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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 September 30, 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 Exchange Act).
Yes X No
----------- ----------
Indicate the number of shares outstanding of each of the Issuer's classes
of common stock, as of the latest practicable date.
Common Stock 28,030,317 Shares
($.01 Par Value) (Outstanding at October 31, 2004)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004
INDEX
PART I - FINANCIAL INFORMATION PAGE
Item 1. Condensed Consolidated Financial Statements.
Condensed Consolidated Balance Sheets
- September 30, 2004 and December 31, 2003 3
Condensed Consolidated Statement of Income
- For the Three month and Nine month periods ended
September 30, 2004 and 2003 4
Condensed Consolidated Statements of Stockholders' Equity
- For the Nine month period ended September 30, 2004 and
year ended December 31, 2003 5
Condensed Consolidated Statements of Cash Flows
- For the Nine month periods ended September 30, 2004 and 2003 6
Notes to Condensed Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 19
Item 3. Quantitative and Qualitative Disclosures About Market Risk. 31
Item 4. Controls and Procedures. 33
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 34
Item 2. Unregistered Sales of Securities and Use of Proceeds None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders None
Item 5. Other Information 34
Item 6. Exhibits 34
SIGNATURES 35
CONDENSED CONSOLIDATED BALANCE SHEETS
SWIFT ENERGY COMPANY
September 30, 2004 December 31, 2003
------------------------- ---------------------------
ASSETS
Current Assets:
Cash and cash equivalents .................................$ 4,281,527 $ 1,066,280
Accounts receivable - .....................................
Oil and gas sales ....................................... 29,388,512 26,082,650
Joint interest owners ................................... 1,493,098 1,350,707
Other current assets ...................................... 6,922,297 5,610,420
------------------------- ---------------------------
Total Current Assets .................................. 42,085,434 34,110,057
------------------------- ---------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized ....................... 1,408,446,400 1,305,110,582
Unproved properties not being amortized ................. 73,368,548 67,557,969
------------------------- ---------------------------
1,481,814,948 1,372,668,551
Furniture, fixtures, and other equipment .................. 11,603,507 10,602,786
------------------------- ---------------------------
1,493,418,455 1,383,271,337
Less-Accumulated depreciation, depletion,
and amortization ..................................... (625,468,058) (567,464,334)
------------------------- ---------------------------
867,950,397 815,807,003
------------------------- ---------------------------
Other Assets:
Deferred income taxes ..................................... 2,762,588 1,905,909
Debt issuance costs ....................................... 9,404,282 8,015,575
------------------------- ---------------------------
12,166,870 9,921,484
------------------------- ---------------------------
$ 922,202,701 $ 859,838,544
========================= ===========================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities ..................$ 21,104,321 $ 26,247,477
Accrued capital costs ..................................... 14,216,880 29,417,542
Accrued interest .......................................... 11,053,499 8,748,656
Undistributed oil and gas revenues ........................ 6,423,277 4,939,667
------------------------- ---------------------------
Total Current Liabilities ............................. 52,797,977 69,353,342
------------------------- ---------------------------
Long-Term Debt .............................................. 356,200,000 340,254,783
Deferred Income Taxes ....................................... 59,682,338 43,498,682
Asset Retirement Obligation ................................. 8,680,547 9,340,473
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 share authorized,
28,467,891 and 28,011,109 shares issued, and 27,987,023
and 27,484,091 shares outstanding, respectively ......... 284,679 280,111
Additional paid-in capital ................................ 339,812,135 334,865,204
Treasury stock held, at cost, 480,868 and
527,018 shares, respectively ............................ (6,896,245) (7,558,093)
Retained earnings ......................................... 111,689,882 70,073,384
Other comprehensive loss, net of taxes .................... (48,612) (269,342)
------------------------- ---------------------------
444,841,839 397,391,264
------------------------- ---------------------------
$ 922,202,701 $ 859,838,544
========================= ===========================
See accompanying notes to condensed consolidated financial statements.
