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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------------------
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 June 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 (I.R.S. Employer
of incorporation or organization) 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
The number of shares outstanding of the registrant's common stock, par
value $0.01 per share, on August 13, 2002 was 33,159,331.
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SPINNAKER EXPLORATION COMPANY
Form 10-Q
For the Three and Six Months Ended June 30, 2002
Page
----
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets
June 30, 2002 (unaudited) and December 31, 2001 ........................................ 3
Consolidated Statements of Operations
Three and Six Months Ended June 30, 2002 and 2001 (unaudited) .......................... 4
Consolidated Statements of Cash Flows
Six Months Ended June 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 ...................... 18
PART II - OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders ............................. 21
Item 6. Exhibits and Reports on Form 8-K ................................................ 21
SIGNATURES .................................................................................... 22
2
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
June 30, December 31,
2002 2001
------------ ------------
ASSETS (Unaudited)
CURRENT ASSETS:
Cash and cash equivalents ................................................................. $ 96,061 $ 14,061
Accounts receivable, net of allowance for doubtful accounts of $3,059
at June 30, 2002 and December 31, 2001, respectively .................................... 40,474 24,129
Hedging assets ............................................................................ 2,637 20,593
Other ..................................................................................... 8,032 3,664
--------- ---------
Total current assets .................................................................. 147,204 62,447
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties ....................................................................... 718,852 575,806
Unproved properties and properties under development, not being amortized ............... 159,212 102,881
Other ..................................................................................... 10,939 7,245
--------- ---------
889,003 685,932
Less - Accumulated depreciation, depletion and amortization ............................... (202,881) (163,359)
--------- ---------
Total property and equipment .......................................................... 686,122 522,573
OTHER ASSETS ................................................................................. 584 2,296
--------- ---------
Total assets .......................................................................... $ 833,910 $ 587,316
========= =========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable .......................................................................... $ 39,320 $ 32,383
Accrued liabilities and other ............................................................. 54,981 50,718
Hedging liabilities ....................................................................... 3,736 --
--------- ---------
Total current liabilities ............................................................. 98,037 83,101
OTHER LIABILITIES ............................................................................ 3,027 --
DEFERRED INCOME TAXES ........................................................................ 49,788 45,723
COMMITMENTS AND CONTINGENCIES
EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued
and outstanding at June 30, 2002 and December 31, 2001, respectively .................... -- --
Common stock, $0.01 par value; 50,000,000 shares authorized; 33,171,292 shares
issued and 33,157,788 shares outstanding at June 30, 2002 and 27,308,912
shares issued and 27,293,264 shares outstanding at December 31, 2001 .................... 332 273
Additional paid-in capital ................................................................ 595,755 365,993
Retained earnings ......................................................................... 89,556 77,758
Less: Treasury stock, at cost, 13,504 and 15,648 shares at June 30, 2002 and
December 31, 2001, respectively ......................................................... (34) (39)
Accumulated other comprehensive income (loss) ............................................. (2,551) 14,507
--------- ---------
Total equity .......................................................................... 683,058 458,492
--------- ---------
Total liabilities and equity .......................................................... $ 833,910 $ 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 Six Months
Ended June 30, Ended June 30,
---------------------------- ------------------------------
2002 2001 2002 2001
----------- ------------ ----------- -----------
REVENUES ........................................... $ 37,164 $ 59,500 $ 69,764 $ 126,953
EXPENSES:
Lease operating expenses ........................ 3,734 3,312 7,143 6,003
Depreciation, depletion and amortization
- natural gas and oil properties .............. 21,231 20,978 38,608 40,320
Depreciation and amortization - other ........... 210 106 383 202
General and administrative ...................... 2,733 2,218 5,411 4,750
--------- --------- --------- ---------
Total expenses .............................. 27,908 26,614 51,545 51,275
--------- --------- --------- ---------
INCOME FROM OPERATIONS ............................. 9,256 32,886 18,219 75,678
OTHER INCOME (EXPENSE):
Interest income ................................. 620 1,249 664 2,594
Interest expense ................................ (155) (102) (449) (258)
--------- --------- --------- ---------
Total other income (expense) ................ 465 1,147 215 2,336
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES ......................... 9,721 34,033 18,434 78,014
Income tax provision ........................... 3,499 12,252 6,636 28,085
--------- --------- --------- ---------
NET INCOME ......................................... $ 6,222 $ 21,781 $ 11,798 $ 49,929
