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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Form 10-Q
(X) Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 for the quarterly period ended September 30, 2002.
(_) Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.
Commission file number 001-16009
SPINNAKER EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 76-0560101
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
1200 Smith Street, Suite 800
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 759-1770
(Registrant's telephone number, including area code)
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 ____
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The number of shares outstanding of the registrant's common stock, par
value $0.01 per share, on November 12, 2002 was 33,170,740.
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SPINNAKER EXPLORATION COMPANY
Form 10-Q
For the Three and Nine Months Ended September 30, 2002
Page
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets
September 30, 2002 (unaudited) and December 31, 2001 ...................... 3
Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2002 and 2001 (unaudited) ....... 4
Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2002 and 2001 (unaudited) ................. 5
Notes to Interim Consolidated Financial Statements (unaudited) ............. 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations ................................ 10
Item 3. Quantitative and Qualitative Disclosures About Market Risk ........... 19
Item 4. Controls and Procedures .............................................. 20
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K ..................................... 20
SIGNATURES .................................................................... 21
2
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
September 30, December 31,
2002 2001
------------- ------------
ASSETS (Unaudited)
CURRENT ASSETS:
Cash and cash equivalents ............................................................. $ 36,285 $ 14,061
Accounts receivable, net of allowance for doubtful accounts of $3,187 at
September 30, 2002 and $3,059 at December 31, 2001, respectively .................... 42,438 24,129
Hedging assets ........................................................................ 23 20,593
Other ................................................................................. 9,239 3,664
---------- ----------
Total current assets .............................................................. 87,985 62,447
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties ................................................................... 819,269 575,806
Unproved properties and properties under development, not being amortized ........... 140,259 102,881
Other ................................................................................. 13,817 7,245
---------- ----------
973,345 685,932
Less - Accumulated depreciation, depletion and amortization ........................... (235,474) (163,359)
---------- ----------
Total property and equipment ...................................................... 737,871 522,573
OTHER ASSETS ............................................................................. 374 2,296
---------- ----------
Total assets ...................................................................... $ 826,230 $ 587,316
========== ==========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable ...................................................................... $ 27,904 $ 32,383
Accrued liabilities and other ......................................................... 46,957 50,718
Hedging liabilities ................................................................... 10,202 -
---------- ----------
Total current liabilities ......................................................... 85,063 83,101
OTHER LIABILITIES ........................................................................ 2,455 -
DEFERRED INCOME TAXES .................................................................... 53,903 45,723
COMMITMENTS AND CONTINGENCIES
EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued
and outstanding at September 30, 2002 and December 31, 2001, respectively ........... - -
Common stock, $0.01 par value; 50,000,000 shares authorized; 33,181,065 shares
issued and 33,167,561 shares outstanding at September 30, 2002 and 27,308,912
shares issued and 27,293,264 shares outstanding at December 31, 2001 ................ 332 273
Additional paid-in capital ............................................................ 595,952 365,993
Retained earnings ..................................................................... 96,702 77,758
Less: Treasury stock, at cost, 13,504 and 15,648 shares at September 30, 2002 and
December 31, 2001, respectively ..................................................... (34) (39)
Accumulated other comprehensive income (loss) ......................................... (8,143) 14,507
---------- ----------
Total equity ...................................................................... 684,809 458,492
---------- ----------
Total liabilities and equity ...................................................... $ 826,230 $ 587,316
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
3
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
--------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ---------- -----------
REVENUES ............................................. $ 51,558 $ 44,818 $ 121,322 $ 171,771
EXPENSES:
Lease operating expenses .......................... 5,237 3,309 12,380 9,312
Depreciation, depletion and amortization -
natural gas and oil properties .................. 31,929 23,009 70,537 63,329
Depreciation and amortization - other ............. 246 131 629 333
General and administrative ........................ 2,976 2,219 8,387 6,969
Charges related to Enron bankruptcy ............... 128 - 128 -
----------- ----------- ---------- ----------
Total expenses ................................ 40,516 28,668 92,061 79,943
----------- ----------- ---------- ----------
INCOME FROM OPERATIONS ............................... 11,042 16,150 29,261 91,828
OTHER INCOME (EXPENSE):
Interest income ................................... 272 777 936 3,371
Interest expense .................................. (148) (48) (597) (306)
----------- ----------- ---------- ----------
Total other income (expense) .................. 124 729 339 3,065
----------- ----------- ---------- ----------
INCOME BEFORE INCOME TAXES ........................... 11,166 16,879 29,600 94,893
Income tax provision ................................. 4,020 6,076 10,656 34,161
----------- ----------- ---------- ----------
NET INCOME ........................................... $ 7,146 $ 10,803 $ 18,944 $ 60,732
=========== =========== ========== ==========
NET INCOME PER COMMON SHARE:
Basic ............................................. $ 0.22 $ 0.40 $ 0.61 $ 2.25
=========== =========== ========== ==========
Diluted ........................................... $ 0.21 $ 0.38 $ 0.59 $ 2.14
=========== =========== ========== ==========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
Basic ............................................. 33,160 27,172 31,198 27,027
=========== =========== ========== ==========
Diluted ........................................... 34,038 28,335 32,118 28,314
=========== =========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
4
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
For the Nine Months
Ended September 30,
-------------------------
2002 2001
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................................................ $ 18,944 $ 60,732
Adjustments to reconcile net income to net cash provided by (used in) operating
activities:
Depreciation, depletion and amortization ................................................ 71,166 63,662
Deferred income tax expense ............................................................. 10,956 34,161
Other ................................................................................... 610 (81)
Change in components of working capital:
Accounts receivable ................................................................... (18,309) 15,959
Accounts payable and accrued liabilities .............................................. 7,074 24,565
Other current assets and other ........................................................ (1,983) 1,641
--------- ---------
Net cash provided by operating activities ......................................... 88,458 200,639
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties ....................................................... (287,998) (230,161)
Purchases of other property and equipment ................................................. (6,572) (1,042)
Purchases of short-term investments ....................................................... - (29,627)
Sales of short-term investments ........................................................... - 49,042
--------- ---------
Net cash used in investing activities ............................................. (294,570) (211,788)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings .................................................................. 37,000 -
Payments on borrowings .................................................................... (37,000) -
Proceeds from issuance of common stock .................................................... 227,873 -
Common stock issuance costs ............................................................... (489) -
Proceeds from exercise of stock options ................................................... 952 6,122
--------- ---------
Net cash provided by financing activities ......................................... 228,336 6,122
--------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ....................................... 22,224 (5,027)
CASH AND CASH EQUIVALENTS, beginning of year ............................................... 14,061 63,910
--------- ---------
CASH AND CASH EQUIVALENTS, end of period ................................................... $ 36,285 $ 58,883
========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized ........................................ $ 392 $ 171
Cash paid for income taxes ................................................................ $ - $ -
The accompanying notes are an integral part of these consolidated financial
statements.