3
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
SWIFT ENERGY COMPANY
Three Months Ended Nine Months Ended
------------------------------- ----------------------------------
09/30/04 09/30/03 09/30/04 09/30/03
--------------- -------------- ----------------- ---------------
Revenues:
Oil and gas sales ..............................$ 74,653,106 $ 52,087,321 $ 212,431,665 $ 157,846,870
Price-risk management and other, net ........... 289,645 (534,799) (1,089,449) (2,076,826)
--------------- -------------- ----------------- ---------------
74,942,751 51,552,522 211,342,216 155,770,044
--------------- -------------- ----------------- ---------------
Costs and Expenses:
General and administrative, net ................ 4,390,432 3,670,416 12,595,665 10,564,959
Depreciation, depletion and amortization ....... 19,845,167 16,042,377 57,649,907 46,630,689
Accretion of asset retirement obligation.... 168,135 206,475 498,870 623,761
Lease operating costs .......................... 9,848,949 8,664,259 29,910,742 25,149,050
Severance and other taxes ...................... 7,077,994 5,066,208 20,251,822 14,243,481
Interest expense, net .......................... 7,317,002 6,749,419 21,361,566 20,107,188
Debt retirement cost ........................... 6,822,476 --- 9,513,719 ---
--------------- -------------- ----------------- ---------------
55,470,155 40,399,154 151,782,291 117,319,128
--------------- -------------- ----------------- ---------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle........ 19,472,596 11,153,368 59,559,925 38,450,916
Provision for Income Taxes ....................... 5,341,879 4,090,743 17,943,427 13,681,928
--------------- -------------- ----------------- ---------------
Income Before Cumulative Effect of Change
in Accounting Principle ........................ 14,130,717 7,062,625 41,616,498 24,768,988
Cumulative Effect of Change in Accounting
Principle (net of taxes) ....................... --- --- --- 4,376,852
--------------- -------------- ----------------- ---------------
Net Income .............................$ 14,130,717 $ 7,062,625 $ 41,616,498 $ 20,392,136
=============== ============== ================= ===============
Per share amounts
Basic:
Income Before Cumulative Effect of
Change in Accounting Principle......$ 0.51 $ 0.26 $ 1.50 $ 0.91
Cumulative Effect of Change in
Accounting Principle............... --- --- --- (0.16)
--------------- -------------- ----------------- ---------------
Net Income .....................$ 0.51 $ 0.26 $ 1.50 $ 0.75
=============== ============== ================= ===============
Diluted:
Income Before Cumulative Effect of
Change in Accounting Principle ....$ 0.50 $ 0.26 $ 1.47 $ 0.90
Cumulative Effect of Change in
Accounting Principle................ --- --- --- (0.16)
--------------- -------------- ----------------- ---------------
Net Income .....................$ 0.50 $ 0.26 $ 1.47 $ 0.74
=============== ============== ================= ===============
Weighted Average Shares Outstanding .............. 27,948,095 27,424,195 27,747,789 27,326,169
=============== ============== ================= ===============
See accompanying notes to condensed consolidated financial statements
4
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SWIFT ENERGY COMPANY
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
(406,364 shares) .................... 4,064 4,278,536 - - - 4,282,600
Employee stock purchase plan
(50,418 shares) ..................... 504 502,097 - - - 502,601
Comprehensive income:
Net income ............................. - - - 41,616,498 - 41,616,498
Change in fair value of cash
flow hedges, net of income tax........ - - - - 220,730 220,730
-------------
Total comprehensive income ............ 41,837,228
---------- --------------- ------------ ------------- ------------- -------------
Balance, September 30, 2004...............$ 284,679 $ 339,812,135 $ (6,896,245) $ 111,689,882 $ (48,612) $ 444,841,839
========== =============== ============ ============= ============= =============
(1)$.01 par value
See accompanying notes to condensed consolidated financial statements.
5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
SWIFT ENERGY COMPANY
Period Ended September 30,
------------------------------------------------
2004 2003
--------------------- ---------------------
Cash Flows From Operating Activities:
Net income .........................................................$ 41,616,498 $ 20,392,136
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 ........................ 57,649,907 46,630,689
Accretion of asset retirement obligation ......................... 498,870 623,761
Deferred income taxes ............................................ 17,534,427 13,375,807
Debt retirement cost - cash and non-cash ......................... 9,513,719 ---
Other ............................................................ 839,048 658,524
Change in assets and liabilities -
Increase in accounts receivable ................................ (5,940,575) (3,895,748)
Increase in accounts payable and accrued liabilities ........... 2,402,826 413,820
Increase in accrued interest ................................... 2,304,843 1,446,218
--------------------- ---------------------
Net Cash Provided by Operating Activities ................ 126,419,563 84,022,059
--------------------- ---------------------
Cash Flows From Investing Activities:
Additions to property and equipment ................................ (128,499,752) (101,510,935)
Proceeds from the sale of property and equipment ................... 1,411,554 3,839,714
Net cash distributed as operator of
oil and gas properties ........................................... (3,910,392) (989,176)
Net cash received as operator of partnerships
and joint ventures ............................................... 81,254 471,957
Other .............................................................. (101,164) (89,635)
--------------------- ---------------------
Net Cash Used in Investing Activities .................... (131,018,500) (98,278,075)
--------------------- ---------------------
Cash Flows From Financing Activities:
Proceeds from long-term debt ....................................... 150,000,000 ---
Payments of long-term debt ......................................... (125,000,000) ---
Net proceeds from (payments of) bank borrowings .................... (9,700,000) 11,900,000
Net proceeds from issuances of common stock ........................ 3,559,781 1,218,224
Payments of debt retirement costs .................................. (6,712,062) ---
Payments of debt issuance costs .................................... (4,333,535) ---
--------------------- ---------------------
Net Cash Provided by Financing Activities ................ 7,814,184 13,118,224
--------------------- ---------------------
Net Increase (Decrease) in Cash and Cash Equivalents ................. 3,215,247 (1,137,792)
Cash and Cash Equivalents at Beginning of Period ..................... 1,066,280 3,816,107
--------------------- ---------------------
Cash and Cash Equivalents at End of Period ...........................$ 4,281,527 $ 2,678,315
===================== =====================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized ........................................................$ 18,200,440 $ 17,825,296
Cash paid during period for income taxes .............................$ 409,000 $ 306,121
See accompanying notes to condensed consolidated financial statements.
