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UNITED STATES
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 March 31, 2004
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in its Charter)
TEXAS 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Drive, Suite 400
Houston, Texas 77060
(Address of principal executive offices) (Zip Code)
(281) 874-2700
(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 and Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
-------- --------
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes X No
-------- --------
Indicate the number of shares outstanding of each of the Registrant's classes
of common stock, as of the latest practicable date.
Common Stock 27,712,536 Shares
($.01 Par Value) (Outstanding at April 30, 2004)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2004
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets
- March 31, 2004 and December 31, 2003 3
Consolidated Statement of Income
- For the Three-month period ended March 31, 2004 and 2003 5
Consolidated Statements of Stockholders' Equity
- For the Three-month period ended March 31, 2004 and
year ended December 31, 2003 6
Consolidated Statement of Cash Flows
- For the Three-month period ended March 31, 2004 and 2003 7
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk 25
Item 4. Controls and Procedures 26
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 27
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders None
Item 5. Other Information 27
Item 6. Exhibit Index and Reports on Form 8-K 27
SIGNATURES 28
2
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
March 31, 2004 December 31, 2003
------------------------ -------------------------
ASSETS
Current Assets:
Cash and cash equivalents $ 4,398,581 $ 1,066,280
Accounts receivable -
Oil and gas sales 27,201,434 26,082,650
Joint interest owners 1,942,313 1,350,707
Other current assets 6,959,951 4,957,647
------------------------ -------------------------
Total Current Assets 40,502,279 33,457,284
------------------------ -------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 1,341,732,893 1,305,763,355
Unproved properties not being amortized 67,625,981 67,557,969
------------------------ -------------------------
1,409,358,874 1,373,321,324
Furniture, fixtures, and other equipment 10,936,689 10,602,786
------------------------ -------------------------
1,420,295,563 1,383,924,110
Less-Accumulated depreciation, depletion,
and amortization (585,839,389) (567,464,334)
------------------------ -------------------------
834,456,174 816,459,776
------------------------ -------------------------
Other Assets:
Deferred income taxes 3,663,957 1,905,909
Debt issuance costs 7,746,868 8,015,575
------------------------ -------------------------
11,410,825 9,921,484
------------------------ -------------------------
$ 886,369,278 $ 859,838,544
======================== =========================
See accompanying notes to consolidated financial statements.
3
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
March 31, 2004 December 31, 2003
------------------------ -----------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 16,434,311 $ 25,450,477
Accrued capital costs 22,725,804 29,417,542
Accrued interest 10,072,226 8,748,656
Undistributed oil and gas revenues 6,639,926 4,939,667
----------------------- -----------------------
Total Current Liabilities 55,872,267 68,556,342
----------------------- -----------------------
Long-Term Debt 356,876,926 340,254,783
Deferred Income Taxes 49,425,159 43,498,682
Asset Retirement Obligation 10,367,979 10,137,473
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000
shares authorized, none outstanding --- ---
Common stock, $.01 par value, 85,000,000
shares authorized, 28,102,324 and 28,011,109
shares issued, and 27,621,456 and 27,484,091
shares outstanding, respectively 281,023 280,111
Additional paid-in capital 336,050,367 334,865,204
Treasury stock held, at cost, 480,868 and
527,018 shares, respectively (6,896,245) (7,558,093)
Retained earnings 84,661,238 70,073,384
Other comprehensive loss, net of taxes (269,436) (269,342)
----------------------- -----------------------
413,826,947 397,391,264
----------------------- -----------------------
$ 886,369,278 $ 859,838,544
======================= =======================
See accompanying notes to consolidated financial statements.
4
SWIFT ENERGY COMPANY
Consolidated Statements of Income
Three months ended
----------------------------------------------
03/31/04 03/31/03
---------------------- ---------------------
Revenues:
Oil and gas sales $ 65,953,770 $ 54,850,299
Price-risk management and other, net (598,040) (1,350,306)
---------------------- ---------------------
65,355,730 53,499,993
---------------------- ---------------------
Costs and Expenses:
General and administrative, net 4,029,674 3,556,548
Depreciation, depletion and amortization 18,295,684 14,911,763
Accretion of asset retirement obligation 170,476 215,383
Lease operating costs 9,625,980 7,313,104
Severance and other taxes 6,246,559 4,594,549
Interest expense, net 6,901,175 6,684,902
---------------------- ---------------------
45,269,548 37,276,249
---------------------- ---------------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle 20,086,182 16,223,744
Provision for Income Taxes 5,498,328 5,738,807
---------------------- ---------------------
Income Before Cumulative Effect of Change
in Accounting Principle 14,587,854 10,484,937
Cumulative Effect of Change in Accounting
Principle (net of taxes) --- 4,376,852
----------------------- ---------------------
Net Income $ 14,587,854 $ 6,108,085
====================== =====================
Per share amounts -
Basic: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.53 $ 0.38
Cumulative Effect of Change in
Accounting Principle --- (0.16)
---------------------- ---------------------
Net Income $ 0.53 $ 0.22
====================== =====================
Diluted: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.52 $ 0.38
Cumulative Effect of Change in
Accounting Principle --- (0.16)
---------------------- ---------------------
Net Income $ 0.52 $ 0.22
====================== =====================
Weighted Average Shares Outstanding 27,552,827 27,243,142
====================== =====================
See accompanying notes to consolidated financial statements.
5
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Accumulated
Additional Other
Common Paid-in Treasury Retained Comprehensive
Stock (1) Capital Stock Earnings Loss Total
---------- -------------- ------------- ------------- -------------- --------------
Balance, December 31, 2002 $ 278,116 $ 333,543,471 $ (8,749,922) $ 40,179,572 $ (178,053) $ 365,073,184
Stock issued for benefit plans
(83,201 shares) 1 (408,178) 1,191,829 - - 783,652
Stock options exercised
(142,807 shares) 1,428 1,315,964 - - - 1,317,392
Employee stock purchase plan
(56,574 shares) 566 413,947 - - - 414,513
Comprehensive income:
Net income - - - 29,893,812 - 29,893,812
Change in fair value of
cash flow hedges, net of
income tax (91,289) (91,289)
--------------
Total comprehensive income - - - - - 29,802,523
---------- -------------- ------------- ------------- -------------- --------------
Balance, December 31, 2003 $ 280,111 $ 334,865,204 $ (7,558,093) $ 70,073,384 $ (269,342) $ 397,391,264
========== ============== ============= ============= ============== ==============
Stock issued for benefit plans
(46,150 shares) - 166,298 661,848 - - 828,146
Stock options exercised
(91,215 shares) 912 1,018,865 - - - 1,019,777
Comprehensive income:
Net income - - - 14,587,854 - 14,587,854
Change in fair value of cash
flow hedges, net of income tax
income tax (94) (94)
--------------
Total comprehensive income 14,587,760
---------- --------------- ------------- ------------- -------------- --------------
Balance, March 31, 2004 $ 281,023 $ 336,050,367 $ (6,896,245) $ 84,661,238 $ (269,436) $ 413,826,947
========== ============== ============= ============= ============== ==============
(1)$.01 par value
See accompanying notes to consolidated financial statements.
6
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Period Ended March 31,
-----------------------------------------------
2004 2003
--------------------- --------------------
Cash Flows From Operating Activities:
Net income $ 14,587,854 $ 6,108,085
Adjustments to reconcile net income to net cash provided
by operating activities -
Cumulative effect of change in accounting principle --- 4,376,852
Depreciation, depletion, and amortization 18,295,684 14,911,763
Accretion of asset retirement obligation 170,476 215,383
Deferred income taxes 5,434,312 5,738,807
Other 274,125 291,780
Change in assets and liabilities -
Increase in accounts receivable (2,021,976) (7,076,900)
Increase in accounts payable and accrued liabilities 1,531,695 747,167
Increase in accrued interest 1,323,570 1,485,861
--------------------- --------------------
Net Cash Provided by Operating Activities 39,595,740 26,798,798
--------------------- --------------------
Cash Flows From Investing Activities:
Additions to property and equipment (45,149,834) (26,335,122)
Proceeds from the sale of property and equipment 23,255 551,263
Net cash distributed as operator of
oil and gas properties (8,707,560) (5,889,986)
Net cash received (distributed) as operator of partnerships
and joint ventures 105,566 (286,935)
Other (934) (35,839)
--------------------- --------------------
Net Cash Used in Investing Activities (53,729,507) (31,996,619)
--------------------- --------------------
Cash Flows From Financing Activities:
Net proceeds from bank borrowings 16,600,000 5,700,000
Net proceeds from issuances of common stock 866,068 ---
--------------------- --------------------
Net Cash Provided by Financing Activities 17,466,068 5,700,000
--------------------- --------------------
Net Increase in Cash and Cash Equivalents 3,332,301 502,179
Cash and Cash Equivalents at Beginning of Period 1,066,280 3,816,107
--------------------- --------------------
Cash and Cash Equivalents at End of Period $ 4,398,581 $ 4,318,286
===================== ====================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized $ 5,300,358 $ 4,939,154
Cash paid during period for income taxes $ --- $ ---
See accompanying notes to consolidated financial statements.
