulted in $0.8 million in severance expense
during the first quarter of 2000, of which $0.6 million had been paid at March
31, 2000. The remaining $0.2 million was paid during the second quarter of 2000.
The Company expects to recognize $0.5 million in savings, after severance costs,
from the reduction in personnel costs during 2000. No additional reductions in
personnel are planned.
Depletion, depreciation and amortization was $0.5 million and $0.5 million
for the six months ended June 30, 2000 and 1999, respectively.
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, 2000 and 1999, respectively.
The Company incurred net losses of $4.3 million and $4.9 million for the six
months ended June 30, 2000 and 1999, respectively.
TAXES
Our net income, as defined under Colombian law, from Colombian sources, is
subject to Colombian corporate income tax at a rate of 35%. An additional
remittance tax is imposed upon remittance of profits abroad at a rate of 7%.
The Company is also subject to income taxes in Canada and the United States,
where the statutory rates were 45% and 35% respectively.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risk, including adverse changes in commodity
prices, interest rates and foreign currency exchange rates as discussed below.
COMMODITY RISK
We have faced minimal risk from commodity pricing because of the small
amounts of oil and gas produced to date. Realized commodity prices received for
such production are primarily driven by the prevailing worldwide price for crude
oil and spot prices applicable to natural gas. The effects of such pricing are
expected to be minor until such time as we produce commercial quantities of oil
and gas.
INTEREST RATE RISK
We consider our interest rate risk exposure to be minimal as a result of a
fixed interest rate on the $110 million 12 1/2% Senior Notes. We currently have
no open interest rate swap agreements.
FOREIGN CURRENCY EXCHANGE RATE RISK
We conduct business in several foreign currencies and are subject to foreign
currency exchange rate risk on cash flows related to sales, expenses and capital
expenditures. However, because predominately all transactions in our existing
foreign operations are denominated in U.S. dollars, the U.S. dollar is the
functional currency for all operations. Exposure from transactions in currencies
other than the U.S. dollars is not material.
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on 8-K
(a) Exhibits
3 -- Articles of Incorporation and By-laws
*(A) -- The Amalgamation Agreement effective June 29, 1995 by and between
Seven Seas Petroleum Inc., a British Columbia corporation; and Rusty
Lake Resources Ltd.
*(B) -- Certificate of Continuance and Articles of Continuance into the
Yukon Territory
*(C) -- By-Laws
27 - Financial Data Schedule
----------
* Incorporated herein by reference to like exhibit in Registration on Form 10
(File No. 022483).
(b) Reports on From 8-K
None
SIGNATURES
Seven Seas Petroleum Inc.
Date: August 14, 2000 By: Larry A. Ray, Executive Vice President, Chief
Operating Officer, Chief Financial Officer, and
Corporate Secretary
Sir Mark Thomson, Bt. President
18
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INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
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
</TABLE>
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* Incorporated herein by reference to like exhibit in Registration on Form 10
(File No. 022483).