6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SWIFT ENERGY COMPANY
(1) General Information
The condensed consolidated financial statements included herein have
been prepared by Swift Energy Company and 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
condensed 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. 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 nine months ended September 30, 2004 and 2003, such
internal costs capitalized totaled $9.6 million and $9.3 million,
respectively. Interest costs are also capitalized to unproved oil and gas
properties. For the nine months ended September 30, 2004 and 2003,
capitalized interest on our unproved properties totaled $4.7 million and
$5.2 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.
7
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Geological and geophysical (G&G) costs incurred on developed properties
are recorded in Proved Property and 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. 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 including future abandonment costs of wells
to be drilled, 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 September 30, 2004 consisted of natural gas and
crude oil price floors with strike prices lower than the period-end price
and therefore had no effect on 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 non-cash write-downs of oil and gas
properties could occur in the future.
Principles of Consolidation
The accompanying condensed 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 inland waters
and onshore oil and natural gas reserves in Louisiana and Texas, as well
as onshore oil and natural gas reserves in New Zealand. Our investments in
oil and gas partnerships where we are the general partner are accounted
for using the proportionate consolidation method, whereby our
proportionate share of assets, liabilities, revenues, and expenses are
included in the appropriate classifications in the condensed consolidated
financial statements. Intercompany balances and transactions have been
eliminated in preparing the condensed consolidated financial statements.
Accounts Receivable
Included in the "Accounts receivable" balance, which totaled $30.9
million and $27.4 million at September 30, 2004 and December 31, 2003,
respectively, on the accompanying condensed consolidated balance sheets,
is approximately $2.3 million of receivables related to hydrocarbon
volumes produced during 2001 and 2002
8
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
that have been disputed since early 2003. Accordingly, we did not record a
receivable with regard to those 2003 disputed volumes.
We continually assess the collectibility of accounts receivable, and
based on our judgment, we establish a reserve when we believe a receivable
may not be collected. At both September 30, 2004 and December 31, 2003, we
had an allowance for doubtful accounts of $0.5 million. These allowances
for doubtful accounts have been deducted from the total "Accounts
receivable" balances on the accompanying condensed consolidated balance
sheets.
Inventory
We value inventories at the lower of cost or market value. Cost of
crude oil inventory is determined using the weighted average method, all
other inventory is accounted for using the first in, first out method
("FIFO"). The major categories of inventories, which are included in
"Other current assets" on the accompanying balance sheets, are shown as
follows:
Balance at Balance at
September 30, December 31,
2004 2003
---------------- ----------------
Materials, Supplies and Tubulars....$ 3,996,866 $ 2,965,813
Crude Oil .......................... 1,045,013 238,228
---------------- ----------------
Total ..............................$ 5,041,879 $ 3,204,041
================ ================
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
The effective tax rate for the first nine months of 2004 was lower than
the statutory tax rates primarily due to reductions from the New Zealand
statutory rate attributable to the currency effect on New Zealand deferred
income taxes, along with reductions to the domestic tax rate due to
changes in prior year tax estimates that are updated after we filed the
prior year tax return. The tax laws in the jurisdictions we operate in are
continuously changing and professional judgments regarding such laws can
differ. Although the Internal Revenue Service regulations concerning the
recently enacted American Jobs Creation Act of 2004 have not been issued,
we do not believe this act will have a material impact in the near-term on
our financial position or cash flow from operations.