7
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) GENERAL INFORMATION
The consolidated financial statements included herein have been
prepared by Swift Energy Company and are unaudited, except for the
consolidated balance sheet at December 31, 2003 and consolidated statement
of stockholders' equity for the year ended December 31, 2003, which has
been prepared from the audited financial statements at that date. The
financial statements reflect necessary adjustments, all of which were of a
recurring nature, and are in the opinion of our management necessary for a
fair presentation. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with accounting
principles generally accepted in the United States have been omitted
pursuant to the rules and regulations of the Securities and Exchange
Commission. We believe that the disclosures presented are adequate to allow
the information presented not to be misleading. Certain reclassifications
have been made to prior period financial information to conform to the
current period presentation. The consolidated financial statements should
be read in conjunction with the audited financial statements and the notes
thereto included in the latest Form 10-K and Annual Report.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Oil and Gas Properties
We follow the "full-cost" method of accounting for oil and gas property
and equipment costs. Under this method of accounting, all productive and
nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Under the full-cost
method of accounting, such costs may be incurred both prior to and after
the acquisition of a property and include lease acquisitions, geological
and geophysical services, drilling, completion, and equipment. Internal
costs incurred that are directly identified with exploration, development,
and acquisition activities undertaken by us for our own account, and which
are not related to production, general corporate overhead, or similar
activities, are also capitalized. For the three months ended March 31, 2004
and 2003, such internal costs capitalized totaled $2.9 million and $3.0
million, respectively. Interest costs are also capitalized to unproved oil
and gas properties. For the three months ended March 31, 2004 and 2003,
capitalized interest on our unproved properties totaled $1.6 million and
$1.8 million, respectively. Interest not capitalized and general and
administrative costs related to production and general overhead are
expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil
and gas properties, except in transactions involving a significant amount
of reserves or where the proceeds from the sale of oil and gas properties
would significantly alter the relationship between capitalized costs and
proved reserves of oil and gas attributable to a cost center. Internal
costs associated with selling properties are expensed as incurred.
Future development costs are estimated property-by-property based on
current economic conditions and are amortized to expense as our capitalized
oil and gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization
of oil and gas properties by the unit-of-production method. Under this
method, we compute the provision by multiplying the total unamortized costs
of oil and gas properties-including future development costs, gas
processing facilities and capitalized asset retirement obligations, but
excluding costs of unproved properties-by an overall rate determined by
dividing the physical units of oil and gas produced during the period by
the total estimated units of proved oil and gas reserves at the beginning
of the period. This calculation is done on a country-by-country basis.
Furniture, fixtures, and other equipment are depreciated by the
straight-line method at rates based on the estimated useful lives of the
property. Repairs and maintenance are charged to expense as incurred.
Renewals and betterments are capitalized.
Geological and geophysical (G&G) costs incurred on developed properties
are recorded in Proved Property
8
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
and therefore subject to amortization. In exploration areas, G&G costs are
capitalized in Unproved Property and evaluated as part of the total
capitalized costs associated with a prospect.
The cost of unproved properties not being amortized is assessed
quarterly, on a country-by-country basis, to determine whether such
properties have been impaired. In determining whether such costs should be
impaired, we evaluate current drilling results, lease expiration dates,
current oil and gas industry conditions, international economic conditions,
capital availability, foreign currency exchange rates, the political
stability in the countries in which we have an investment, and available
geological and geophysical information. Any impairment assessed is added to
the cost of proved properties being amortized. To the extent costs
accumulate in countries where there are no proved reserves, any costs
determined by management to be impaired are charged to expense.
Full-Cost Ceiling Test. At the end of each quarterly reporting period,
the unamortized cost of oil and gas properties, including gas processing
facilities and capitalized asset retirement obligations, net of related
salvage values and deferred income taxes, and excluding the asset
retirement obligation liability is limited to the sum of the estimated
future net revenues from proved properties, excluding cash outflows from
asset retirement obligations, using period-end prices, adjusted for the
effects of hedging, discounted at 10%, and the lower of cost or fair value
of unproved properties, adjusted for related income tax effects ("Ceiling
Test"). Our hedges at March 31, 2004 consisted of natural gas price floors
with strike prices lower than the period end price and thus did not affect
prices used in this calculation. This calculation is done on a
country-by-country basis for those countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There
are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production, timing, and plan
of development. The accuracy of any reserves estimate is a function of the
quality of available data and of engineering and geological interpretation
and judgment. Results of drilling, testing, and production subsequent to
the date of the estimate may justify revision of such estimate.
Accordingly, reserves estimates are often different from the quantities of
oil and gas that are ultimately recovered.
Given the volatility of oil and gas prices, it is reasonably possible
that our estimate of discounted future net cash flows from proved oil and
gas reserves could change in the near term. If oil and gas prices decline
from our period-end prices used in the Ceiling Test, even if only for a
short period, it is possible that additional non-cash write-downs of oil
and gas properties could occur in the future.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts
of Swift Energy Company and our wholly owned subsidiaries, which are
engaged in the exploration, development, acquisition, and operation of oil
and natural gas properties, with a focus on onshore and inland waters oil
and natural gas reserves in Texas and Louisiana, as well as onshore oil and
natural gas reserves in New Zealand. Our investments in affiliated oil and
gas partnerships and other ventures are accounted for using the
proportionate consolidation method, whereby our proportionate share of each
entity's assets, liabilities, revenues, and expenses are included in the
appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing
the consolidated financial statements.
Accounts Receivable
Included in the total 'Accounts receivable' balance, which totaled
$29.1 million and $27.4 million at March 31, 2004 and December 31, 2003,
respectively, on the accompanying consolidated balance sheet, is
approximately $2.3 million of receivables related to hydrocarbon volumes
produced during 2001 and 2002 that have been disputed since early 2003.
Accordingly, we did not record a receivable with regard to 2003 volumes. We
continually assess the collectibility of trade and other receivables, and
based on our judgment,
9
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
we establish a reserve when we believe a receivable may not be collected.
At both March 31, 2004 and December 31, 2003, we had an allowance for
doubtful accounts of $0.8 million. These allowances for doubtful accounts
have been deducted from the total "Accounts receivable" balances on the
accompanying consolidated balance sheets.
Use of Estimates
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, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from estimates. Significant estimates include proved reserve
volumes, DD&A, and deferred income taxes.
Income Taxes
Income tax expense in the first quarter of 2004 includes a reduction
from the U.S. statutory rate, primarily from the result of the currency
exchange rate effect on the New Zealand deferred tax, along with a
reduction in tax expense primarily attributable to an adjustment of the tax
basis on the TAWN properteries acquired in 2002.
Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. Diluted earnings per share ("Diluted EPS") for all periods also
assume, as of the beginning of the period, exercise of stock options using
the treasury stock method. Certain of our stock options that would
potentially dilute Basic EPS in the future were antidilutive for the three
months ended March 31, 2004 and 2003. The following is a reconciliation of
the numerators and denominators used in the calculation of Basic and
Diluted EPS (before cumulative effect of change in accounting principle)
for the three-month periods ended March 31, 2004 and 2003:
Three Months Ended March 31,
-----------------------------------------------------------------------------------
2004 2003
----------------------------------------- ---------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
-------------- ------------ ---------- ------------- ----------- ----------
Basic EPS:
Net Income Before Cumulative
Effect of Change in
Accounting Principle and
Share Amounts $ 14,587,854 27,552,827 $ .53 $ 10,484,937 27,243,142 $ .38
Stock Options --- 546,460 --- 66,734
-------------- ------------ ------------- -----------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in
Accounting Principle and
Assumed Share Conversions $ 14,587,854 28,099,287 $ .52 $ 10,484,937 27,309,876 $ .38
-------------- ------------ ------------- -----------
Options to purchase approximately 3.2 million shares of common stock,
at an average exercise price of $16.58 were outstanding at March 31, 2004,
and 3.0 million shares of common stock, at an average price of $16.59 were
outstanding at March 31, 2003. Approximately 0.9 million and 1.7 million
options to purchase shares were not included in the computation of Diluted
EPS for the three-month periods ended March 31, 2004 and 2003,
respectively, because the options were antidilutive, given that the option
price was greater than the average closing market price of the common
shares during those periods.
10
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Other Comprehensive Loss
We follow the provisions of SFAS No. 130 "Reporting Comprehensive
Income," which establishes standards for reporting comprehensive income. In
addition to net income, comprehensive income or loss includes all changes
to equity during a period, except those resulting from investments and
distributions to the owners of the Company. At March 31, 2004, we recorded
$269,436, net of taxes of $151,558, of derivative losses in "Other
comprehensive loss" on the accompanying balance sheet. The components of
accumulated other comprehensive loss and related tax effects for the
three-month period ended March 31, 2004 were as follows:
Gross Value Tax Effect Net of Tax Value
---------------- --------------- -----------------
Balance at December 31, 2003 $ 420,847 $ 151,505 $ 269,342
Change in fair value of cash flow
hedges 634,987 228,595 406,392
Effect of cash flow hedges settled
during the period (634,840) (228,542) (406,298)
---------------- --------------- -----------------
Balance at March 31, 2004 $ 420,994 $ 151,558 $ 269,436
================ =============== =================
For the three-month periods ended March 31, 2004 and 2003, total
comprehensive income was $14.6 million and $6.0 million, respectively.
Stock Based Compensation
We account for three stock-based compensation plans under the
recognition and measurement principles of APB Opinion No. 25, "Accounting
for Stock Issued to Employees," and related interpretations. No stock-based
employee compensation cost is reflected in net income, as all options
granted under those plans had an exercise price equal to the market value
of the underlying common stock on the date of the grant; or in the case of
the employee stock purchase plan, the purchase price is 85% of the lower of
the closing price of our common stock as quoted on the New York Stock
Exchange at the beginning or end of the plan year or a date during the year
chosen by the participant. Had compensation expense for these plans been
determined based on the fair value of the options consistent with SFAS No.
123, "Accounting for Stock-Based Compensation," our net income and earnings
per share would have been adjusted to the following pro forma amounts:
Three Months Ended March 31,
----------------------------------------------
2004 2003
--------------------- ------------------
Net Income: As Reported $14,587,854 $6,108,085
Stock-based employee compensation
expense determined under fair value
method for all awards, net of tax (1,022,306) (981,942)
--------------------- ------------------
Pro Forma $13,565,548 $5,126,143
Basic EPS: As Reported $.53 $.22
Pro Forma $.49 $.19
Diluted EPS: As Reported $.52 $.22
Pro Forma $.48 $.18
Pro forma compensation cost reflected above may not be representative
of the cost to be expected in future periods. The fair value of each option
grant is estimated on the date of grant using the Black-Scholes
option-pricing model.
11
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Price-Risk Management Activities
We follow SFAS No. 133, which requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. The statement also establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in
the balance sheet as either an asset or a liability measured at its fair
value. Special hedge accounting for qualifying hedges would allow the gains
and losses on derivatives to offset related results on the hedged item in
the income statements and requires that a company formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting. Hedges that do not meet the criteria for special hedge
accounting are accounted for under mark to market accounting. SFAS No. 133,
as amended, was adopted by us on January 1, 2001.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the purchase
of price floors and collars. During the first quarters of 2004 and 2003, we
recognized net losses of $0.6 million and $1.4 million, respectively,
relating to our derivative activities. This activity is recorded in
"Price-risk management and other, net" on the accompanying statements of
income. At March 31, 2004, we had recorded $0.3 million, net of taxes of
$0.2 million, of derivative losses in "Other comprehensive loss" on the
accompanying balance sheet. This amount represents the change in fair value
for the effective portion of our hedging transactions that were qualified
as cash flow hedges. The ineffectiveness reported in "Price-risk management
and other, net" for the first three months of 2004 and 2003 was not
material. We expect to reclassify all amounts currently held in "Other
comprehensive loss" into the statement of income within the next three
months when the forecasted sale of hedged production occurs.
As of March 31, 2004, we had in place natural gas price floors in
effect for the April 2004 contract month through the June 2004 contract
month, which cover a portion of our domestic natural gas production for
April 2004 to June 2004. The natural gas price floors cover notional
volumes of 1,800,000 Mmbtu with a weighted average floor price of $4.83 per
Mmbtu. Our hedges in place at March 31, 2004 are expected to cover
approximately 55% to 65% of our domestic natural gas production from April
2004 to June 2004. When we entered into these transactions, they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of natural gas production. Changes in the fair value of a
hedge that is highly effective and is designated and qualifies as a cash
flow hedge, to the extent that the hedge is effective, are recorded in
"Other Comprehensive Income (Loss)". When the hedged transactions are
recorded upon the actual sale of oil and natural gas, these gains or losses
are reclassified from "Other comprehensive income (loss)" and recorded in
"Price-risk management and other, net" on the consolidated statement of
income. The fair value of our derivatives are computed using the
Black-Scholes option pricing model and are periodically verified against
quotes from brokers. The fair value of these instruments at March 31, 2004,
was less than $0.1 million and is recognized on the balance sheet in "Other
current assets."
Asset Retirement Obligation
In June 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." The statement requires
entities to record the fair value of a liability for legal obligations
associated with the retirement obligations of tangible long-lived assets in
the period in which it is incurred. When the liability is initially
recorded, the carrying amount of the related long-lived asset is increased.
The liability is discounted from the year the well is expected to deplete.
Over time, accretion of the liability is recognized each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Upon settlement of the liability, an entity either settles the obligation
for its recorded amount or incurs a gain or loss upon settlement. This
standard requires us to record a liability for the fair value of our
dismantlement and abandonment costs, excluding salvage values. SFAS No. 143
was adopted by us effective January 1, 2003. Upon adoption of SFAS No. 143
effective January 1, 2003, we recorded an asset retirement obligation of
$8.9 million, an addition to oil and gas properties of $2.0 million and a
non-cash charge of $4.4 million (net of $2.5 million of deferred taxes),
which is recorded as a Cumulative Effect of Change in
12
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Accounting Principle. The cumulative charge to earnings took into
consideration the impact of adopting SFAS No. 143 on previous full-cost
ceiling tests. SFAS No. 143 is silent with respect to whether prior period
ceiling tests should be reflected in the implementation entry calculation;
however, management believes that any impairment on the properties should
be reflected in the historical periods. Had we not considered the impact of
adopting SFAS No. 143 on previous full-cost ceiling tests, the charge
recognized would have been reduced. Excluding the Cumulative Effect of
Change in Accounting Principle, the adoption of SFAS No. 143 reduced our
net income for the three months ended March 31, 2003 by approximately $0.2
million, or $0.01 per diluted share. The following provides a roll-forward
of our asset retirement obligation:
2004 2003
---------------- ---------------
Asset Retirement Obligation recorded as of January 1 $ 10,137,473 $ 8,934,320
Accretion expense for the three months ended March 31 170,476 215,383
Liabilities incurred for new wells and facilities construction 81,953 35,843
Reductions due to sold and abandoned wells (26,000) ---
Increase due to currency exchange rate fluctuations 4,077 ---
---------------- ---------------
Asset Retirement Obligation as of March 31 $ 10,367,979 $ 9,185,546
---------------- ---------------
New Accounting Principles
In March 2004, the FASB issued an exposure draft that would amend SFAS
No. 123 "Accounting for Stock Based Compensation" and SFAS No. 95
"Statement of Cash Flows." This exposure draft was issued to improve
existing accounting rules and provide more complete, higher quality
information for investors on employee stock compensation matters. The
comment period for the exposure draft ends June 30, 2004. The exposure
draft covers a wide range of equity-based arrangements including stock
options. Under the FAS's proposal, share-based payments to employees,
including stock options, would be treated the same as other forms of
compensation by recognizing the related cost in the income statement. The
expense of the award would generally be measured at fair value at the grant
date. Current accounting guidance requires that the expense relating to
employee stock options only be disclosed in the footnotes of the financial
statements. The Company is evaluating the effects that will result from
future adoption of this proposed statement or related accounting changes.