========= ========= ========= =========
NET INCOME PER COMMON SHARE:
Basic ........................................... $ 0.19 $ 0.80 $ 0.39 $ 1.85
========= ========= ========= =========
Diluted ......................................... $ 0.18 $ 0.77 $ 0.38 $ 1.76
========= ========= ========= =========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING:
Basic ........................................... 33,030 27,132 30,200 26,953
========= ========= ========= =========
Diluted ......................................... 34,162 28,427 31,330 28,295
========= ========= ========= =========
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 Six Months
Ended June 30,
---------------------------
2002 2001
----------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................................................ $ 11,798 $ 49,929
Adjustments to reconcile net income to net cash provided by (used in) operating
activities:
Depreciation, depletion and amortization ................................................ 38,991 40,522
Deferred income tax expense ............................................................. 6,936 28,085
Other ................................................................................... 490 718
Change in components of working capital:
Accounts receivable ................................................................... (16,345) 8,874
Accounts payable and accrued liabilities .............................................. 4,379 12,958
Other current assets and other ........................................................ (4,419) 4,793
--------- ---------
Net cash provided by operating activities ......................................... 41,830 145,879
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties ....................................................... (184,432) (136,184)
Purchases of other property and equipment ................................................. (3,694) (481)
Purchases of short-term investments ....................................................... -- (26,655)
Sales of short-term investments ........................................................... -- 37,243
--------- ---------
Net cash used in investing activities ............................................. (188,126) (126,077)
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 ............................................................... (469) --
Proceeds from exercise of stock options ................................................... 892 5,882
--------- ---------
Net cash provided by financing activities ......................................... 228,296 5,882
--------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS .................................................... 82,000 25,684
CASH AND CASH EQUIVALENTS, beginning of year ................................................. 14,061 63,910
--------- ---------
CASH AND CASH EQUIVALENTS, end of period ..................................................... $ 96,061 $ 89,594
========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized........................................ $ 315 $ 147
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)
June 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 Six Months Ended
June 30, June 30,
----------------------- -----------------------
2002 2001 2002 2001
--------- ---------- ---------- ----------
Numerator:
Net income ........................................... $ 6,222 $ 21,781 $ 11,798 $49,929
======= ======== ======== =======
Denominator:
Basic weighted average number of shares .............. 33,030 27,132 30,200 26,953
======= ======== ======== =======
Dilutive securities:
Stock options ...................................... 1,132 1,295 1,130 1,342
------- -------- -------- -------
Diluted adjusted weighted average number of shares and
assumed conversions................................. 34,162 28,427 31,330 28,295
======= ======== ======== =======
Net income per common share:
Basic ................................................ $ 0.19 $ 0.80 $ 0.39 $ 1.85
======= ======== ======== =======
Diluted .............................................. $ 0.18 $ 0.77 $ 0.38 $ 1.76
======= ======== ======== =======
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 bank's 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 June 30, 2002, the Company was in compliance with the
covenants and restrictive provisions. As of August 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 item in the statement of operations and require 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 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. Some of the master agreements
require the Company to make margin payments to counterparties when net exposure
exceeds a certain threshold. During the second quarter of 2002 and as of August
12, 2002, the Company had no such margin obligations.
As of June 30, 2002, Spinnaker's commodity price risk management positions
in fixed price natural gas swap contracts were as follows:
Average Weighted
Daily Average Net
Volume Price (Per Hedge Positions
Period (MMBtu) MMBtu) (in thousands)
- ------------------------------------- ---------- ----------- ------------
Third Quarter 2002 .................. 80,000 $ 3.37 $ 803
Fourth Quarter 2002 ................. 86,685 3.64 413
First Quarter 2003 .................. 50,000 3.61 (1,344)
Second Quarter 2003 ................. 50,000 3.52 (971)
Third Quarter 2003 .................. 50,000 3.55 (1,195)
Fourth Quarter 2003 ................. 50,000 3.63 (1,694)
--------
Total .......................... $ (3,988)
========
The Company reported a net liability of $4.0 million related to its
derivative contracts at June 30, 2002. The components of the net liability were
as follows (in thousands):
As of As of
June 30, December 31,
2002 2001
-------------- ----------------
Current:
Hedging asset ................. $ 2,637 $20,593
Hedging liability ............. (3,736) -
Non-current:
Hedging asset ................. $ 138 $ 1,726
Hedging liability ............. (3,027) -
7
The Company also reported a loss in accumulated other comprehensive income
of $2.6 million, net of income taxes of $1.4 million. The ineffective component
of the derivatives recognized in earnings was a loss less than $0.1 million in
the first six months of 2002.