9
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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 were antidilutive for the three months and
nine months ended September 30, 2004 and 2003 were excluded. 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 and nine month periods ended
September 30, 2004 and 2003:
Three Months Ended September 30,
------------------------------------------------------------------------------------
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........ $14,130,717 27,948,095 $.51 $7,062,625 27,424,195 $.26
Stock Options ....................... --- 555,861 --- 259,246
-------------- ----------- -------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions ....................... $14,130,717 28,503,956 $.50 $7,062,625 27,683,441 $.26
-------------- ----------- -------------- ------------
Nine Months Ended September 30,
------------------------------------------------------------------------------------
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 $41,616,498 27,747,789 $1.50 $24,768,988 27,326,169 $.91
Stock Options ....................... --- 502,251 --- 147,158
-------------- ----------- -------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions ....................... $41,161,498 28,250,040 $1.47 $24,768,988 27,473,327 $.90
-------------- ----------- -------------- ------------
Options to purchase approximately 2.8 million shares of common stock,
at an average exercise price of $17.65 were outstanding at September 30,
2004, and options to purchase approximately 2.9 million shares of common
stock, at an average price of $16.61 were outstanding at September 30,
2003. Approximately 0.9 million and 1.3 million options to purchase shares
were not included in the computation of Diluted EPS for the three month
periods ended September 30, 2004 and 2003, respectively, and approximately
0.9 million and 1.6 million options to purchase shares were not included
in the computation of Diluted EPS for the nine month periods ended
September 30, 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.
Other Comprehensive Loss
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
10
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
owners of the Company. At September 30, 2004, we recorded $48,612, net of
taxes of $27,702, of derivative losses in "Other comprehensive loss" on
the accompanying balance sheet. The components of accumulated other
comprehensive loss and related tax effects for the nine month period ended
September 30, 2004 were as follows:
Gross Value Tax Effect Net of Tax Value
---------------- --------------- ------------------
Balance at December 31, 2003 ................$ 420,847 $ 151,505 $ 269,342
Change in fair value of cash flow hedges .... 911,302 332,065 579,237
Effect of cash flow hedges settled
during the period ........................ (1,255,835) (455,868) (799,967)
---------------- --------------- ------------------
Balance at September 30, 2004 ...............$ 76,314 $ 27,702 $ 48,612
================ =============== ==================
For the nine month periods ended September 30, 2004 and 2003, total
comprehensive income was $41.8 million and $20.5 million, respectively.
For the three month periods ended September 30, 2004 and 2003, total
comprehensive income was $14.2 million and $7.3 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 September 30,
-----------------------------------------------
2004 2003
---------------------- -------------------
Net Income: As Reported ....................................... $14,130,717 $7,062,625
Stock-based employee compensation expense
determined under fair value method for
all awards, net of tax .......................... (1,059,331) (1,024,734)
---------------------- -------------------
Pro Forma ......................................... $13,071,386 $6,037,891
Basic EPS: As Reported ....................................... $.51 $.26
Pro Forma ......................................... $.47 $.22
Diluted EPS: As Reported ....................................... $.50 $.26
Pro Forma ......................................... $.46 $.22
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Nine Months Ended September 30,
-----------------------------------------------
2004 2003
---------------------- -------------------
Net Income: As Reported ....................................... $41,616,498 $20,392,136
Stock-based employee compensation expense
determined under fair value method for
all awards, net of tax .......................... (3,170,157) (3,048,052)
---------------------- -------------------
Pro Forma ......................................... $38,446,341 $17,344,084
Basic EPS: As Reported ....................................... $1.50 $.75
Pro Forma ......................................... $1.39 $.63
Diluted EPS: As Reported ....................................... $1.47 $.74
Pro Forma ......................................... $1.36 $.63
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.
Price-Risk Management Activities
Changes in the derivative's fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. Every
derivative instrument (including certain derivative instruments embedded
in other contracts) are recorded in the balance sheet as either an asset
or a liability measured at its fair value. Hedge accounting for qualifying
hedges allows 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. Changes in the fair value of
derivatives that do not meet the criteria for hedge accounting are
recognized currently in income.
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 third quarters of 2004
and 2003, we recognized net losses of $0.2 million and $0.6 million,
respectively, relating to our derivative activities. During the first nine
months of 2004 and 2003, we recognized net losses of $1.3 million and $2.4
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 September 30, 2004, we had recorded
$48,612, net of taxes of $27,702, 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 qualified as cash flow hedges. The
ineffectiveness reported in "Price-risk management and other, net" for the
first nine months of 2004 and 2003 were not material. We expect to
reclassify all amounts currently held in "Other comprehensive loss" into
the statement of income within the next six months when the forecasted
sale of hedged production occurs.