In January 2003, the FASB issued Interpretation No. 46 (Revised
December 2003), Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51 Consolidated
Financial Statements (the "Interpretation"). The Interpretation
significantly changes whether entities included in its scope are
consolidated by their sponsors, transferors, or investors. The
Interpretation introduces a new consolidation model-the variable interest
model; which determines control (and consolidation) based on potential
variability in gains and losses of the entity being evaluated for
consolidation. The Interpretation provides guidance for determining whether
an entity lacks sufficient equity or its equity holders lack adequate
decision-making ability. These variable interest entities ("VIEs") are
covered by the Interpretation and are to be evaluated for consolidation
based on their variable interests. These provisions applied immediately to
variable interests in VIEs created after January 31, 2003, and to variable
interests in special purpose entities for periods ending after December 15,
2003. The provisions apply for all other types of variable interests in
VIEs for periods ending after March 15, 2004. We have no variable interests
in VIEs, nor do we have variable interests in special purpose entities. The
adoption of this interpretation had no impact on the Company's financial
position or results of operations.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations,"
and SFAS No. 142, "Goodwill and Intangible Assets." We adopted these
statements on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires that all business combinations initiated after June 30, 2001, be
accounted for using the purchase method and that intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142
establishes new guidelines for accounting for goodwill and other intangible
assets. Under SFAS No.
13
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
142, goodwill and other indefinite lived intangible assets are not
amortized but reviewed annually for impairment.
An issue, EITF Issue 04-2, had arisen for companies engaged in oil and
gas exploration and production regarding the application of SFAS No. 141
and SFAS No. 142 as they relate to mineral rights held under lease or other
contractual arrangements, and as to whether costs associated with these
rights should be classified as intangible assets on the balance sheet,
apart from other capitalized oil and gas property costs, and to provide
specific footnote disclosure. In March 2004, the Emerging Issues Task Force
of the FASB reached a consensus that mineral rights are tangible assets. In
April 2004, the FASB ratified the EITF's consensus by issuing FASB Staff
Position (FSP) 141-1 and 142-1, which amend SFAS No. 141 and SFAS No. 142
to address the inconsistency between the EITF consensus on EITF Issue No.
04-02 and SFAS No. 141 and SFAS No. 142. The FSP is effective for reporting
periods beginning after April 29, 2004 and defines mineral rights as
tangible assets. These staff positions will have no impact on our
consolidated financial statements.
(3) LONG-TERM DEBT
Our long-term debt as of March 31, 2004 and December 31, 2003, was as
follows:
March 31, December 31,
2004 2003
------------------ -------------------
Bank Borrowings $ 32,500,000 $ 15,900,000
Senior Notes due 2009 124,376,926 124,354,783
Senior Notes due 2012 200,000,000 200,000,000
------------------ -------------------
Long-Term Debt $ 356,876,926 $ 340,254,783
------------------ -------------------
The unamortized discount on the Senior Notes due 2009 was $0.6 million
at both March 31, 2004 and December 31, 2003, respectively.
Bank Borrowings
At March 31, 2004, we had $32.5 million in outstanding borrowings under
our $300.0 million credit facility with a syndicate of ten banks that has a
borrowing base of $250.0 million and expires in October 2005. At December
31, 2003, we had $15.9 million in outstanding borrowings under our credit
facility. The interest rate is either (a) the lead bank's prime rate (4% at
March 31, 2004) or (b) the adjusted London Interbank Offered Rate ("LIBOR")
plus the applicable margin depending on the level of outstanding debt. The
applicable margin is based on the ratio of the outstanding balance to the
last calculated borrowing base. Of the $32.5 million borrowed at March 31,
2004, $30.0 million was borrowed at the LIBOR rate plus applicable margin,
which was 2.34%, the remaining $2.5 million of borrowings was borrowed at
4%.
The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $5.0 million in
any fiscal year), a remaining aggregate limitation on purchases of our
stock of $15.0 million, requirements as to maintenance of certain minimum
financial ratios (principally pertaining to working capital, debt, and
equity ratios), and limitations on incurring other debt or repurchasing our
Senior Notes. Since inception, no cash dividends have been declared on our
common stock. We are currently in compliance with the provisions of this
agreement. The credit facility is secured by our domestic oil and gas
properties. We have also pledged 65% of the stock in our two active New
Zealand subsidiaries as collateral for this credit facility. The borrowing
base is re-determined at least every six months and was reaffirmed by our
bank group at $250.0 million effective May 1, 2004. We requested that the
commitment amount with our bank group be reduced to $150.0 million
effective May 9, 2003. Under the terms of the credit facility, we can
increase this commitment amount back to the total amount of the borrowing
base at our discretion, subject to the terms of the credit agreement. The
next borrowing base review is scheduled for November 2004.
14
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Senior Notes Due 2009
Our Senior Notes due 2009 consist of $125.0 million of 10.25% Senior
Subordinated Notes due 2009. These Senior Notes were issued at 99.236% of
the principal amount on August 4, 1999, and will mature on August 1, 2009.
The Senior Notes are unsecured senior subordinated obligations and are
subordinated in right of payment to all our existing and future senior
debt, including our bank borrowings. Interest on these Senior Notes is
payable semiannually on February 1 and August 1. On or after August 1,
2004, the Senior Notes are redeemable for cash at the option of Swift, with
certain restrictions, at 105.125% of principal, declining to 100% in 2007.
Upon certain changes in control of Swift, each holder of Senior Notes will
have the right to require us to repurchase the Senior Notes at a purchase
price in cash equal to 101% of the principal amount, plus accrued and
unpaid interest to the date of purchase. The terms of these Senior Notes
include, among other restrictions, a limit on repurchases by Swift of its
common stock. We are currently in compliance with the provisions of the
indenture governing the Senior Notes.
Senior Notes Due 2012
Our Senior Notes due 2012 consist of $200.0 million of 9.375% Senior
Subordinated Notes due 2012. The Senior Notes were issued on April 11, 2002
at 100% of the principal amount, and will mature on May 1, 2012. The notes
are unsecured senior subordinated obligations and are subordinated in right
of payment to all our existing and future senior debt, including our bank
borrowings. Interest on the Senior Notes is payable semiannually on May 1
and November 1. On or after May 1, 2007, the Senior Notes are redeemable
for cash at the option of Swift, with certain restrictions, at 104.688% of
principal, declining to 100% in 2010. In addition, prior to May 1, 2005, we
may redeem up to 33.33% of the Senior Notes with the proceeds of qualified
offerings of our equity at 109.375% of the principal amount of the Senior
Notes, together with accrued and unpaid interest. Upon certain changes in
control of Swift, each holder of Senior Notes will have the right to
require us to repurchase the Senior Notes at a purchase price in cash equal
to 101% of the principal amount, plus accrued and unpaid interest to the
date of purchase. The terms of these Senior Notes include, among other
restrictions, a limit on repurchases by Swift of its common stock. We are
currently in compliance with the provisions of the indenture governing the
Senior Notes.
The aggregate maturities on our long-term debt are $0, $32.5 million,
$0, $0, $0, and $325.0 million for the remainder of 2004, 2005, 2006, 2007,
2008, and thereafter, respectively.
(4) FOREIGN ACTIVITIES
As of March 31, 2004, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $212.0 million. Approximately $177.2
million has been included in the proved properties portion of our oil and
gas properties, while $34.8 million is included as unproved properties. Our
functional currency in New Zealand is the U.S. dollar.