In connection with monthly settlements, the Company recognized net hedging
gains of $6.5 million in revenues in the first six months of 2002. Based on
future natural gas prices as of June 30, 2002, the Company would reclassify a
net loss of $1.1 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 June 30, 2002, Spinnaker entered into additional swap
contracts for the third 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 August 12, 2002 and
July and August settlements, were as follows:
Average Weighted
Daily Average Net Hedge
Volume Price (Per Positions
Period (MMBtu) MMBtu) (in thousands)
- --------------------------- -------------- ------------ ---------------
Third Quarter 2002 ........ 93,261 $ 3.32 $ 2,208
Fourth Quarter 2002 ....... 86,685 3.64 2,712
First Quarter 2003 ........ 50,000 3.61 (538)
Second Quarter 2003 ....... 50,000 3.52 (464)
Third Quarter 2003 ........ 50,000 3.55 (615)
Fourth Quarter 2003 ....... 50,000 3.63 (1,193)
--------
Total $ 2,110
========
6. Comprehensive Income
Comprehensive income was $3.7 million and $9.2 million in the second
quarter and first six months of 2002, respectively. The following represents
components of comprehensive income (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- ------------------------
2002 2001 2002 2001
------------ ------------ ----------- --------- -
Net income ................................................ $ 6,222 $ 21,781 $ 11,798 $ 49,929
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 .......................................... (3,567) (773) 1,599 15,729
Financial derivative settlements taken to income, net of
tax .................................................. 1,016 1,333 (4,150) 11,957
-------- -------- -------- --------
Comprehensive income ...................................... $ 3,671 $ 22,341 $ 9,247 $ 50,489
======== ======== ======== ========
8
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 additional 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 expects to 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:
o financial position;
o business strategy;
o budgets;
o amount, nature and timing of capital expenditures, including future
development costs;
o drilling of wells;
o natural gas and oil reserves;
o timing and amount of future production of natural gas and oil;
o operating costs and other expenses;
o cash flow and anticipated liquidity;
o prospect development and property acquisitions; and
o marketing of natural gas and oil.
Numerous important factors, risks and uncertainties may affect the
Company's operating results, including:
o the risks associated with exploration;
o delays in anticipated start-up dates;
o the ability to find, acquire, market, develop and produce new
properties;
o natural gas and oil price volatility;
o uncertainties in the estimation of proved reserves and in the
projection of future rates of production and timing of development
expenditures;
o downward revisions of proved reserves and the related negative impact
on the DD&A rate;
o operating hazards attendant to the natural gas and oil business;
o downhole drilling and completion risks that are generally not
recoverable from third parties or insurance;
o potential mechanical failure or under-performance of significant
wells;
o impact of weather conditions on timing and costs of operations;
o availability and cost of material and equipment;
o actions or inactions of third-party operators of the Company's
properties;
o the ability to find and retain skilled personnel;
o availability of capital;
o the strength and financial resources of competitors;
o regulatory developments;
o environmental risks; and
o 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.
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
10
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 June 30, 2002, the Company excluded from the amortization base
estimated future expenditures of $34.4 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 $34.4 million had been included in the amortization base as of June
30, 2002, and no additional reserves were assigned to the Front Runner project,
the DD&A rate as of June 30, 2002 would have been $2.10 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 June 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 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 $1.3 million and $2.8 million of
general and administrative costs in the second quarter and first six months of
2002, respectively.
11
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 dry.
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 $0.3
million and $0.5 million related to seismic hardware and software costs in the
second quarter and first six months of 2002, respectively.