As of September 30, 2004, we had in place natural gas price floors in
effect for the October 2004 contract month through the March 2005 contract
month, which cover a portion of our domestic natural gas production for
October 2004 to March 2005. The natural gas price floors cover notional
volumes of 950,000 Mmbtu with a weighted average floor price of $5.63 per
Mmbtu. Our natural gas hedges in place at September 30, 2004 are expected
to cover approximately 10% to 15% of our domestic natural gas production
from October 2004 to March 2005. As of September 30, 2004, we also had
crude oil price floors in effect for the January 2005 contract month
through the March 2005 contract month, which cover a portion of our
domestic crude oil production for January 2005 through March 2005. The
crude oil price floors cover notional volumes of 216,000 barrels with a
weighted average floor price of $37.00 per barrel. Our crude oil floors at
September 30, 2004 are expected to cover approximately 15% to 20% of our
domestic crude oil production from January 2005 to March 2005.
When we entered into these transactions discussed above, they were
designated as a hedge of the
12
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
variability in cash flows associated with the forecasted sale of natural
gas and crude oil production. Changes in the fair value of a hedge that is
highly effective and is designated and documented 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 condensed
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 September 30, 2004, was $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 on a unit of production
basis 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 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 and nine months ended September 30, 2003 by approximately
$0.2 million and $0.5 million, respectively, or less than $0.01 per
diluted share for the three months and $0.02 per diluted share for the
nine months period. The following is a roll-forward of our asset
retirement obligation:
2004 2003
----------------- ----------------
Asset Retirement Obligation recorded as of January 1 ..................$ 10,137,473 $ 8,934,320
Accretion expense for the nine months ended September 30............. 498,870 623,761
Liabilities incurred for new wells and facilities construction...... 315,404 546,350
Reductions due to sold, or plugged and abandoned wells .............. (234,769) (332,327)
Increase due to currency exchange rate fluctuations ................. 37,569 62,591
----------------- ----------------
Asset Retirement Obligation as of September 30 ....................... $ 10,754,547 $ 9,834,695
----------------- ----------------
At September 30, 2004 and December 31, 2003, approximately $2.1 million
and $0.8 million, respectively, of our asset retirement obligation is
classified as a current liability in "Accounts payable and accrued
liabilities" on the accompanying condensed consolidated balance sheets.
New Accounting Principles
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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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. In September 2004, the EITF
issued FASB Staff Position (FSP) 142-2, in which the FASB staff further
concluded that the costs for acquiring contractual mineral rights in oil
and gas properties would continue to be recorded as tangible assets. These
staff positions had no impact on our consolidated financial statements.
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 our financial position or results of operations.
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. This
statement is effective for interim or annual periods beginning after June
15, 2005. 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
allows that the expense relating to employee stock options to only be
disclosed in the footnotes of the financial statements. We are evaluating
the effects that will result from future adoption of this proposed
statement.
In September 2004, the EITF discussed an issue dealing with how to
evaluate whether a partnership should be consolidated by its general
partner, EITF Issue 04-5. The issue deals with rights held by the limited
partners and how this affects the consolidation of partnerships by the
sole general partner in accordance with generally accepted accounting
principles, absent the existence of these rights held by the limited
partners. The EITF will discuss this issue in the future and we do not
believe this staff position will have a material impact on our
Consolidated Financial Statements.
In September 2004, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the SEC staff's
views regarding SFAS No. 143 and its impact on both the full-cost ceiling
test and the calculation of depletion expense. In accordance with SAB 106,
beginning in the
14
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
fourth quarter of 2004, undiscounted abandonment costs for future wells,
not recorded at the present time but needed to develop the proved reserves
in existence at the present time, should be included in the unamortized
cost of oil and as properties, net of related salvage value, for purposes
of computing DD&A. The effect of including undiscounted abandonment costs
of future wells to the undiscounted cost of oil and gas properties will
increase depletion expense in future periods, however, not materially at
the present time.
(3) Long-Term Debt
Our long-term debt, including the current portion, as of September 30,
2004 and December 31, 2003, was as follows (in thousands):
September 30, December 31,
2004 2003
-------------- -------------
Bank Borrowings ......................$ 6,200 $ 15,900
Senior Subordinated Notes due 2009 ... --- 124,355
Senior Notes due 2011 ................ 150,000 ---
Senior Subordinated Notes due 2012 ... 200,000 200,000
-------------- -------------
Long-Term Debt .............$ 356,200 $ 340,255
-------------- -------------
The unamortized discount on the Senior Subordinated Notes due 2009 was
$0.6 million at December 31, 2003.
Bank Borrowings
At September 30, 2004, we had $6.2 million in outstanding borrowings
under our $400.0 million credit facility with a syndicate of ten banks
that has a borrowing base of $250.0 million and expires in October 2008.