15
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
(5) SEGMENT INFORMATION
The Company has two reportable segments, one domestic and one foreign,
that are in the business of crude oil and natural gas exploration and
production. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies. The Company
evaluates performance based on profit or loss from oil and gas operations
before other revenues, general and administrative expenses, and interest
expense, net. The Company's reportable segments are managed separately
based on their geographic locations. Financial information by operating
segment is presented below:
Three Months Ended March 31,
--------------------------------------------------------------------------------------------
2004 2003
------------------------------------------- --------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- ------------- ------------ ------------- ------------- -------------
Oil and gas sales $ 54,666,162 $ 11,287,608 $ 65,953,770 $ 43,741,176 $ 11,109,123 $ 54,850,299
Costs and Expenses:
Depreciation, depletion and
amortization 14,517,949 3,777,735 18,295,684 9,796,980 5,114,783 14,911,763
Accretion of asset retirement
obligation 130,548 39,928 170,476 149,441 65,942 215,383
Lease operating costs 6,919,281 2,706,699 9,625,980 5,516,453 1,796,651 7,313,104
Severance and other taxes 5,418,881 827,678 6,246,559 3,656,366 938,183 4,594,549
------------- ------------- ------------ ------------- ------------- -------------
Income from oil and gas operations $ 27,679,503 $ 3,935,568 $ 31,615,071 $ 24,621,936 $ 3,193,564 $ 27,815,500
Price-risk management and other,
net (598,040) (1,350,306)
General and administrative, net 4,029,674 3,556,548
Interest expense, net 6,901,175 6,684,902
Income before income taxes and
cumulative effect of change in
accounting principle $ 20,086,182 $ 16,223,744
============ =============
Property, plant and equipment, net $ 657,041,778 $ 177,414,396 $834,456,174 $ 575,025,253 $ 163,782,385 $ 738,807,638
============= ============= ============ ============= ============= =============
16
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis supplements and is provided to
facilitate increased understanding of our consolidated financial statements
and our accompanying notes included with this report.
OVERVIEW
For the first three months of 2004, Swift Energy had revenues of $65.4
million and production of 14.3 Bcfe. Our revenues were bolstered by oil and
gas prices remaining strong in this period and domestic production in the
first quarter of 2004 increasing by 35% to 10.4 Bcfe compared to the same
period in 2003. We continued to focus our efforts and capital throughout
the quarter on better infrastructure, increased production and the
development of longer life oil reserves in the Lake Washington area. In
January 2004, we produced over 12,000 gross (10,000 net) barrels of oil
equivalent per day in Lake Washington, compared to approximately 5,000
gross (4,100 net) barrels of oil equivalent per day in January 2003. During
2004, we also allocated capital to development in our three other domestic
core areas. New Zealand accounted for 3.9 Bcfe of production in the first
quarter of 2004, a 25% decrease from production in the same period in 2003.
Natural gas production in New Zealand declined due to minimum takes from
the gas purchaser at TAWN. Increased use of hydroelectricity in New Zealand
has contributed to a short-term reduction in market demand, which is
expected to continue at least through the second quarter of this year.
While our fields at TAWN have been able to meet minimum contracted volumes
to date, it is anticipated, due to accelerated production in 2002 and 2003
along with natural gas declines, that these fields will not be able to meet
the contracted volumes beginning in the second half of this year without
additional development. We are currently considering drilling a development
well in the Tariki field in the second half of this year, but to some
extent, our ongoing activity at TAWN is affected by discussions with the
gas purchaser. New Zealand natural gas and NGL contracts are denominated in
the New Zealand dollar, which have significantly strengthened during the
last several years against the U.S. Dollar.
Our production costs were up in the first quarter of 2004 predominately
due to increased production in Lake Washington, increased severance taxes,
currency exchange rates and maintenance activities in New Zealand. Our
general and administrative expenses increased in the first quarter of 2004
predominantly due an increase in franchise tax expense, increased costs
related to our corporate governance activities and compliance with the
Sarbanes-Oxley Act, as well as higher costs in our New Zealand operations
due to currency exchange rates. We are working to reduce our production and
general and administrative costs on a per unit produced basis for the
remainder of 2004.
Our debt to PV-10 ratio has remained relatively steady at 22% at
December 31, 2003 and 21% at March 31, 2004. Our debt to capitalization
ratio was 46% at March 31, 2004 and year-end 2003. Management continues to
believe that our current cash flow is best utilized on capital projects
rather than reducing debt. We will continue to look for opportunities in
2004 to improve our balance sheet and liquidity, but expect our capital
expenditures to continue to equal or modestly exceed our cash flow for the
near term.
Our 2004 capital expenditure budget assumes increased drilling activity
in all domestic core areas except Lake Washington. In Lake Washington, the
2004 budget assumes reduced drilling activity, 25 to 30 wells, accompanied
by an extensive three-dimensional seismic survey, together with the
analysis of the resulting data, to enhance our drilling program in the area
for years to come. We plan to drill 15 to 18 wells in AWP Olmos, with the
objective of again maintaining production levels in that area.
Additionally, we expect to have ongoing exploratory efforts in our South
Texas Garcia Ranch properties. In New Zealand, we plan to drill 8 to 12
wells, primarily in the areas in which we had success in 2003. We continue
to see a tightening natural gas market and strengthening gas prices in New
Zealand. For the remainder of 2004, we believe we are positioned for
production growth of 11% to 17% and reserve growth of 5% to 8%, and expect
commodity prices to remain strong.
17
SWIFT ENERGY COMPANY
MANAGEMENT"S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
RESULTS OF OPERATIONS - Three Months Ended March 31, 2004 and 2003
Revenues. Our revenues in the first quarter of 2004 increased by 22%
compared to revenues in the same period in 2003, due primarily to an
increase in oil prices and production from our Lake Washington area.
Revenues from our oil and gas sales comprised substantially all of net
revenues for the first quarter of 2004 and 2003. Natural gas production
made up 41% of our production volumes in the first quarter of 2004 and 60%
in the same 2003 period. Domestic natural gas production made up 52% of our
total natural gas production volumes in the first quarter of 2004 and 47%
in the comparable period of 2003.
Oil and gas sales in the first quarter of 2004 increased by 20%, or
$11.1 million, from the level of those revenues for the same period in
2003. Average prices received for oil, NGL and gas were $34.14 per Bbl,
$22.30 per Bbl, and $3.64 per Mcf in the first quarter of 2004,
respectively. In the first quarter of 2003, average prices received for
oil, NGLSs and gas were $32.73 per Bbl, $21.90 per Bbl, and $3.71 per Mcf,
respectively. The increase in production volumes during the first quarter
of 2004 was primarily from our Lake Washington, AWP and Brookeland areas
domestically, and the Rimu/Kauri area in New Zealand.
In the first quarter of 2004, our $11.1 million increase in oil, NGL,
and gas sales resulted from:
oVolume variances that had a $9.8 million favorable impact on sales,
with $16.5 million of increases coming from the 539,000 Bbl increase
in oil and NGL sales volumes, offset by $6.7 million in decreases
attributable to the 1.8 Bcf decrease in gas sales volumes.