5
SPINNAKER EXPLORATION COMPANY
Notes to Interim Consolidated Financial Statements (Unaudited)
September 30, 2002
1. Basis of Presentation
The accompanying unaudited consolidated financial statements of Spinnaker
Exploration Company ("Spinnaker" or the "Company") have been prepared in
accordance with generally accepted accounting principles for interim financial
information and the instructions to Form 10-Q and Article 10 of Regulation S-X.
Accordingly, they do not include all of the information and footnotes required
by accounting principles generally accepted in the United States for complete
financial statements. In the opinion of management, all adjustments (consisting
only of normal and recurring adjustments) necessary to present a fair statement
of the results for the periods included herein have been made and the
disclosures contained herein are adequate to make the information presented not
misleading. Interim period results are not necessarily indicative of results of
operations or cash flows for a full year. These consolidated financial
statements and the notes thereto should be read in conjunction with the
Company's Annual Report on Form 10-K for the year ended December 31, 2001.
2. Earnings Per Share
The basic and diluted net income per common share calculations are based on
the following information (in thousands, except per share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- ----------------------
2002 2001 2002 2001
-------- -------- -------- ---------
Numerator:
Net income ............................................... $ 7,146 $ 10,803 $ 18,944 $ 60,732
======== ======== ======== =========
Denominator:
Basic weighted average number of shares .................. 33,160 27,172 31,198 27,027
======== ======== ======== =========
Dilutive securities:
Stock options .......................................... 878 1,163 920 1,287
-------- -------- -------- ---------
Diluted adjusted weighted average number of shares and
assumed conversions .................................... 34,038 28,335 32,118 28,314
======== ======== ======== =========
Net income per common share:
Basic .................................................... $ 0.22 $ 0.40 $ 0.61 $ 2.25
======== ======== ======== =========
Diluted .................................................. $ 0.21 $ 0.38 $ 0.59 $ 2.14
======== ======== ======== =========
3. Credit Facility
On December 28, 2001, the Company replaced its $75.0 million credit
facility with an unsecured $200.0 million credit facility ("Credit Facility")
with a group of seven banks. The borrowing base of the three-year Credit
Facility is re-determined on or about April 30 and September 30 each year. The
banks and Spinnaker also have the option to request one additional
re-determination each year. The borrowing base is determined by the banks, in
their usual and customary manner, and at their sole discretion. The amount of
the borrowing base is a function of the banks' view of the Company's reserve
profile as well as commodity prices. The current borrowing base is $100.0
million. The Company has the option to elect to use a base interest rate as
described below or the LIBOR rate plus, for each such rate, a spread based on
the percent of the borrowing base used at that time. The base interest rate
under the Credit Facility is a fluctuating rate of interest equal to the higher
of either Toronto-Dominion Bank's base rate for dollar advances made in the
United States or the Federal Funds Rate plus 0.5 percent per annum. The
commitment fee rate ranges from 0.3 percent to 0.5 percent, depending on the
borrowing base usage. The Credit Facility contains various covenants and
restrictive provisions. At September 30, 2002, the Company was in compliance
with the covenants and restrictive provisions and expects to remain in
compliance through December 31, 2002. As of November 12, 2002, the Company had
no outstanding borrowings under the Credit Facility.
6
4. Equity Offering
On April 3, 2002, the Company completed a public offering of 5,750,000
shares of common stock, par value $0.01 per share ("Common Stock"), at $41.50
per share, including the over-allotment option consisting of 750,000 shares.
After payment of underwriting discounts and commissions, the Company received
net proceeds of $227.9 million. On April 3, 2002, the Company used a portion of
the proceeds from the offering to repay outstanding borrowings of $37.0 million.
The remaining net proceeds were invested in short-term high quality investments
and are being used to fund a portion of the costs to develop the Company's deep
water oil discovery at Green Canyon Blocks 338/339 ("Front Runner"), to fund a
portion of exploration and other development activities and for general
corporate purposes, including possible acquisitions of properties or seismic
data.
5. Derivatives and Hedging
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 133, as amended, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 133 established accounting and reporting
standards requiring that all derivative instruments be recorded in the balance
sheet as either an asset or liability measured at its fair value. SFAS No. 133
requires that changes in a derivative's fair value be realized currently in
earnings unless specific hedge accounting criteria are met. Accounting for
qualifying hedges allows derivative gains and losses to offset related results
on the hedged items in the statement of operations and requires a company to
formally document, designate and assess the effectiveness of transactions that
qualify for hedge accounting.
The Company enters into New York Mercantile Exchange ("NYMEX") related swap
contracts and collar arrangements from time to time. The Company's swap
contracts and collar arrangements will settle based on the reported settlement
price on the NYMEX for the last trading day of each month for natural gas.