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 (4.75% at September 30, 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. In June 2004,
we increased, renewed and extended this credit facility, increasing the
facility to $400 million from $300 million and extending its expiration to
October 1, 2008 from October 1, 2005. The other terms of the credit
facility, such as the borrowing base amount and commitment amount, stayed
largely the same. The covenants related to this credit facility changed
somewhat with the extension of the facility and are discussed below.
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 and EBITDAX
ratios), and limitations on incurring other debt or repurchasing our
Senior Subordinated Notes due 2011 or Senior Notes due 2012. 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 November 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 May 2005.
15
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Senior Subordinated Notes Due 2009
These notes consisted of $125.0 million of 10 1/4% Senior Subordinated
Notes due August 2009, which were issued at 99.236% of the principal
amount on August 4, 1999, and were scheduled to mature on August 1, 2009.
These notes were unsecured senior subordinated obligations. Interest on
these notes had been payable semi-annually on February 1 and August 1. In
June 2004, we repurchased $32.1 million of these notes pursuant to a
tender offer. In the second quarter of 2004, we recorded a charge of $2.7
million related to the repurchase of these notes, which is recorded in
"Debt retirement costs" on the condensed consolidated statement of income.
The costs were comprised of approximately $1.8 million of premiums paid to
repurchase the notes, $0.6 million to write-off unamortized debt issuance
costs, $0.2 million to write-off unamortized debt discount and
approximately $0.1 million of other costs. In July 2004, we repurchased
approximately $0.5 million of these notes, and as of August 1, 2004, we
redeemed the remaining $92.5 million in outstanding notes. In the third
quarter of 2004, we recorded a charge of $6.8 million related to the
repurchase of these notes, which is recorded in "Debt retirement costs" on
the condensed consolidated statement of income. The costs were comprised
of approximately $4.8 million of premiums paid to repurchase the notes,
$1.6 million to write-off unamortized debt issuance costs and $0.4 million
to write-off unamortized debt discount.
Senior Notes Due 2011
These notes consist of $150.0 million of 7 5/8% Senior Notes due 2011,
which were issued on June 23, 2004 at 100% of the principal amount and
will mature on July 15, 2011. The notes are senior unsecured obligations
that rank equally with all of our existing and future senior unsecured
indebtedness, are effectively subordinated to all our existing and future
secured indebtedness to the extent of the value of the collateral securing
such indebtedness, including borrowing under our bank credit facility, and
rank senior to all of our existing and future subordinated indebtedness.
Interest on the Senior Notes is payable semi-annually on January 15 and
July 15, and commences on January 15, 2005. On or after July 15, 2008, we
may redeem some or all of the Senior Notes, with certain restrictions, at
a redemption price, plus accrued and unpaid interest, of 103.813% of
principal, declining to 100% in 2010 and thereafter. In addition, prior to
July 15, 2007, we may redeem up to 35% of the Senior Notes with the net
proceeds of qualified offerings of our equity at a redemption price of
107.625% of the principal amount of the Senior Notes, plus accrued and
unpaid interest. We incurred approximately $3.9 million of debt issuance
costs related to these notes, which is included in "Debt issuance costs"
on the accompanying condensed consolidated balance sheets and will be
amortized to interest expense over the life of the notes using the
effective interest method. Upon certain changes in control of Swift
Energy, each holder of Senior Notes will have the right to require us to
repurchase all or any part of 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 limitation on how much of our own common stock we may
repurchase. We are currently in compliance with the provisions of the
indenture governing these Senior Notes due 2011.
Senior Subordinated Notes Due 2012
These notes consist of $200.0 million of 9 3/8% Senior Subordinated
Notes due 2012, which were issued on April 16, 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 borrowings under our
bank credit facility. Interest on these notes is payable semi-annually on
May 1 and November 1. On or after May 1, 2007, we may redeem these notes,
with certain restrictions, at a redemption price, plus accrued and unpaid
interest, of 104.688% of principal, declining to 100% in 2010. In
addition, prior to May 1, 2005, we may redeem up to 33.33% of these notes
with the net proceeds of qualified offerings of our equity at 109.375% of
the principal amount of the notes, plus accrued and unpaid interest. Upon
certain changes in control of Swift Energy, each holder of these notes
will have the right to require us to repurchase the Senior Subordinated
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 notes include, among other restrictions, a limitation on how much of
our own common stock we may repurchase. We are currently in compliance
with the provisions of the indenture governing these Senior Subordinated
Notes due 2012.
16
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
The aggregate maturities on our long-term debt are $0 in 2004, 2005,
2006, 2007, $6.2 million in 2008 and $350.0 million thereafter,
respectively.