oPrice variances that had a $1.3 million favorable impact on sales, of
which $1.7 million was attributable to the 4% increase in average
combined oil and NGL prices received, partially offset by $0.4 million
in decreases attributable to the 2% decrease in average gas prices
received; and
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our four
domestic core areas and two New Zealand core areas:
Three Months March 31,
----------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
---- --------------------------------------- -----------------------------------------
2004 2003 2004 2003
---- ---- ---- ----
AWP Olmos $ 11.7 $ 12.5 2.6 2.0
Brookeland 4.6 4.3 1.0 0.8
Lake Washington 28.9 11.1 5.1 2.0
Masters Creek 5.1 9.4 1.0 1.7
Other 4.4 6.5 0.7 1.2
------------------ ------------------- ----------------- -----------------------
Total Domestic $ 54.7 $ 43.8 10.4 7.7
------------------ ------------------- ----------------- -----------------------
Rimu/Kauri 4.3 1.5 1.1 0.5
TAWN 7.0 9.6 2.8 4.7
------------------ ------------------- ----------------- -----------------------
Total New Zealand $ 11.3 $ 11.1 3.9 5.2
------------------ ------------------- ----------------- -----------------------
Total $ 66.0 $ 54.9 14.3 12.9
================== =================== ================= =======================
18
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
The following table provides additional information regarding our oil and
gas sales:
Net Sales Volume Average Sales Price
---------------- -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
----------- ---------- ---------- ------------ ----------- ---------- ----------
2003
- ----
Three Months Ended March 31:
Domestic 578 100 3.6 7.7 $32.80 $28.47 $6.03
New Zealand 112 73 4.1 5.2 $32.36 $12.89 $1.62
----------- ---------- ---------- ------------
Total 690 173 7.7 12.9 $32.73 $21.90 $3.71
=========== ========== ========== ============
2004
- ----
Three Months Ended March 31:
Domestic 1,018 211 3.1 10.4 $33.95 $24.31 $4.90
New Zealand 106 67 2.8 3.9 $36.03 $16.00 $2.27
----------- ---------- ---------- ------------
Total 1,124 278 5.9 14.3 $34.14 $22.30 $3.64
=========== ========== ========== =============
Costs and Expenses. Our total expenses in the first quarter of 2004
increased $8.0 million, or 21%, compared to expenses in the same period in
2003. The majority of the increase was due to the $3.4 million increase in
depreciation, depletion and amortization and the $2.3 million increase in
lease operating costs, both of which increased as our production volumes
increased in the 2004 period.
As discussed in Note 1 to the Consolidated Financial Statements, we
adopted SFAS No. 143 on January 1, 2003. Our adoption of SFAS No. 143
resulted in a one-time net of taxes charge of $4.4 million, which is
recorded as a "Cumulative Effect of Change in Accounting Principle" in the
2003 consolidated statement of income.
Our first quarter of 2004 general and administrative expenses, net,
increased $0.5 million, or 13%, from the level of such expenses in the 2003
period. This increase is due primarily to an increase in franchise tax
expense, increased costs related to our corporate governance activities and
compliance with the Sarbanes-Oxley Act, as well as higher costs in our New
Zealand operations due to currency exchange rates. Our general and
administrative expenses per Mcfe produced were $0.28 per Mcfe in both the
first quarter of 2004 and 2003. The portion of supervision fees recorded as
a reduction of general and administrative expenses was $1.3 million for the
first quarter of 2004 and $0.7 million for the 2003 period.
Depreciation, depletion, and amortization of our oil and gas
properties, or DD&A, increased $3.4 million, or 23%, in the first quarter
of 2004 from 2003 levels. Domestically, DD&A increased $4.7 million in the
2004 period, mainly due to higher production in the 2004 period. In New
Zealand, DD&A decreased by $1.3 million in the 2004 period due to decreased
production. Our DD&A rate per Mcfe of production was $1.28 in the first
quarter of 2004 and $1.16 in the comparable 2003 period.
We recorded $0.2 million of accretion on our asset retirement
obligation in both the first quarter of 2004 and 2003.
Our lease operating costs per Mcfe produced were $0.67 in the first
quarter of 2004 and $0.57 in the same period of 2003. The portion of
supervision fees recorded as a reduction to production costs was $0 for the
2004 period and $0.5 million for the 2003 period. Our lease operating costs
in the first quarter of 2004 increased
19
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
$2.3 million, or 32%, over the level of such expenses in the comparable
2003 period. Approximately $1.4 million of the increase in lease operating
costs during the first quarter of 2004 was related to our domestic
operations, which increased due to higher production from our Lake
Washington, AWP, and Brookeland areas in that period. In New Zealand,
production costs increased by $0.9 million in the first quarter of 2004
mainly due to the increase in currency exchange rates between the New
Zealand dollar and the U.S. dollar, and scheduled maintenance activities in
the first quarter of 2004.
Severance and other taxes in the first quarter of 2004 increased $1.7
million, or 36%, over the level of such expenses in the comparable 2003
period. The increase is mainly due to higher commodity prices and increased
Lake Washington production in the first quarter of 2004. Severance and
other taxes, as a percentage of oil and gas sales, were approximately 9%
and 8% in the first quarters of 2004 and 2003, respectively.
Interest expense on our Senior Notes issued in April 2002, including
amortization of debt issuance costs, totaled $4.8 million in both the first
quarters of 2004 and 2003, respectively. Interest expense on our Senior
Notes issued in July 1999, including amortization of debt issuance costs,
totaled $3.3 million in both the first quarter of 2004 and 2003. Interest
expense on the credit facility, including commitment fees and amortization
of debt issuance costs, totaled $0.4 million in both the first quarter of
2004 and 2003. The total interest cost in the first quarter of 2004 was
$8.5 million, of which $1.6 million was capitalized. The total interest
cost in the first quarter of 2003 was $8.5 million, of which $1.8 million
was capitalized.
Income tax expense in the first quarter of 2004 includes a reduction
from the U.S. statutory rate, primarily from the result of the currency
exchange rate effect on the New Zealand deferred tax, along with a
reduction in tax expense primarily attributable to an adjustment of the tax
basis of the TAWN properties acquired in 2002.
Net Income. Our net income in the first quarter of 2004 of $14.6
million was 139% higher, and Basic EPS of $0.53 was 136% higher, than our
first quarter of 2003 net income of $6.1 million and Basic EPS of $0.22.
Our Diluted EPS in the first quarter of 2004 of $0.52 was 132% higher than
our 2003 Diluted EPS of $0.22. These amounts increased in the 2004 period
as oil and gas sales increased due to higher commodity prices, increased
domestic production, and the effect of the cumulative effect of change in
accounting principle recognized in the first quarter of 2003.
CONTRACTUAL COMMITMENTS AND OBLIGATIONS
We had no material changes in our contractual commitments and
obligations from December 31, 2003.
COMMODITY PRICE TRENDS AND UNCERTAINTIES
Oil and natural gas prices historically have been volatile and are
expected to continue to be volatile in the future. The price of oil
increased significantly in the first quarter of 2004 when compared to
longer-term historical prices. Factors such as actions taken by OPEC,
worldwide supply disruptions, worldwide economic conditions, weather
conditions, and fluctuating currency exchange rates can cause wide
fluctuations in the price of oil. Domestic natural gas prices increased
significantly in the first quarter of 2003 when compared to longer-term
historical prices, and have since declined somewhat. North American weather
conditions, the industrial and consumer demand for natural gas, storage
levels of natural gas, and the availability and accessibility of natural
gas deposits in North America can cause significant fluctuations in the
price of natural gas. Such factors are beyond our control.
LIQUIDITY AND CAPITAL RESOURCES
During the first quarter of 2004, we largely relied upon our net cash
provided by operating activities of $39.6 million and proceeds from bank
borrowings of $16.6 million to fund capital expenditures of $45.1
20
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
million. During the first quarter of 2003, we relied upon our net cash
provided by operating activities of $26.8 million to fund capital
expenditures of $26.3 million.
Net Cash Provided by Operating Activities. For the first quarter of
2004, net cash provided by our operating activities was $39.6 million,
representing a 48% increase as compared to $26.8 million generated during
the first quarter of 2003. The $12.8 million increase was primarily due to
an increase of $11.1 million in oil and gas sales for the 2004 period,
attributable to higher commodity prices and production, offset in part by
lease operating cost increases due to higher domestic production and
severance taxes due to higher commodity prices in the first quarter of
2004.
Accounts Receivable. Included in the total "Accounts receivable"
balance, which totaled $29.1 million and $27.4 million at March 31, 2004
and December 31, 2003, respectively, on the accompanying balance sheet, is
approximately $2.3 million of receivables related to hydrocarbon volumes
produced from 2001 and 2002 that have been disputed since early 2003.
Accordingly, we did not record a receivable with regard to 2003 volumes. We
assess the collectibility of trade and other receivables, and based on our
judgment, we accrue a reserve when we believe a receivable may not be
collected. At March 31, 2004 and December 31, 2003, we had an allowance for
doubtful accounts of $0.8. These allowances for doubtful accounts have been
deducted from the total "Accounts receivable" balances on the accompanying
consolidated balance sheet.