In a swap transaction, the counterparty is required to make a payment to
the Company for the difference between the fixed price and the settlement price
if the settlement price is below the fixed price. The Company is required to
make a payment to the counterparty for the difference between the fixed price
and the settlement price if the settlement price is above the fixed price. As of
September 30, 2002, Spinnaker's commodity price risk management positions in
fixed price natural gas swap contracts and related fair value were as follows:
Average Weighted
Daily Average
Volume Price Fair Value
Period (MMBtus) (Per MMBtu) (in thousands)
------------------------------- -------------- -------------- --------------
Fourth Quarter 2002 .......... 106,685 $ 3.68 $ (3,510)
First Quarter 2003 ........... 60,000 3.71 (2,558)
Second Quarter 2003 .......... 53,297 3.55 (1,978)
Third Quarter 2003 ........... 50,000 3.55 (2,001)
Fourth Quarter 2003 .......... 50,000 3.63 (2,223)
--------------
Total ................... $ (12,270)
==============
7
In a collar arrangement, the counterparty is required to make a payment to
the Company for the difference between the fixed floor price and the settlement
price if the settlement price is below the fixed floor price. The Company is
required to make a payment to the counterparty for the difference between the
fixed ceiling price and the settlement price if the settlement price is above
the fixed ceiling price. Neither party is required to make a payment if the
settlement price falls between the fixed floor price and the fixed ceiling
price. As of September 30, 2002, Spinnaker's commodity price risk management
positions in natural gas collar arrangements and related fair value were as
follows:
Average Weighted Weighted
Daily Average Average
Volume Floor Price Ceiling Price Fair Value
Period (MMBtu) (Per MMBtu) (Per MMBtu) (in thousands)
------------------------------- ----------- --------------- --------------- --------------
First Quarter 2003 ......... 15,000 $ 3.25 $ 5.21 $ (281)
Second Quarter 2003 ........ 15,000 3.25 5.21 102
Third Quarter 2003 ......... 15,000 3.25 5.21 48
Fourth Quarter 2003 ........ 15,000 3.25 5.21 (233)
--------------
Total ................. $ (364)
==============
The Company reported a net liability of $12.6 million related to its
derivative contracts at September 30, 2002. The components of the net liability
were as follows (in thousands):
As of As of
September 30, December 31,
2002 2001
------------- ------------
Current:
Hedging asset ............................. $ 23 $ 20,593
Hedging liability ......................... 10,202 -
Non-current:
Hedging asset ............................. $ - $ 1,726
Hedging liability ......................... 2,455 -
The Company also reported a loss in accumulated other comprehensive income
of $8.1 million, net of income taxes of $4.4 million. The ineffective component
of the derivatives recognized in earnings was a loss less than $0.1 million in
the first nine months of 2002.
In connection with monthly settlements, the Company recognized net hedging
gains of $1.2 million and $7.7 million in revenues in the third quarter and
first nine months of 2002, respectively. Based on future natural gas prices as
of September 30, 2002, the Company would reclassify a net loss of $10.2 million
from accumulated other comprehensive income (loss) to earnings within the next
twelve months. The amounts ultimately reclassified into earnings will vary due
to changes in the fair value of the open derivative contracts prior to
settlement.
Subsequent to September 30, 2002, Spinnaker entered into additional swap
contracts for the fourth quarter of 2002. Spinnaker's current commodity price
risk management positions in fixed price natural gas swap contracts and the
related fair values, using natural gas forward prices as of November 11, 2002
and including October and November 2002 settlements paid to counterparties of
$2.0 million were as follows:
Average Weighted
Daily Average
Volume Price Fair Value
Period (MMBtu) (Per MMBtu) (in thousands)
--------------------------- --------- ------------ --------------
Fourth Quarter 2002 ........ 113,315 $ 3.71 $ (1,592)
First Quarter 2003 ......... 60,000 3.71 (843)
Second Quarter 2003 ........ 53,297 3.55 (857)
Third Quarter 2003 ......... 50,000 3.55 (1,013)
Fourth Quarter 2003 ........ 50,000 3.63 (1,474)
--------------
Total ................. $ (5,779)
==============
8
Spinnaker's current commodity price risk management positions in natural
gas collar arrangements as of November 11, 2002 were as follows:
Average Weighted Weighted
Daily Average Average
Volume Floor Price Ceiling Price
Period (MMBtu) (Per MMBtu) (Per MMBtu)
--------------------------------------- ----------- ------------- --------------
First Quarter 2003 .................. 15,000 $ 3.25 $ 5.21
Second Quarter 2003 ................. 15,000 3.25 5.21
Third Quarter 2003 .................. 15,000 3.25 5.21
Fourth Quarter 2003 ................. 15,000 3.25 5.21
6. Comprehensive Income
The following are components of comprehensive income (loss) (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Net income ...................................................... $ 7,146 $ 10,803 $ 18,944 $ 60,732
Other comprehensive income (loss), net of tax:
Cumulative effect of accounting change for derivative
financial instruments ...................................... - - - (27,126)
Net change in fair value of derivative financial
instruments ................................................ (7,360) 17,128 (3,209) 32,298
Financial derivative settlements taken to income, net of
tax ........................................................ (784) (1,640) (4,935) 10,317
-------- -------- -------- --------
Comprehensive income (loss) ..................................... $ (998) $ 26,291 $ 10,800 $ 76,221
======== ======== ======== ========
7. New Accounting Principle
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires
that the fair value of a liability for an asset retirement obligation be
recognized in the period in which it is incurred with the associated asset
retirement costs being capitalized as a part of the carrying amount of the
long-lived asset. SFAS No. 143 also includes disclosure requirements that
provide a description of asset retirement obligations and reconciliation of
changes in the components of those obligations. The Company currently records
its plugging and abandonment costs, net of salvage value, with respect to its
natural gas and oil properties as depreciation, depletion and amortization
expense ("DD&A") using the units-of-production method. This statement will
require the Company to recognize a liability for the fair value of its plugging
and abandonment liability, excluding salvage value, with the associated costs as
part of its natural gas and oil property balance. The Company is still
evaluating the future financial effects of adopting SFAS No. 143 and will adopt
the standard effective January 1, 2003.
9
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Cautionary Statement About Forward-Looking Statements
Some of the information in this quarterly report on Form 10-Q contains
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The
forward-looking statements speak only as of the date made, and the Company
undertakes no obligation to update such forward-looking statements. These
forward-looking statements may be identified by the use of the words "believe,"
"expect," "anticipate," "will," "contemplate," "would" and similar expressions
that contemplate future events. These future events include the following
matters:
. financial position;
. business strategy;
. budgets;
. amount, nature and timing of capital expenditures, including future
development costs;
. drilling of wells;
. natural gas and oil reserves;
. timing and amount of future production of natural gas and oil;
. operating costs and other expenses;
. cash flow and anticipated liquidity;
. prospect development and property acquisitions; and
. marketing of natural gas and oil.