Natural Gas and Oil Reserves
The following table presents estimated net proved natural gas and oil
reserves and the present value of future net cash flows, before income taxes and
discounted at 10 percent, of the reserves at June 30, 2002 based on a reserve
report prepared by Ryder Scott Company, L.P. ("Ryder Scott"). In accordance with
requirements of the Securities and Exchange Commission, Ryder Scott bases the
present value of future net cash flows from proved reserves on prices and costs
on the date of the estimate. Actual future prices and costs may differ
materially from those used in the present value estimate. The present value of
future net cash flows as of June 30, 2002 was determined by using prices of
$3.37 per Mcf of natural gas and $26.05 per barrel of oil, representing the June
30, 2002 weighted average market prices for natural gas and oil. The present
value of future net cash flows (before income taxes) discounted at 10 percent is
not intended to represent the current market value of the estimated natural gas
and oil reserves Spinnaker owns.
Proved Reserves
---------------------------------------------
Developed Undeveloped Total
--------------- ---------------- ------------
Natural gas (MMcf) ........................................... 114,546 52,564 167,110
Oil and condensate (MBbls) ................................... 3,293 24,558 27,851
Total proved reserves (MMcfe) ................................ 134,302 199,913 334,215
Present value of future net cash flows (before income taxes)
discounted at 10 percent (in thousands) ................... $322,728 $323,884 $646,612
The process of estimating natural gas and oil reserves is complex. It
requires various assumptions, including natural gas and oil prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. Ryder
Scott projects production rates and timing of development and abandonment
expenditures. Based on the reserve data at June 30, 2002, future development and
abandonment expenditures were estimated to be $185.9 million. Ryder Scott also
analyzes available geological, geophysical, production and engineering data, and
the extent, quality and reliability of this data can vary. Therefore, estimates
of natural gas and oil reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from estimates. Any
significant variance could materially affect the estimated quantities and net
present value of reserves. In addition, Ryder Scott may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing natural gas and oil prices and other factors, many of
which are beyond the Company's control. At June 30, 2002, approximately 74
percent of proved reserves were either undeveloped or non-producing. Because
most of the reserve estimates are not based on a lengthy production history and
are calculated using volumetric analysis, these estimates are less reliable than
estimates based on a lengthy production history.
At June 30, 2002, approximately 60 percent of proved reserves were
undeveloped, including proved reserves associated with Front Runner. Recovery of
undeveloped reserves generally requires significant capital expenditures and
successful
12
drilling operations. Although Ryder Scott estimates Spinnaker's reserves and the
costs associated with developing them in accordance with industry standards, the
estimated costs may be inaccurate, development may not occur as scheduled and
results may not be as estimated.
Overview
Financial and operational results for the three and six months ended June
30, 2002 compared to the same periods in 2001 included:
Three Months Ended June 30, 2002 as Compared to the Three Months Ended
June 30, 2001
o Production of 10.6 billion cubic feet gas equivalent ("Bcfe"), down 22
percent.
o Revenues of $37.2 million, down 38 percent.
o Income from operations of $9.3 million, down 72 percent.
o Net income of $6.2 million, or $0.18 per diluted share, down 71
percent.
o Cash flows from operating activities, before working capital changes,
of $31.4 million, down 44 percent.
Six Months Ended June 30, 2002 as Compared to the Six Months Ended June 30,
2001
o Production of 20.4 Bcfe, down 22 percent.
o Revenues of $69.8 million, down 45 percent.
o Income from operations of $18.2 million, down 76 percent.
o Net income of $11.8 million, or $0.38 per diluted share, down 76
percent.
o Cash flows from operating activities, before working capital changes,
of $58.2 million, down 51 percent.
Spinnaker's results of operations and financial position were significantly
impacted by lower natural gas production and prices in the second quarter of
2002. Natural gas revenues decreased $27.7 million in the second quarter of
2002. The decrease was attributable to lower volumes of 4.0 Bcf and lower
natural gas prices in the second quarter of 2002. Excluding the effects of
hedging activities, second quarter 2002 natural gas prices averaged $3.57 per
thousand cubic feet of natural gas ("Mcf") compared to the second quarter 2001
average price of $4.58 per Mcf.