Existing Credit Facility. We had $32.5 million in outstanding
borrowings under our credit facility at March 31, 2004, and $15.9 million
in outstanding borrowings at December 31, 2003. Our credit facility at
March 31, 2004 consisted of a $300.0 million revolving line of credit with
a $250.0 million borrowing base. The borrowing base is re-determined at
least every six months and was reaffirmed by our bank group at $250.0
million, effective May 1, 2004. We requested that the commitment amount
with our bank group be reduced to $150.0 million effective May 9, 2003.
Under the terms of the credit facility, we can increase this commitment
amount back to the total amount of the borrowing base at our discretion,
subject to the terms of the credit agreement. Our revolving credit facility
includes, among other restrictions, requirements as to maintenance of
certain minimum financial ratios (principally pertaining to working
capital, debt, and equity ratios), and limitations on incurring other debt.
We are in compliance with the provisions of this agreement.
Debt Maturities. Our credit facility extends until October 1, 2005. Our
$125.0 million Senior Notes mature August 1, 2009 and our $200.0 million
Senior Notes mature May 1, 2012.
Working Capital. Our working capital improved from a deficit of $35.1
million at December 31, 2003, to a deficit of $15.4 million at March 31,
2004. The improvement was primarily due to a decrease in accounts payable
and accrued capital costs due to a reduction in our drilling activities at
March 31, 2004.
Capital Expenditures. During the first three months of 2004, we used
$45.1 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
Domestic activities of $36.5 million as follows:
o $31.2 million for drilling and developmental activity costs;
o $4.7 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $0.4 million relating to costs directly associated with evaluating
potential producing property acquisitions; and
o $0.2 million primarily for computer equipment, software, furniture,
and fixtures.
21
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
New Zealand activities of $8.6 million as follows:
o $7.0 million for drilling costs and developmental activity costs;
o $1.5 million on prospect costs, principally seismic and geological
costs;
o $0.1 million for fixed assets.
We have spent considerable time and capital in 2003 and the first
quarter of 2004, on significant facility capacity upgrades in the Lake
Washington field to increase facility capacity to more than 20,000 barrels
per day ('b/d') for crude oil, up from 9,000 b/d capacity in the first
quarter 2003. Facility upgrades, most of which have been recently
completed, and the commissioning of these upgrades, led to numerous planned
production shut-in periods during the third and fourth quarters of 2003. We
have upgraded three production platforms, added new compression for the gas
lift system, and installed a new oil delivery system and permanent barge
loading facility.
We drilled or participated in drilling 12 domestic development wells
and two domestic exploratory wells in the first quarter of 2004. Seven of
the development wells and one exploratory well were in the Lake Washington
area. Four of the development wells were in the AWP area. One domestic
exploratory well and 11 of the domestic development wells were completed.
In New Zealand, the Kauri-E3 well was completed while the Kauri-E4 began
completion procedures.
For the remaining nine months of 2004, we expect to make capital
expenditures of approximately $90.0 to $120.0 million. We currently
estimate total capital expenditures for 2004 to be approximately $133.0 to
$163.0 million, excluding acquisition costs and net of approximately $3.0
million to $13.0 million in non-core property dispositions. Capital
expenditures for 2003 were $144.5 million. The budget for 2004, as always,
is dependent upon operational performance and commodity pricing levels
during the year. Domestic activities account for the majority of budgeted
spending, with the largest allocation going to the Lake Washington area.
We believe that the anticipated internally generated cash flows for
2004, together with bank borrowings under our credit facility, will be
sufficient to finance the costs associated with our currently budgeted 2004
capital expenditures. If producing property acquisitions become attractive
during 2004, we will explore the use of debt and/or equity offerings to
fund such activity.
During the last nine months of 2004, we anticipate drilling or
participating in the drilling of up to an additional 10 to 15 wells in our
Lake Washington area, an additional 7 to 10 wells in our AWP area, and up
to five additional wells, with varying working interest percentages, mainly
in our South Texas areas. In addition, we plan on drilling an additional 2
to 3 Kauri wells, a Tariki well, and 4 to 6 Manutahi wells.
Our 2004 capital expenditures continue to be focused on developing and
producing long-lived oil reserves in Lake Washington and in the Rimu/Kauri
area in New Zealand. With this focus, we expect our 2004 total production
to increase by 11% to 17% over 2003 levels primarily from the Lake
Washington area, while we expect production in our other core areas to
decrease as limited new drilling is currently budgeted to offset the
natural production decline of these properties. This drilling focus should
help add long-lived oil reserves and should help develop an overall lesser
production decline curve, which would extend our average reserve life and
emphasize the balancing of our reserves between oil and gas.
New Accounting Principles
In March 2004, the FASB issued an exposure draft that would amend SFAS
No. 123 "Accounting for Stock Based Compensation ' and SFAS No. 95
"Statement of Cash Flows." This exposure draft was issued to
22
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
improve existing accounting rules and provide more complete, higher quality
information for investors on employee stock compensation matters. The
comment period for the exposure draft ends June 30, 2004. The exposure
draft covers a wide range of equity-based arrangements including stock
options. Under the FASB's proposal, share-based payments to employees,
including stock options, would be treated the same as other forms of
compensation by recognizing the related cost in the income statement. The
expense of the award would generally be measured at fair value at the grant
date. Current accounting guidance requires that the expense relating to
employee stock options only be disclosed in the footnotes of the financial
statements. The Company is evaluating the effects that will result from
future adoption of this proposed statement or related accounting changes.
In January 2003, the FASB issued Interpretation No. 46 (Revised
December 2003), Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51 Consolidated
Financial Statements (the "Interpretation"). The Interpretation
significantly changes whether entities included in its scope are
consolidated by their sponsors, transferors, or investors. The
Interpretation introduces a new consolidation model-the variable interest
model; which determines control (and consolidation) based on potential
variability in gains and losses of the entity being evaluated for
consolidation. The Interpretation provides guidance for determining whether
an entity lacks sufficient equity or its equity holders lack adequate
decision-making ability. These variable interest entities ("VIEs") are
covered by the Interpretation and are to be evaluated for consolidation
based on their variable interests. These provisions applied immediately to
variable interests in VIEs created after January 31, 2003, and to variable
interests in special purpose entities for periods ending after December 15,
2003. The provisions apply for all other types of variable interests in
VIEs for periods ending after March 15, 2004. We have no variable interests
in VIEs, nor do we have variable interests in special purpose entities. The
adoption of this interpretation had no impact on the Company's financial
position or results of operations.
In June 2001, the FASB issued SFAS No. 141, "Business Combinations,"
and SFAS No. 142, "Goodwill and Intangible Assets." We adopted these
statements on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires that all business combinations initiated after June 30, 2001, be
accounted for using the purchase method and that intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142
establishes new guidelines for accounting for goodwill and other intangible
assets. Under SFAS No. 142, goodwill and other indefinite lived intangible
assets are not amortized but reviewed annually for impairment.
An issue, EITF Issue 04-2, had arisen for companies engaged in oil and
gas exploration and production regarding the application of SFAS No. 141
and SFAS No. 142 as they relate to mineral rights held under lease or other
contractual arrangements, and as to whether costs associated with these
rights should be classified as intangible assets on the balance sheet,
apart from other capitalized oil and gas property costs, and to provide
specific footnote disclosure. In March 2004, the Emerging Issues Task Force
of the FASB reached a consensus that mineral rights are tangible assets. In
April 2004, the FASB ratified the EITF's consensus by issuing FASB Staff
Position (FSP) 141-1 and 142-1, which amend SFAS No. 141 and SFAS No. 142
to address the inconsistency between the EITF consensus on EITF Issue No.
04-02 and SFAS No. 141 and SFAS No. 142. The FSP is effective for reporting
periods beginning after April 29, 2004 and defines mineral rights as
tangible assets. These staff positions will have no impact on our
consolidated financial statemenst.