Numerous important factors, risks and uncertainties may affect the
Company's operating results, including:
. the risks associated with exploration;
. delays in anticipated start-up dates;
. the ability to find, acquire, market, develop and produce new
properties;
. natural gas and oil price volatility;
. uncertainties in the estimation of proved reserves and in the
projection of future rates of production and timing of development
expenditures;
. downward revisions of proved reserves and the related negative impact
on the DD&A rate;
. production and reserves concentrated in a small number of properties;
. operating hazards attendant to the natural gas and oil business;
. downhole drilling and completion risks that are generally not
recoverable from third parties or insurance;
. potential mechanical failure or under-performance of significant
wells;
. impact of weather conditions on timing and costs of operations;
. availability and cost of material and equipment;
. actions or inactions of third-party operators of the Company's
properties;
. the ability to find and retain skilled personnel;
. availability of capital;
. the strength and financial resources of competitors;
. regulatory developments;
. environmental risks; and
. general economic conditions.
Any of the factors listed above and other factors contained in this
quarterly report could cause the Company's actual results to differ materially
from the results implied by these or any other forward-looking statements made
by the Company or on its behalf. The Company cannot provide assurance that
future results will meet its expectations. You should pay particular attention
to the risk factors and cautionary statements described in the Company's annual
report on Form 10-K for the year ended December 31, 2001.
10
Critical Accounting Policies
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates include DD&A of proved natural gas and oil properties.
Natural gas and oil reserve estimates, which are the basis for
unit-of-production DD&A and the full cost ceiling test, are inherently imprecise
and are expected to change as future information becomes available. The
Company's critical accounting policies are as follows:
Full Cost Method of Accounting
The Company uses the full cost method of accounting for its investments in
natural gas and oil properties. Under this method, all acquisition, exploration
and development costs, including certain related employee costs, incurred for
the purpose of exploring for and developing natural gas and oil are capitalized.
Acquisition costs include costs incurred to purchase, lease or otherwise acquire
property. Exploration costs include the costs of drilling exploratory wells,
including those in progress, geological and geophysical service costs and
depreciation of support equipment used in exploration activities. Development
costs include the costs of drilling development wells and costs of completions,
platforms, facilities and pipelines. Costs associated with production and
general corporate activities are expensed in the period incurred. Sales of
natural gas and oil properties, whether or not being amortized currently, are
accounted for as adjustments of capitalized costs, with no gain or loss
recognized, unless such adjustments would significantly alter the relationship
between capitalized costs and proved reserves of natural gas and oil.
DD&A
The Company computes the provision for DD&A of natural gas and oil
properties using the unit-of-production method based upon production and
estimates of proved reserve quantities. Unevaluated costs and related carrying
costs are excluded from the amortization base until the properties associated
with these costs are evaluated. In addition to costs associated with evaluated
properties, the amortization base includes estimated future development costs
and dismantlement, restoration and abandonment costs, net of estimated salvage
values.
Certain future development costs may be excluded from amortization when
incurred in connection with major development projects expected to entail
significant costs to ascertain the quantities of proved reserves attributable to
the properties under development. The amounts that may be excluded are portions
of the costs that relate to the major development project and have not
previously been included in the amortization base and the estimated future
expenditures associated with the development project. Such costs may be excluded
from costs to be amortized until the earlier determination of whether additional
reserves are proved or impairment occurs.
As of September 30, 2002, the Company excluded from the amortization base
estimated future expenditures of $27.0 million associated with common
development costs for its deep water discovery at Front Runner. This estimate of
future expenditures associated with common development costs is based on
existing proved reserves to total proved reserves expected to be established
upon completion of the Front Runner project.
If the $27.0 million had been included in the amortization base as of
September 30, 2002, and no additional reserves were assigned to the Front Runner
project, the DD&A rate as of September 30, 2002 would have been $2.24 per
thousand cubic feet gas equivalent ("Mcfe"). All future development costs
associated with the deep water discovery at Front Runner are included in the
determination of estimated future net cash flows from proved natural gas and oil
reserves used in the full cost ceiling calculation, as discussed below.
Full Cost Ceiling
Capitalized costs of natural gas and oil properties, net of accumulated
DD&A and related deferred taxes, are limited to the estimated future net cash
flows from proved natural gas and oil reserves, including the effects of hedging
activities in place as of September 30, 2002, discounted at 10 percent, plus the
lower of cost or fair value of unproved properties, as adjusted for related
income tax effects (the full cost ceiling). If capitalized costs exceed the full
cost ceiling, the excess is charged to write-down of natural gas and oil
properties in the quarter in which the excess occurs.
Given the volatility of natural gas and oil prices, it is probable that the
Company's estimate of discounted future net cash flows from proved natural gas
and oil reserves will change in the near term. If natural gas or oil prices
decline, even if for
11
only a short period of time, or if the Company has downward revisions to its
estimated proved reserves, it is possible that write-downs of natural gas and
oil properties could occur in the future.
Capitalized General and Administrative Expenses
Under the full cost method of accounting, certain internal costs are
capitalized that are directly identified with acquisition, exploration and
development activities. These capitalized internal costs include salaries,
employee benefits, costs of consulting services and other related expenses and
do not include costs related to production, general corporate overhead or
similar activities. Spinnaker capitalized $1.4 million and $4.3 million of
general and administrative costs in the third quarter and first nine months of
2002, respectively.
Unproved Properties
The costs associated with unproved properties and properties under
development are not initially included in the amortization base and relate to
unevaluated leasehold acreage and delay rentals, seismic data, wells
in-progress, wells pending determination and capitalized interest. Unevaluated
leasehold costs, delay rentals and capitalized interest are either transferred
to the amortization base with the costs of drilling the related well or are
assessed quarterly for possible impairment or reduction in value. Unevaluated
leasehold costs, delay rentals and capitalized interest are transferred to the
amortization base if a reduction in value has occurred. The costs of seismic
data are transferred to the amortization base using the sum-of-the-year's-digits
method over a period of six years. The costs associated with wells in-progress
and wells pending determination are transferred to the amortization base once a
determination is made whether or not proved reserves can be assigned to the
property. The costs of drilling exploratory dry holes and associated leasehold
costs are included in the amortization base immediately upon determination that
the well is unsuccessful.
Other
The costs associated with seismic hardware and software are included in
other property and equipment. These costs are depreciated using the
straight-line method over three years, with the provision for depreciation
recorded to the amortization base. Spinnaker capitalized a provision of $0.4
million and $0.9 million related to seismic hardware and software costs in the
third quarter and first nine months of 2002, respectively.