Natural gas revenues decreased $86.1 million in the first six months of
2002. The decrease was attributable to lower volumes of 6.6 Bcf and lower
natural gas prices in the first six months of 2002. Excluding the effects of
hedging activities, natural gas prices averaged $3.01 per Mcf in the first six
months of 2002 compared to $5.64 per Mcf in the same period of 2001. Revenues
from natural gas hedging activities of $6.5 million in the first six months of
2002 improved $25.2 million compared to a net loss of $18.7 million in the first
six months of 2001.
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 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.
13
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 Ended For the Six Months Ended
June 30, June 30,
-------------------------------- -----------------------------
2002 2001 2002 2001
------------ ------------ -------------- -----------
Production:
Natural gas (MMcf) ........................ 9,096 13,120 18,441 25,089
Oil and condensate (MBbls) ................ 250 72 323 149
Total (MMcfe) ........................... 10,592 13,553 20,377 25,983
Revenues (in thousands):
Natural gas ............................... $ 32,431 $ 60,094 $ 55,451 $ 141,549
Oil and condensate ........................ 6,502 1,924 7,869 4,087
Net hedging income (loss) ................. (1,773) (2,083) 6,485 (18,683)
Other ..................................... 4 (435) (41) --
---------- ---------- ---------- -----------
Total ................................... $ 37,164 $ 59,500 $ 69,764 $ 126,953
Average sales price per unit:
Natural gas revenues from production (per
Mcf) .................................... $ 3.57 $ 4.58 $ 3.01 $ 5.64
Effects of hedging activities (per Mcf) ... (0.20) (0.16) 0.35 (0.74)
---------- ---------- ---------- -----------
Average price (per Mcf) ................. $ 3.37 $ 4.42 $ 3.36 $ 4.90
Oil and condensate revenues from
production (per Bbl) .................... $ 26.09 $ 26.62 $ 24.38 $ 27.42
Effects of hedging activities (per Bbl) ... -- -- -- --
---------- ---------- ---------- -----------
Average price (per Bbl) ................. $ 26.09 $ 26.62 $ 24.38 $ 27.42
Total revenues from production (per Mcfe).. $ 3.68 $ 4.58 $ 3.11 $ 5.61
Effects of hedging activities (per Mcfe) .. (0.17) (0.16) 0.32 (0.72)
---------- ---------- ---------- -----------
Total average price (per Mcfe) .......... $ 3.51 $ 4.42 $ 3.43 $ 4.89
Expenses (per Mcfe):
Lease operating expenses .................. $ 0.35 $ 0.24 $ 0.35 $ 0.23
Depreciation, depletion and amortization -
natural gas and oil properties .......... $ 2.00 $ 1.55 $ 1.89 $ 1.55
Income from operations (in thousands) ........ $ 9,256 $ 32,886 $ 18,219 $ 75,678
Three Months Ended June 30, 2002 as Compared to the Three Months Ended
June 30, 2001
Revenues, including the effects of hedging activities, decreased $22.3
million in the second quarter of 2002 compared to the second quarter of 2001.
The decrease in revenues was primarily due to lower natural gas production and
prices in the second quarter of 2002 compared to the second quarter of 2001.
Excluding the effects of hedging activities, natural gas revenues decreased
$27.7 million and oil and condensate revenues increased $4.6 million. The net
loss associated with hedging activities in the second quarter of 2002 was lower
by $0.3 million compared to the second quarter of 2001.
Production decreased approximately 3.0 Bcfe in the second quarter of 2002
compared to the second quarter of 2001. Average daily production in the second
quarter of 2002 was 116 million cubic feet gas equivalent ("MMcfe") compared to
149 MMcfe in the same period of 2001. Natural gas revenues decreased $27.7
million due to lower volumes of 4.0 Bcf and lower prices in the second quarter
of 2002. Excluding the effects of hedging activities, second quarter 2002
natural gas prices averaged $3.57 per Mcf compared to $4.58 per Mcf in the
second quarter of 2001. The rapid production declines of certain producing
wells, particularly in the High Island 202 area, resulted in lower natural gas
production in the second quarter of 2002. Oil and condensate revenues increased
$4.6 million primarily due to higher production volumes of 178 thousand
14
barrels ("MBbls"). Second quarter 2002 oil and condensate prices averaged $26.09
per barrel compared to $26.62 in the same period of 2001.