(4) Foreign Activities
As of September 30, 2004, our gross capitalized oil and gas property
costs in New Zealand totaled approximately $231.6 million. Approximately
$197.3 million has been included in the proved properties portion of our
oil and gas properties, while $34.3 million is included as unproved
properties. Our functional currency in New Zealand is the U.S. dollar.
(5) Segment Information
We have two reportable segments, one domestic and one foreign, which
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. We evaluate
our performance based on profit or loss from oil and gas operations before
price-risk management and other, general and administrative expenses,
interest expense, net and debt retirement costs. Our reportable segments
are managed separately based on their geographic locations. Financial
information by operating segment is presented below:
Three Months Ended September 30,
-----------------------------------------------------------------------------------
2004 2003
---------------------------------------- ----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ ------------ ------------ ------------ ------------ ------------
Oil and gas sales ............................. $ 63,497,169 $ 11,155,937 $ 74,653,106 $ 39,974,435 $ 12,112,886 $ 52,087,321
Costs and Expenses:
Depreciation, depletion and amortization ... 15,112,143 4,733,024 19,845,167 11,645,480 4,396,897 16,042,377
Accretion of asset retirement obligation ... 124,781 43,354 168,135 151,188 55,287 206,475
Lease operating costs ...................... 7,293,487 2,555,462 9,848,949 6,183,755 2,480,504 8,664,259
Severance and other taxes................... 6,310,555 767,439 7,077,994 4,076,456 989,752 5,066,208
------------ ------------ ------------ ------------ ------------ ------------
Income from oil and gas operations..............$ 34,656,203 $ 3,056,658 $ 37,712,861 $ 17,917,556 $ 4,190,446 $ 22,108,002
Price-risk management and other, net ....... 289,645 (534,799)
General and administrative, net............. 4,390,432 3,670,416
Interest expense, net ...................... 7,317,002 6,749,419
Debt retirement cost ...................... 6,822,476 ---
------------ ------------
Income before income taxes and cumulative
effect of change in accounting principle ... $ 19,472,596 $ 11,153,368
============ ============
17
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Nine Months Ended September 30,
-----------------------------------------------------------------------------------
2004 2003
---------------------------------------- ----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ ------------ ------------ ------------ ------------ ------------
Oil and gas sales ..............................$177,918,389 $ 34,513,276 $212,431,665 $123,693,311 $ 34,153,559 $157,846,870
Costs and Expenses:
Depreciation, depletion and amortization ... 44,533,330 13,116,577 57,649,907 32,508,198 14,122,491 46,630,689
Accretion of asset retirement obligation ... 375,028 123,842 498,870 448,711 175,050 623,761
Lease operating costs ...................... 22,147,817 7,762,925 29,910,742 18,131,045 7,018,005 25,149,050
Severance and other taxes................... 17,792,020 2,459,802 20,251,822 11,401,071 2,842,410 14,243,481
------------ ------------ ------------ ------------ ------------ ------------
Income from oil and gas operations..............$ 93,070,194 $ 11,050,130 $104,120,324 $ 61,204,286 $ 9,995,603 $ 71,199,889
Price-risk management and other, net ....... (1,089,449) (2,076,826)
General and administrative, net............. 12,595,665 10,564,959
Interest expense, net ...................... 21,361,566 20,107,188
Debt retirement cost ....................... 9,513,719 ---
------------ ------------
Income before income taxes and cumulative
effect of change in accounting principle ... $ 59,559,925 $ 38,450,916
============ ============
Property, plant and equipment, net..............$680,540,113 $187,410,284 $867,950,397 $616,251,046 $173,419,123 $789,670,169
============ ============ ============ ============ ============ ============
18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SWIFT ENERGY COMPANY
You should read the following discussion and analysis in conjunction
with our financial information and our condensed consolidated financial
statements and notes thereto included in this report. The following
information contains forward-looking statements. For a discussion of
limitations inherent in forward-looking statements, see "Forward-Looking
Statements" on page 30 of this report.