Related-Party Transactions
We have been the operator of a number of properties owned by our
affiliated limited partnerships and, accordingly, charge these entities
operating fees. The operating fees charged to the partnerships in the first
quarter of 2004 and 2003 totaled less than $0.1 million, and are recorded
as reductions of general and administrative expense in the 2004 period, and
both general and administrative expense and oil and gas production expense
in the 2003 period. We also have been reimbursed for direct,
administrative, and overhead costs
23
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
incurred in conducting the business of the limited partnerships, which
totaled approximately less than $0.1 million in both the first three months
of 2004 and 2003.
Forward Looking Statements
The statements contained in this report that are not historical facts
are forward-looking statements as that term is defined in Section 21E of
the Securities and Exchange Act of 1934, as amended. Such forward-looking
statements may pertain to, among other things, financial results, capital
expenditures, drilling activity, development activities, cost savings,
production efforts and volumes, hydrocarbon reserves, hydrocarbon prices,
liquidity, regulatory matters and competition. Such forward-looking
statements generally are accompanied by words such as "plan," "future,"
"estimate," "expect," "budget," "predict," "anticipate," "projected,"
"should," "believe" or other words that convey the uncertainty of future
events or outcomes. Such forward-looking information is based upon
management's current plans, expectations, estimates and assumptions, upon
current market conditions, and upon engineering and geologic information
available at this time, and is subject to change and to a number of risks
and uncertainties, and therefore, actual results may differ materially.
Among the factors that could cause actual results to differ materially are:
volatility in oil and gas prices; fluctuations of the prices received or
demand for our oil and natural gas; the uncertainty of drilling results and
reserve estimates; operating hazards; requirements for capital; general
economic conditions; changes in geologic or engineering information;
changes in market conditions; competition and government regulations; as
well as the risks and uncertainties discussed herein, and set forth from
time to time in our other public reports, filings and public statements.
Also, because of the volatility in oil and gas prices and other factors,
interim results are not necessarily indicative of those for a full year.
24
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Risk
Our major market risk exposure is the commodity pricing applicable to
our oil and natural gas production. Realized commodity prices received for
such production are primarily driven by the prevailing worldwide price for
crude oil and spot prices applicable to natural gas. The effects of such
pricing volatility are expected to continue.
Our price-risk management policy permits the utilization of derivative
instruments (such as futures, forward and option contracts, and swaps) to
mitigate price risk associated with fluctuations in oil and natural gas
prices. Below is a description of the derivative instruments we have
utilized to hedge our exposure to price risk.
oPrice Floors - At March 31, 2004, we had in place price floors in effect
through the June 2004 contract month for natural gas, these cover our
domestic natural gas production for April 2004 to June 2004. The natural
gas price floors cover notional volumes of 1,800,000 MMBtu, with a weighted
average floor price of $4.83 per MMBtu. Our hedges in place at March 31,
2004 are expected to cover approximately 55% to 65% of our domestic natural
gas production from April 2004 to June 2004.
oNew Zealand Gas Contracts - All of our gas production in New Zealand is
sold under long-term, fixed-price contracts denominated in New Zealand
dollars. These contracts protect against price volatility, and our revenue
from these contracts will vary only due to production fluctuations and
foreign exchange rates.
Customer Credit Risk
We are exposed to the risk of financial non-performance by customers.
Our ability to collect on sales to our customers is dependent on the
liquidity of our customer base. To manage customer credit risk, we monitor
credit ratings of customers and seek to minimize exposure to any one
customer where other customers are readily available. Due to availability
of other purchasers, we do not believe that the loss of any single oil or
gas customer would have a material adverse effect on our results of
operations.
Foreign Currency Risk
We are exposed to the risk of fluctuations in foreign currencies, most
notably the New Zealand dollar. Fluctuations in rates between the New
Zealand dollar and U.S. dollar may impact our financial results from our
New Zealand subsidiaries since we have receivables, liabilities and natural
gas and NGL sales contracts denominated in New Zealand dollar.
Interest Rate Risk
Our Senior Notes have a fixed interest rate, so consequently we are not
exposed to cash flow risk from market interest rate changes on our Senior
Notes. However, there is a risk that market rates will decline and the
required interest payments on our Senior Notes may exceed those payments
based on the current market rate. At March 31, 2004, we had $32.5 million
in borrowings under our credit facility, which is subject to floating rates
and therefore susceptible to interest rate fluctuations. The result of a
10% fluctuation in the bank's base rate would constitute 40 basis points
and would not have a material adverse effect on our 2004 cash flows based
on this same level of borrowing.
25
CONTROLS AND PROCEDURES
The Company's chief executive officer and chief financial officer have
evaluated the Company's disclosure controls and procedures, as defined in
Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934
(the "Exchange Act") as of the end of the period covered by the report.
Based on that evaluation, they have concluded that such disclosure controls
and procedures are effective in alerting them on a timely basis to material
information relating to the Company required under the Exchange Act to be
disclosed in this report. There were no significant changes in the
Company's internal controls that could significantly affect such controls
subsequent to the date of their evaluation.
26
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation incidental to the Company's business.
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities - N/A
Item 3. Defaults Upon Senior Securities - N/A
Item 4. Submission of Matters to a Vote of Security Holders - N/A
Item 5. Other Information
Our Insider Trading Policy allows directors and officers covered under the
policy to establish stock trading plans under specified circumstances pursuant
to Rule 10b5-1 established by the SEC under the Securities Exchange Act of 1934
to provide a safe harbor under certain provisions of that act. In April of 2004,
one of our executive officers, Bruce Vincent, Executive Vice President-Corporate
Development and Secretary, established a Rule 10b5-1 sales plan which specifies
for future periods the trading period, the number of shares of common stock to
be sold, and prices and conditions under which such shares may be sold. Under
the trading plan, Mr. Vincent may sell up to an aggregate of 72,506 shares,
which shares are principally acquirable under options that expire in 2004,
during the period beginning on May 10, 2004 and ending on May 10, 2005. Under
the trading plan, an independent broker will execute the trades pursuant to
specific selling instructions provided by Mr. Vincent at the time the plan was
established. Other directors or officers may establish Rule 10b5-1 trading plans
in the future.
Item 6. Exhibits & Reports on Form 8-K -
(a) Documents filed as part of the report
(3) Exhibits
31.1 Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
32 Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K filed during the quarter ended March 31, 2004,
which are incorporated herein by reference:
On February 11, 2004, the Company filed a Current Report on Form
8-K that reported under Item 7, "Financial Statements, Pro Forma
Financial Information and Exhibits" and Item 12, "Results of
Operations and Financial Conditions" relating to the press
release announcement of fourth quarter and full year 2003
earnings.
27
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.
SWIFT ENERGY COMPANY
(Registrant)
Date: May 7, 2004 By: (original signed by)
------------------ --------------------------
Alton D. Heckaman, Jr.
Senior Vice President
Chief Financial Officer
Date: May 7, 2004 By: (original signed by)
------------------ ---------------------------
David W. Wesson
Controller and Principal Accounting
Officer
28
Exhibit 31.1
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended March
31, 2004, of Swift Energy Company;
2. Based on my knowledge, this 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 report;
3. Based on my knowledge, the financial statements, and other financial
information included in this 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 report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, 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 report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: May 7, 2004
/s/ Terry E. Swift
--------------------------------
Terry E. Swift
President and
Chief Executive Officer
29
Exhibit 31.2
CERTIFICATION
I, Alton D. Heckaman, Jr., certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended March
31, 2004, of Swift Energy Company;
2. Based on my knowledge, this 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 report;
3. Based on my knowledge, the financial statements, and other financial
information included in this 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 report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, 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 report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: May 7, 2004
/s/ Alton D. Heckaman, Jr.
------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President - Finance
Chief Financial Officer
30
Exhibit 32
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Quarterly Report on Form 10-Q for the period
ended March 31, 2004 (the "Report") of Swift Energy Company ("Swift") as filed
with the Securities and Exchange Commission on May 7, 2004, the undersigned, in
his capacity as an officer of Swift, hereby certifies pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002, that to his knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934, as amended; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of Swift.
Dated: May 7, 2004
/s/ Alton D. Heckaman, Jr.
-------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President-Finance and
Chief Financial Officer
Dated: May 7, 2004
/s/ Terry E. Swift
-------------------------------------
Terry E. Swift
President and Chief Executive Officer
31