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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
AMENDMENT NO. 1
(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
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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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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
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 (518) (178)
Inventory (9) -- (1,325)
Prepaids and other, net 121 11 (104)
Accounts payable (2,823) (1,439) 797
Other accrued liabilities (233) (92) 346
--------- --------- ---------
Cash Flow Used in Operating Activities (5,161) (2,632) (24,448)
--------- --------- ---------
INVESTING ACTIVITIES
Exploration of oil and gas properties (18,135) (20,759) (88,390)
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 (5,731) (59,810) (115,573)
--------- --------- ---------
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 28,641
Cash and cash equivalents, beginning of period 38,147 18,067 --
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 28,641 $ 67,849 $ 28,641
========= ========= =========
</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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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 cash
expenditures for the acquisition, exploration, and development of its oil and
gas properties of $88.4 million.
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. 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.
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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 Refinerie del Nare or 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.
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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 23,564 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 Refinerie del Nare or 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.
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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: April 13, 1999 By: Larry A. Ray
Executive Vice President, Chief Operating
Officer and Chief Financial Officer
Sir Mark Thomson, Bt.
President
14