Lease operating expenses increased $0.4 million in the second quarter of
2002 compared to the second quarter of 2001. Of the total increase in lease
operating expenses, approximately $1.2 million was attributable to wells on 13
new blocks that commenced production subsequent to June 30, 2001, offset in part
by a decrease of $0.6 million in expenses associated with existing wells and a
decrease of $0.2 million related to workover activities.
DD&A increased $0.4 million in the second quarter of 2002 compared to the
second quarter of 2001. Of the total increase in DD&A, $4.8 million related to
an increase in the DD&A rate and $0.1 million related to an increase in other
property and equipment depreciation and amortization, offset in part by $4.5
million related to lower production volumes of 3.0 Bcfe in the second quarter of
2002. The DD&A rate increased in the second quarter of 2002 primarily due to
three unsuccessful drilling operations, one unsuccessful completion activity and
a net downward revision in reserves.
General and administrative expenses increased approximately $0.5 million in
the second quarter of 2002 compared to the second 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.
Interest income decreased $0.6 million in the second quarter of 2002
compared to the second quarter of 2001 primarily due to significantly lower
interest rates in the second quarter of 2002.
Income tax provision decreased $8.8 million in the second quarter of 2002
compared to the second quarter of 2001, primarily due to lower earnings in the
second quarter of 2002. Income taxes were accrued at a 36 percent effective tax
rate in the second quarter of 2002 and 2001.
The Company recognized net income of $6.2 million, or $0.19 per basic share
and $0.18 per diluted share, in the second quarter of 2002 compared to net
income of $21.8 million, or $0.80 per basic share and $0.77 per diluted share,
in the second quarter of 2001.
Six Months Ended June 30, 2002 as Compared to the Six Months Ended June 30,
2001
Revenues, including the effects of hedging activities, decreased $57.2
million in the first six months of 2002 compared to the first six months of
2001. The decrease in revenues was primarily due to lower natural gas production
and prices in the first six months of 2002. Excluding the effects of hedging
activities, natural gas revenues decreased $86.1 million and oil and condensate
revenues increased $3.8 million. Revenues from natural gas hedging activities
improved approximately $25.1 million in the first six months of 2002 compared to
the same period of 2001.
Production decreased approximately 5.6 Bcfe in the first six months of 2002
compared to the first six months of 2001. Average daily production in the first
six months of 2002 was 113 MMcfe compared to 144 MMcfe in the same period of
2001. Natural gas revenues decreased $86.1 million due to lower volumes of 6.6
Bcf and lower prices in the first six months of 2002. Excluding the effects of
hedging activities, natural gas prices averaged $3.01 per Mcf in the first six
months of 2002 compared to $5.64 per Mcf in the same period of 2001. The rapid
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 six months of 2002. Oil and condensate
revenues increased $3.8 million primarily due to higher production volumes of
174 MBbls. Oil and condensate prices averaged $24.38 per barrel in the first six
months of 2002 compared to $27.42 in the same period of 2001.
Lease operating expenses increased $1.1 million in the first six months of
2002 compared to the first six months of 2001. Of the total increase in lease
operating expenses, approximately $1.6 million was attributable to wells on 13
new blocks that commenced production subsequent to June 30, 2001 and $0.6
million related to workover activities, offset in part by a decrease of $1.1
million in expenses associated with existing wells.
DD&A decreased $1.5 million in the first six months of 2002 compared to the
first six months of 2001. Of the total decrease in DD&A, $8.7 million related to
lower production volumes of 5.6 Bcfe, offset in part by $7.0 million related to
an increase in the DD&A rate and $0.2 million related to an increase in other
property and equipment depreciation and amortization in the first six months of
2002 compared to the same period of 2001.
15
General and administrative expenses increased approximately $0.7 million in
the first six months of 2002 compared to the first six 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.
Interest income decreased $1.9 million in the first six months of 2002
compared to the first six months of 2001 primarily due to lower average cash and
short-term investment balances and significantly lower interest rates in the
first six months of 2002. Interest expense increased $0.2 million in the first
six months of 2002 compared to the same period of 2001 primarily due to
borrowings of $37.0 million in the first quarter of 2002. On April 3, 2002, the
Company repaid all of its outstanding borrowings of $37.0 million under the
Credit Facility.