Overview
Financial and operational results for the three and nine months ended
September 30, 2002 compared to the same periods in 2001 included:
Three Months Ended September 30, 2002 as Compared to the Three Months Ended
September 30, 2001
. Production of 14.8 billion cubic feet gas equivalent ("Bcfe"), up 4
percent.
. Revenues of $51.6 million, up 15 percent.
. Income from operations of $11.0 million, down 32 percent.
. Net income of $7.1 million, down 34 percent.
. Cash flows from operating activities, before working capital changes,
of $43.5 million, up 11 percent.
Nine Months Ended September 30, 2002 as Compared to the Nine Months Ended
September 30, 2001
. Production of 35.2 Bcfe, down 13 percent.
. Revenues of $121.3 million, down 29 percent.
. Income from operations of $29.3 million, down 68 percent.
. Net income of $18.9 million, down 69 percent.
. Cash flows from operating activities, before working capital changes,
of $101.7 million, down 36 percent.
12
Results of Operations
The following table sets forth certain operating information with respect
to the natural gas and oil operations of the Company:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
------------------------ --------------------------
2002 2001 2002 2001
---------- ---------- ----------- -----------
Production:
Natural gas (MMcf) ................................... 12,690 13,747 31,131 38,836
Oil and condensate (MBbls) ........................... 349 81 672 230
Total (MMcfe) ...................................... 14,783 14,235 35,160 40,218
Revenues (in thousands):
Natural gas .......................................... $ 41,303 $ 39,945 $ 96,754 $ 181,494
Oil and condensate ................................... 9,058 2,083 16,927 6,170
Net hedging income (loss) ............................ 1,225 2,465 7,710 (16,218)
Other ................................................ (28) 325 (69) 325
---------- ---------- ----------- -----------
Total .............................................. $ 51,558 $ 44,818 $ 121,322 $ 171,771
Average sales price per unit:
Natural gas revenues from production
(per Mcf) .......................................... $ 3.25 $ 2.91 $ 3.11 $ 4.67
Effects of hedging activities (per Mcf) .............. 0.10 0.17 0.25 (0.41)
---------- ---------- ----------- -----------
Average price (per Mcf) ............................ $ 3.35 $ 3.08 $ 3.36 $ 4.26
Oil and condensate revenues from production
(per Bbl) .......................................... $ 25.97 $ 25.66 $ 25.21 $ 26.80
Effects of hedging activities (per Bbl) .............. - - - -
---------- ---------- ----------- -----------
Average price (per Bbl) ............................ $ 25.97 $ 25.66 $ 25.21 $ 26.80
Total revenues from production (per Mcfe) ............ $ 3.41 $ 2.95 $ 3.23 $ 4.67
Effects of hedging activities (per Mcfe) ............. 0.08 0.18 0.22 (0.41)
---------- ---------- ----------- -----------
Total average price (per Mcfe) ..................... $ 3.49 $ 3.13 $ 3.45 $ 4.26
Expenses (per Mcfe):
Lease operating expenses ............................. $ 0.35 $ 0.23 $ 0.35 $ 0.23
Depreciation, depletion and amortization -
natural gas and oil properties ..................... $ 2.16 $ 1.62 $ 2.01 $ 1.57
Income from operations (in thousands) ................... $ 11,042 $ 16,150 $ 29,261 $ 91,828
Three Months Ended September 30, 2002 as Compared to the Three Months Ended
September 30, 2001
Revenues, including the effects of hedging activities, increased $6.7
million in the third quarter of 2002 compared to the third quarter of 2001. The
increase in revenues was primarily due to higher oil production in the third
quarter of 2002 compared to the third quarter of 2001. Excluding the effects of
hedging activities, natural gas revenues increased $1.4 million and oil and
condensate revenues increased $7.0 million. The net income associated with
hedging activities in the third quarter of 2002 decreased $1.6 million compared
to the third quarter of 2001.
Production increased approximately 0.5 Bcfe in the third quarter of 2002
compared to the third quarter of 2001. Average daily production in the third
quarter of 2002 was 161 million cubic feet gas equivalent ("MMcfe") compared to
155 MMcfe in the same period of 2001. Natural gas revenues increased $1.4
million due to higher prices in the third quarter of 2002, although natural gas
production decreased 1.1 Bcf. Excluding the effects of hedging activities, third
quarter 2002 natural gas prices averaged $3.25 per Mcf compared to $2.91 per Mcf
in the third quarter of 2001. The production declines of certain producing
wells, particularly in the High Island 202 area, resulted in lower natural gas
production in the third quarter of 2002. Oil and condensate revenues increased
$7.0 million primarily due to higher production volumes of 268 thousand barrels
("MBbls"). Third quarter 2002 oil and condensate prices averaged $25.97 per
barrel compared to $25.66 in the same period
13
of 2001. The Company estimates that its net production was reduced by
approximately 0.5 Bcfe in the third quarter of 2002 as a result of Tropical
Storms Fay and Isidore. The Company estimates that its net production will be
reduced by approximately 0.8 Bcfe in the fourth quarter of 2002 as a result of
Hurricane Lili, which caused damage to several pipelines and facilities in which
the Company owns an interest.
Lease operating expenses increased $1.9 million in the third quarter of
2002 compared to the third quarter of 2001. Of the total increase in lease
operating expenses, approximately $3.0 million was attributable to wells on 11
new blocks that commenced production subsequent to September 30, 2001, offset in
part by decreases of $0.6 million in operating expenses associated with existing
wells and $0.5 million in workover expenses. The overall increase in the lease
operating expense rate per Mcfe in the third quarter of 2002 compared to the
same period in 2001 was primarily due to the production declines of certain
wells in the High Island 202 area where the lease operating rate was
significantly lower than other producing areas operated by the Company.
DD&A increased $8.9 million in the third quarter of 2002 compared to the
third quarter of 2001. Of the total increase in DD&A, $8.0 million related to an
increase in the DD&A rate per Mcfe and $0.9 million related to higher production
volumes in the third quarter of 2002. The DD&A rate increased in the third
quarter of 2002 compared to the second quarter of 2002 primarily due to four
unsuccessful drilling operations. Because of additional unsuccessful drilling
operations experienced to date, the Company currently expects that the DD&A rate
will increase in the fourth quarter of 2002 to approximately $2.25 per Mcfe.
General and administrative expenses increased approximately $0.8 million in
the third quarter of 2002 compared to the third quarter of 2001. The increase in
general and administrative expenses was primarily due to higher
employment-related costs resulting from the Company's recent growth in personnel
and increased professional services fees.
Interest income decreased $0.5 million in the third quarter of 2002
compared to the third quarter of 2001 primarily due to lower average cash and
short-term investment balances and lower interest rates in the third quarter of
2002. Interest expense increased $0.1 million in the third quarter of 2002
compared to the third quarter of 2001 primarily due to higher commitment fees
and loan origination fee amortization in the third quarter of 2002.
Income tax provision decreased $2.1 million in the third quarter of 2002
compared to the third quarter of 2001 due to lower earnings in the third quarter
of 2002. Income taxes were accrued at a 36 percent effective tax rate in the
third quarter of 2002 and 2001.
The Company recognized net income of $7.1 million, or $0.22 per basic share
and $0.21 per diluted share, in the third quarter of 2002 compared to net income
of $10.8 million, or $0.40 per basic share and $0.38 per diluted share, in the
third quarter of 2001.
Nine Months Ended September 30, 2002 as Compared to the Nine Months Ended
September 30, 2001
Revenues, including the effects of hedging activities, decreased $50.4
million in the first nine months of 2002 compared to the first nine months of
2001. The decrease in revenues was primarily due to lower natural gas production
and prices in the first nine months of 2002. Excluding the effects of hedging
activities, natural gas revenues decreased $84.7 million and oil and condensate
revenues increased $10.8 million. Revenues from natural gas hedging activities
improved approximately $23.5 million in the first nine months of 2002 compared
to the same period of 2001.
Production decreased approximately 5.1 Bcfe in the first nine months of
2002 compared to the first nine months of 2001. Average daily production in the
first nine months of 2002 was 129 MMcfe compared to 147 MMcfe in the same period
of 2001. Natural gas revenues decreased $84.7 million due to lower volumes of
7.7 Bcf and lower prices in the first nine months of 2002. Excluding the effects
of hedging activities, natural gas prices averaged $3.11 per Mcf in the first
nine months of 2002 compared to $4.67 per Mcf in the same period of 2001. The
production declines of certain producing wells, particularly in the High Island
202 area, and less than anticipated results from workovers resulted in lower
natural gas production in the first nine months of 2002. Oil and condensate
revenues increased $10.8 million primarily due to higher production volumes of
442 MBbls. Oil and condensate prices averaged $25.21 per barrel in the first
nine months of 2002 compared to $26.80 in the same period of 2001. The Company
estimates that its net production was reduced by approximately 0.5 Bcfe in the
third quarter of 2002 as a result of Tropical Storms Fay and Isidore. The
Company estimates that its net production will be reduced by approximately 0.8
Bcfe in the fourth quarter of 2002 as a result of Hurricane Lili, which caused
damage to several pipelines and facilities in which the Company owns an
interest.
14
Lease operating expenses increased $3.1 million in the first nine months of
2002 compared to the first nine months of 2001. Of the total increase in lease
operating expenses, approximately $4.4 million was attributable to wells on 11
new blocks that commenced production subsequent to September 30, 2001, offset in
part by a decrease of $1.3 million in operating expenses associated with
existing wells. The overall increase in the lease operating expense rate per
Mcfe in the first nine months of 2002 compared to the same period in 2001 was
primarily due to the production declines of certain wells in the High Island 202
area where the lease operating rate was significantly lower than other producing
areas operated by the Company.
DD&A increased $7.2 million in the first nine months of 2002 compared to
the first nine months of 2001. Of the total increase in DD&A, $15.2 million
related to an increase in the DD&A rate, offset by $8.0 million related to lower
production volumes of 5.1 Bcfe in the first nine months of 2002 compared to the
same period of 2001. Because of additional unsuccessful drilling operations
experienced to date, the Company currently expects that the DD&A rate will
increase in the fourth quarter of 2002.
General and administrative expenses increased approximately $1.4 million in
the first nine months of 2002 compared to the first nine months of 2001. The
increase in general and administrative expenses was primarily due to higher
employment-related costs resulting from the Company's recent growth and
increased professional services fees.
Interest income decreased $2.4 million in the first nine months of 2002
compared to the first nine months of 2001 primarily due to lower average cash
and short-term investment balances and significantly lower interest rates in the
first nine months of 2002. Interest expense increased $0.3 million in the first
nine months of 2002 compared to the same period of 2001 primarily due to
interest on borrowings of $37.0 million in the first quarter of 2002 and higher
commitment fees. On April 3, 2002, the Company repaid all of its outstanding
borrowings of $37.0 million under the Credit Facility.
Income tax provision decreased $23.5 million in the first nine months of
2002 compared to the first nine months of 2001 due to lower earnings in the
first nine months of 2002. Income taxes were accrued at a 36 percent effective
tax rate in the first nine months of 2002 and 2001.
The Company recognized net income of $18.9 million, or $0.61 per basic
share and $0.59 per diluted share, in the first nine months of 2002 compared to
net income of $60.7 million, or $2.25 per basic share and $2.14 per diluted
share, in the same period of 2001.
Liquidity and Capital Resources
The Company has experienced and expects to continue to experience
substantial capital requirements, primarily due to its active exploration and
development programs in the Gulf of Mexico. Capital expenditures in 2001 were
$288.8 million. Spinnaker has capital expenditure plans for 2002 totaling
approximately $322 million and has incurred capital expenditures of
approximately $287.4 million in the first nine months of 2002. During 2001,
Spinnaker participated in a significant deep water oil discovery, Front Runner,
with a 25 percent non-operator working interest. The Company participated in six
consecutive successful wells and sidetracks in testing the reservoirs on these
blocks. Spinnaker has incurred capital expenditures associated with Front Runner
of $20.3 million in the first nine months of 2002 and inception-to-date
expenditures of $49.7 million. The Company expects to incur approximately $103
million in future development costs, including approximately $10 million during
the remainder of 2002, $60 million in 2003, $15 million in 2004 and $18 million
thereafter.