Income tax provision decreased $21.4 million in the first six months of
2002 compared to the first six months of 2001, primarily due to lower earnings
in the first six months of 2002. Income taxes were accrued at a 36 percent
effective tax rate in the first six months of 2002 and 2001.
The Company recognized net income of $11.8 million, or $0.39 per basic
share and $0.38 per diluted share, in the first six months of 2002 compared to
net income of $49.9 million, or $1.85 per basic share and $1.76 per diluted
share, in the first six months 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 $300 million and has recorded capital expenditures of
approximately $188.1 million in the first six 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 approximately $40.8 million beginning in the fourth quarter of 2000 through
June 30, 2002 and expects to incur approximately $105 million in future
development costs during the remainder of 2002 and 2003. The 2002 capital
expenditure plans include a total of approximately $30 million related to the
Front Runner project.
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
six 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 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 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.
16
Cash and cash equivalents increased $82.0 million to $96.1 million at June
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, $41.8 million provided by operating activities and $188.1 million
used in investing activities.
Operating Activities
Net cash provided by operating activities in the first six months of 2002
decreased 71 percent to $41.8 million primarily as a result of 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 second
half of 2002 as compared to the first half 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 3A.
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 increase in accounts receivable of $16.3 million was
primarily related to an increase in the natural gas and oil revenue accrual of
$8.0 million at June 30, 2002 due to higher commodity prices in June 2002
compared to December 2001 and an increase in joint interest billing receivables
of approximately $7.3 million due to higher levels of operated drilling and
development activities in the second quarter of 2002 compared to the fourth
quarter of 2001. The net increase in accounts payable and accrued liabilities of
$11.2 million was primarily due to costs associated with increased drilling and
development activities in the second quarter of 2002 compared to the fourth
quarter of 2001.
Investing Activities
Net cash used in investing activities in the first six months of 2002
increased 49 percent to $188.1 million compared to the first six months of 2001.
Net oil and gas property capital expenditures were $184.4 million. Additionally,
other property and equipment capital expenditures were $3.7 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. The Company drilled 14 wells in the
first six months of 2002, nine of which were successful. In 2001, the Company
drilled 35 wells, 19 of which were successful. Since inception and through June
30, 2002, the Company has drilled 108 wells, 65 of which were successful,
representing a success rate of 60 percent. Dry hole costs, including associated
leasehold costs, incurred for the six months ended June 30, 2002 were
approximately $29.4 million.
The Company has capital expenditure plans for 2002 totaling approximately
$300 million, primarily for costs related to exploration and development
programs. The 2002 budget includes development costs that are contingent on the
success of exploratory drilling. The Company does not anticipate any significant
abandonment or dismantlement costs in 2002. 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 six
months of 2002, the Company incurred acquisition, exploration and development
costs of $35.7 million, $107.1 million and $56.6 million, respectively. The
costs associated with unproved properties and properties under development not
included in the amortization base were $159.2 million as of June 30, 2002 and
$102.9 million as of December 31, 2001 and included the following (in
thousands):
17
As of As of
June 30, December 31,
2002 2001
------------ -------------
Leasehold, delay rentals and seismic data $128,090 $ 92,150
Wells in-progress ....................... 26,436 10,112
Wells pending determination ............. 3,677 --
Capitalized interest .................... 372 372
Other ................................... 637 247
-------- --------
Total .............................. $159,212 $102,881
======== ========
Financing Activities
Net cash provided by financing activities of $228.3 million in the first
six 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
bank's 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 June 30, 2002, the Company was
in compliance with the covenants and restrictive provisions. As of August 12,
2002, the Company had no outstanding borrowings under the Credit Facility.
Item 3A. 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 take the
form of swap contracts or costless collars 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.
The Company enters into NYMEX related swap contracts and collar
arrangements from time to time. The Company's swap contracts 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
18
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. Some of the
master agreements require the Company to make margin payments to counterparties
when net exposure exceeds a certain threshold. During the second quarter of 2002
and as of August 12, 2002, the Company had no such margin obligations.