Natural gas and oil prices have a significant impact on the Company's cash
flows available for capital expenditures and its ability to borrow and raise
additional capital. The amount the Company can borrow under its Credit Facility
is subject to periodic re-determination based in part on changing expectations
of future prices. Lower prices may also reduce the amount of natural gas and oil
that the Company can economically produce. Additionally, the rapid production
declines of certain producing wells resulted in lower production in the first
nine months of 2002. Lower prices and/or lower production may decrease revenues,
cash flows and the borrowing base under the Credit Facility, thus reducing the
amount of financial resources available to meet the Company's capital
requirements.
On April 3, 2002, the Company completed a public offering of 5,750,000
shares of Common Stock at $41.50 per share, including the over-allotment option
consisting of 750,000 shares. After payment of underwriting discounts and
commissions, the Company received net proceeds of $227.9 million. On April 3,
2002, the Company used a portion of the proceeds from the offering to repay
outstanding borrowings of $37.0 million. The remaining net proceeds were
invested in short-term high quality investments and are being used to fund a
portion of the costs to develop the Company's deep water oil discovery at
15
Front Runner, to fund a portion of exploration and other development activities
and for general corporate purposes, including possible acquisitions of
properties or seismic data.
While the Company believes that proceeds from the Common Stock offering,
working capital, cash flows from operations and available borrowings under its
Credit Facility will be sufficient to meet its capital requirements in the next
twelve months, additional debt or equity financing may be required in the future
to fund its growth and exploration and development programs. In the event
additional capital resources are unavailable, the Company may curtail its
drilling, development and other activities or be forced to sell some of its
assets on an untimely or unfavorable basis.
Spinnaker has an effective shelf registration statement relating to the
potential public offer and sale by the Company or certain of its affiliates of
up to $500 million of any combination of debt securities, preferred stock,
common stock, warrants, stock purchase contracts and trust preferred securities
from time to time or when financing needs arise. The registration statement does
not provide assurance that the Company will or could sell any such securities.
Cash and cash equivalents increased $22.2 million to $36.3 million at
September 30, 2002 from $14.1 million at December 31, 2001. The components of
the increase in cash and cash equivalents include $228.3 million provided by
financing activities, $88.5 million provided by operating activities and $294.6
million used in investing activities.
Operating Activities
Net cash provided by operating activities in the first nine months of 2002
decreased 56 percent to $88.5 million primarily due to lower natural gas
production and prices. Cash flow from operations is dependent upon the Company's
ability to increase production through its exploration and development programs
and the prices of natural gas and oil. The Company has made significant
investments to expand its operations in the Gulf of Mexico. These investments
are expected to increase the Company's average daily production in the fourth
quarter of 2002 as compared to the first nine months of 2002. However, the
Company currently expects that its average daily production in 2003 will decline
significantly from the levels it expects to achieve in the fourth quarter of
2002.
The Company sells its natural gas and oil production under fixed or
floating market price contracts. Spinnaker enters into hedging arrangements from
time to time to reduce its exposure to fluctuations in natural gas and oil
prices and achieve more predictable cash flow. However, these contracts also
limit the benefits the Company would realize if prices increase. See "Item 3.
Quantitative and Qualitative Disclosures About Market Risk."
The Company's cash flow from operations also depends on its ability to
manage working capital, including accounts receivable, accounts payable and
accrued liabilities. The net increase of $18.3 million in accounts receivable
was primarily related to an increase of $8.7 million in the natural gas and oil
revenue accrual at September 30, 2002 due to higher production and commodity
prices in September 2002 compared to December 2001 and an increase of $7.4
million in joint interest billing and trade receivables due to higher levels of
operated drilling and development activities in the third quarter of 2002
compared to the fourth quarter of 2001. The net decrease of $8.2 million in
accounts payable and accrued liabilities was primarily due to the reversal of
current deferred taxes of $7.2 million related to the fair value of open
derivative contracts at December 31, 2001. In connection with the fair value of
open derivative contracts at September 30, 2002, the Company recorded a net
deferred tax asset of $3.6 million in other current assets.
16
Investing Activities
Net cash used in investing activities in the first nine months of 2002
increased 39 percent to $294.6 million compared to the first nine months of
2001. Net oil and gas property capital expenditures were $288.0 million and
other property and equipment capital expenditures were $6.6 million.
As part of its strategy, the Company explores for natural gas and oil at
deeper drilling depths and in the deep waters of the Gulf of Mexico, where
operations are more difficult and costly than at shallower drilling depths and
in shallower waters. Along with higher risks and costs associated with these
areas, greater opportunity exists for reserve additions. The Company has
experienced and will continue to experience significantly higher drilling costs
for its deep shelf and deep water projects relative to the drilling costs on
shallower depth shelf projects in the Gulf of Mexico. The Company drilled 22
wells in the first nine months of 2002, 13 of which were successful. In 2001,
the Company drilled 35 wells, 19 of which were successful. Since inception and
through September 30, 2002, the Company has drilled 116 wells, 69 of which were
successful, representing a success rate of 59 percent. Dry hole costs, including
associated leasehold costs, were $33.6 million and $63.0 million in the three
and nine months ended September 30, 2002, respectively.
The Company has capital expenditure plans for the fourth quarter of 2002 of
approximately $35 million. The Company has capital expenditure plans for 2003
totaling approximately $268 million, primarily for costs related to exploration
and development programs. The Company does not anticipate any significant
abandonment or dismantlement costs in 2003. Actual levels of capital
expenditures may vary due to many factors, including drilling results, natural
gas and oil prices, the availability of capital, industry conditions,
acquisitions, decisions of operators and other prospect owners and the prices of
drilling rig dayrates and other oilfield goods and services. In the first nine
months of 2002, the Company incurred acquisition, exploration and development
costs of $37.7 million, $160.6 million and $82.5 million, respectively. The
costs associated with unproved properties and properties under development not
included in the amortization base were $140.3 million as of September 30, 2002
and $102.9 million as of December 31, 2001 and included the following (in
thousands):
As of As of
September 30, December 31,
2002 2001
------------- ------------
Leasehold, delay rentals and seismic data .......... $131,196 $ 92,150
Wells in-progress .................................. 4,186 10,112
Wells pending determination ........................ 4,044 -
Capitalized interest ............................... 372 372
Other .............................................. 461 247
-------- --------
Total .......................................... $140,259 $102,881
======== ========
Financing Activities
Net cash provided by financing activities of $228.3 million in the first
nine months of 2002 included proceeds from the public offering of Common Stock
and $37.0 million in proceeds from and subsequent payments on borrowings. The
Company received net proceeds of $227.9 million from the offering on April 3,
2002, and used a portion of the proceeds from the offering to repay outstanding
borrowings of $37.0 million.
On December 28, 2001, the Company replaced its $75.0 million credit
facility with an unsecured $200.0 million Credit Facility with a group of seven
banks. The borrowing base of the three-year Credit Facility is re-determined on
or about April 30 and September 30 each year. The banks and Spinnaker also have
the option to request one additional re-determination each year. The borrowing
base is determined by the banks, in their usual and customary manner, and at
their sole discretion. The amount of the borrowing base is a function of the
banks' view of the Company's reserve profile as well as commodity prices. The
current borrowing base is $100.0 million. The Company has the option to elect to
use a base interest rate as
17
described below or the LIBOR rate plus, for each such rate, a spread based on
the percent of the borrowing base used at that time. The base interest rate
under the Credit Facility is a fluctuating rate of interest equal to the higher
of either Toronto-Dominion Bank's base rate for dollar advances made in the
United States or the Federal Funds Rate plus 0.5 percent per annum. The
commitment fee rate ranges from 0.3 percent to 0.5 percent, depending on the
borrowing base usage. The Credit Facility contains various covenants and
restrictive provisions. At September 30, 2002, the Company was in compliance
with the covenants and restrictive provisions. As of November 12, 2002, the
Company had no outstanding borrowings under the Credit Facility.
18
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
The Company is exposed to changes in interest rates. Changes in interest
rates affect the interest earned on cash and cash equivalents and the interest
rate paid on borrowings under the Credit Facility. The Company does not
currently use interest rate derivative instruments to manage exposure to
interest rate changes, but may do so in the future.
Commodity Price Risk
The Company's revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. Prices also affect
the amount of cash flow available for capital expenditures and the Company's
ability to borrow and raise additional capital. Lower prices may also reduce the
amount of natural gas and oil that the Company can economically produce. The
Company sells its natural gas and oil production under fixed or floating market
price contracts. Spinnaker enters into hedging arrangements from time to time to
reduce its exposure to fluctuations in natural gas and oil prices and to achieve
more predictable cash flow. However, these contracts also limit the benefits the
Company would realize if prices increase. These financial arrangements are fixed
price swap contracts and costless collar arrangements and are placed with major
trading counterparties the Company believes represent minimum credit risks.
Spinnaker cannot provide assurance that these trading counterparties will not
become credit risks in the future. Under its current hedging practice, the
Company generally does not hedge more than 66 2/3 percent of its estimated
twelve-month production quantities without the prior approval of the risk
management committee of the board of directors.
See Note 5 to the Company's Notes to Interim Consolidated Financial
Statements (Unaudited) for a discussion of activities involving derivative
financial instruments during 2002 and the Company's current commodity price risk
management positions in fixed price natural gas swap contracts and natural gas
collar arrangements. To calculate the potential effect of the derivative
contracts on future revenues, the Company applied NYMEX natural gas forward
prices as of September 30, 2002 to the quantity of the Company's natural gas
production covered by those derivative contracts as of that date. The following
table shows the estimated potential effects of the derivative financial
instruments on future revenues (in thousands):
Estimated Decrease Estimated Decrease
Estimated Change in Revenues with in Revenues with
in Revenues at 10% Decrease in 10% Increase in
Derivative instrument Current Prices Prices Prices
------------------------------------ -------------------- -------------------- --------------------
Fixed price swap transactions ...... $ (12,270) $ (1,763) $ (23,016)
Collar arrangements ................ - - -
19
PART II - OTHER INFORMATION
Item 4. Controls and Procedures
(a) Evaluation of disclosure controls and procedures. Within 90 days before the
filing of this quarterly report on Form 10-Q, the Company's principal
executive officer and principal financial officer evaluated the
effectiveness of the Company's disclosure controls and procedures. Based on
the evaluation, the Company's principal executive officer and principal
financial officer believe that:
. the Company's disclosure controls and procedures are designed to
ensure that information required to be disclosed by the Company in the
reports it files or submits under the Securities Exchange Act of 1934
is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules
and forms; and
. the Company's disclosure controls and procedures were effective to
ensure that material information was accumulated and communicated to
the Company's management, including the Company's principal executive
officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure.
(b) Changes in internal controls. There have been no significant changes in the
Company's internal controls or in other factors that could significantly
affect the Company's internal controls subsequent to their evaluation, nor
have there been any corrective actions with regard to significant
deficiencies or material weaknesses.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
12.1 - Calculation of Ratios of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Dividends
(b) Reports on Form 8-K
A Current Report on Form 8-K dated August 13, 2002 and filed on
August 14, 2002 furnished under Item 9. Regulation FD Disclosure
the certifications by each of the Chief Executive Officer and the
Chief Financial Officer that accompanied the Company's Quarterly
Report on Form 10-Q for the period ended June 30, 2002 in
accordance with 18 U.S.C. Section 1350.
20
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SPINNAKER EXPLORATION COMPANY
Date: November 12, 2002 By: /s/ ROBERT M. SNELL
--------------------- -------------------------------
Robert M. Snell
Vice President, Chief Financial
Officer and Secretary
Date: November 12, 2002 By: /s/ JEFFREY C. ZARUBA
--------------------- -------------------------------
Jeffrey C. Zaruba
Vice President, Treasurer and
Assistant Secretary
21
CERTIFICATION OF
PRINCIPAL EXECUTIVE OFFICER
OF SPINNAKER EXPLORATION COMPANY
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT
I, Roger L. Jarvis, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Spinnaker Exploration
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 12, 2002
/s/ ROGER L. JARVIS
----------------------
Name: Roger L. Jarvis
Title: Chief Executive Officer
22
CERTIFICATION OF
PRINCIPAL FINANCIAL OFFICER
OF SPINNAKER EXPLORATION COMPANY
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT
I, Robert M. Snell, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Spinnaker Exploration
Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 12, 2002
/s/ ROBERT M. SNELL
-----------------------
Name: Robert M. Snell
Title: Chief Financial Officer
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EXHIBIT INDEX
Exhibit
Number Description
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12.1 - Calculation of Ratios of Earnings to Fixed Charges and Combined Fixed
Charges and Preferred Dividends
24