As of June 30, 2002, Spinnaker's commodity price risk management positions
in fixed price natural gas swap contracts were as follows:
Average Weighted
Daily Average Net Hedge
Volume Price (Per Positions
Period (MMBtu) (MMBtu) (in thousands)
- ------------------------- ----------- --------- ---------------
Third Quarter 2002 ...... 80,000 $ 3.37 $ 803
Fourth Quarter 2002 ..... 86,685 3.64 413
First Quarter 2003 ...... 50,000 3.61 (1,344)
Second Quarter 2003 ..... 50,000 3.52 (971)
Third Quarter 2003 ...... 50,000 3.55 (1,195)
Fourth Quarter 2003 ..... 50,000 3.63 (1,694)
----------
Total .............. $ (3,988)
==========
Based upon the Company's assessment of its derivative contracts at June 30,
2002, it reported a net liability of $4.0 million. The components of the net
liability were as follows (in thousands):
As of As of
June 30, December 31,
2002 2001
-------------- ----------------
Current:
Hedging asset..................... $ 2,637 $20,593
Hedging liability................. (3,736) -
Non-current:
Hedging asset..................... $ 138 $ 1,726
Hedging liability................. (3,027) -
The Company also reported a loss in accumulated other comprehensive income
of $2.6 million, net of income taxes of $1.4 million. The ineffective component
of the derivatives recognized in earnings was a loss less than $0.1 million in
the first six months of 2002.
In connection with monthly settlements, the Company recognized net hedging
gains of $6.5 million in revenues in the first six months of 2002. Based on
future natural gas prices as of June 30, 2002, the Company would reclassify a
net loss of $1.1 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.
19
Subsequent to June 30, 2002, Spinnaker entered into additional swap
contracts for the third quarter of 2002. Spinnaker's commodity price risk
management positions in fixed price natural gas swap contracts and the related
fair values, using natural gas forward prices as of August 12, 2002 and July and
August settlements, were as follows:
Average Weighted
Daily Average Net Hedge
Volume Price (Per Positions
Period (MMBtu) (MMBtu) (in thousands)
- ---------------------- -------- ---------- ----------------
Third Quarter 2002 ...... 93,261 $ 3.32 $ 2,208
Fourth Quarter 2002 ..... 86,685 3.64 2,712
First Quarter 2003 ...... 50,000 3.61 (538)
Second Quarter 2003 ..... 50,000 3.52 (464)
Third Quarter 2003 ...... 50,000 3.55 (615)
Fourth Quarter 2003 ..... 50,000 3.63 (1,193)
-------
Total .............. $ 2,110
=======
20
PART II - OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
The Company held its 2002 Annual Meeting of Stockholders ("Annual Meeting")
on Tuesday, May 7, 2002. The meeting was held to elect seven directors to serve
until the 2003 Annual Meeting of Stockholders and to ratify the selection of
KPMG LLP as independent public accountants of the Company for the fiscal year
ending December 31, 2002.
The "For" column represents affirmative votes by holders of Common Stock
represented by either proxy or at the Annual Meeting. Accordingly, abstentions
and "broker non-votes" had the same effect as a vote against a director. The
results of the voting related to the election of the nominees for director were
as follows:
Against or
Name For Withheld
- ----------------------- --- ----------
Roger L. Jarvis ......... 17,599,793 7,614,023
Sheldon R. Erikson ...... 22,931,798 2,282,018
Jeffrey A. Harris ....... 24,020,054 1,193,762
Michael E. McMahon ...... 24,005,399 1,208,417
Michael G. Morris ....... 24,020,112 1,193,704
Howard H. Newman ........ 24,005,232 1,208,584
Michael E. Wiley ........ 23,331,915 1,881,901
Stockholders voted 24,948,685 shares "for" and 258,485 shares "against" the
proposal to ratify the selection of KPMG LLP as independent public accountants
of the Company for the fiscal year ending December 31, 2002, with 6,646 votes
abstaining.
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 April 5, 2002 and filed on April
11, 2002 reported that the Company decided to dismiss Arthur Andersen
LLP as its independent public accountants and engaged KPMG LLP to
serve as its independent public accountants for 2002.
21
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: August 13, 2002 By: /s/ ROBERT M. SNELL
-------------------------- ----------------------------------
Robert M. Snell
Vice President, Chief Financial
Officer and Secretary
Date: August 13, 2002 By: /s/ JEFFREY C. ZARUBA
-------------------------- ----------------------------------
Jeffrey C. Zaruba
Vice President, Treasurer and
Assistant Secretary
22
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
23