Overview
For the first nine months of 2004, we had revenues of $211.3 million
and production of 42.5 Bcfe. Our revenues were bolstered by oil and gas
prices remaining strong during this period and our domestic production for
the first nine months of 2004 increasing by 23% to 30.8 Bcfe compared to
the same period in 2003. We continued to focus our efforts and capital
throughout the third quarter on infrastructure improvements, increased
production and the development of longer life reserves in the Lake
Washington and AWP Olmos areas. Although our production in Lake Washington
was shut-in for brief periods due to hurricane-related weather in the
third quarter of 2004, our net production in Lake Washington for the first
nine months of 2004 has almost doubled as compared to the same period in
2003, and averaged approximately 9,800 net barrels of oil equivalent per
day, compared to approximately 5,000 net barrels of oil equivalent per day
in the same period in 2003. During 2004, capital expenditures were also
used for development in our three other domestic core areas. New Zealand
accounted for 11.7 Bcfe of production in the first nine months of 2004, a
21% decrease from production in the same period in 2003. Natural gas
production in New Zealand declined primarily due to natural production
declines in our TAWN properties. The TAWN gas contract has been
renegotiated to lower the total contract quantity and deliverability
rates, and we anticipate meeting these revised contracted volumes. There
is no penalty if the fields are unable to produce these minimum contracted
volumes. We are currently drilling a development well in the Tariki field
to maximize production and deliverability from that field. New Zealand
natural gas and natural gas liquids ("NGL") contracts are denominated in
the New Zealand dollar, which has significantly strengthened during the
last several years against the U.S. dollar.
Our production costs were up in the first nine months of 2004
predominately due to increased production in Lake Washington, higher
severance taxes due to increased domestic revenues, and currency exchange
rates in New Zealand. Our general and administrative expenses increased in
the first nine months of 2004 primarily due an increase in costs related
to our corporate governance activities and on going compliance efforts
with the Sarbanes-Oxley Act, salaries and benefits, franchise tax expense,
as well as higher costs in our New Zealand operations due to currency
exchange rates. We are working to reduce our controllable production and
general and administrative costs on a per unit produced basis for the
remainder of 2004.
Our debt to PV-10 ratio decreased to 15% at September 30, 2004 compared
to 22% at December 31, 2003, due to higher crude oil and natural gas
prices, which have increased our PV-10 value. Our debt to capitalization
ratio was 44% at September 30, 2004 compared to 46% at year-end 2003, as
debt levels increased slightly in 2004 but were offset by the increase in
retained earnings as a result of current year profit. In June 2004, we
repurchased $32.1 million of our 10 1/4% Senior Subordinated Notes due
2009 through a tender offer. We recorded a charge of $2.7 million related
to the tender offer, which is recorded in "Debt retirement costs" on the
condensed consolidated statement of income. In July 2004, we repurchased
$0.5 million in Senior Subordinated Notes due 2009 at the close of the
tender offer. On August 1, 2004, we redeemed the remaining $92.5 million
of these notes in accordance with our redemption rights under the
indenture governing these notes. In the third quarter of 2004, we recorded
approximately $6.8 million of debt retirement costs related to the
repurchase of these remaining notes. The redemption of our Senior
Subordinated Notes due 2009 has lowered our effective interest rate.
We will continue to look for opportunities in the near term to improve
our balance sheet and liquidity, but we expect our capital expenditures to
continue to equal or modestly exceed our cash flow for the near term.
Our 2005 capital expenditure budget will be dependent upon operational
performance and commodity pricing levels during the year, and we
anticipate 2005 capital expenditures to approximate or slightly exceed our
cash flow provided from operating activities during 2005.
19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Based on results for the first nine months of 2004 and on current
operating conditions, we estimate that 2004 production levels will
increase over 2003 levels by approximately 10%, which is lower than the
previously estimated range of 11% to 15%. We continue to believe that
commodity prices will remain strong for the remainder of 2004 and that we
remain positioned for reserve growth over 2003 levels with our planned
fourth quarter 2004 activities.
Results of Operations - Three Months Ended September 30, 2004 and 2003
Revenues. Our revenues in the third quarter of 2004 increased by 45%
compared to revenues in the same period in 2003, due primarily to an
increase in commodity prices and production from our Lake Washington area.
Revenues from our oil and gas sales comprised substantially all of net
revenues for the third quarter of 2004 and 2003. In the third quarter of
2004, oil production made up 46% of total production, natural gas made up
43% and NGL represented 11%. In the third quarter of 2003, natural gas
production made up 49% of total production, oil production made up 40% and
NGL represented 11%. The percentage of our total production from oil
increased as Lake Washington production, which is almost entirely oil,
increased over prior year levels. Although production in Lake Washington
was shut-in for several days due to hurricane-related weather during the
third quarter of 2004, continued development in this area has increased
production significantly.
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 Ended September 30,
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
- ---- -------------------------------------- ----------------------------------------
2004 2003 2004 2003
---- ---- ---- ----
AWP Olmos ..................... $ 11.9 $ 10.5 2.1 2.3
Brookeland .................... 4.5 3.9 0.8 1.0
Lake Washington ............... 37.1 16.6 5.5 3.5
Masters Creek ................. 5.4 5.6 0.9 1.3
Other ......................... 4.6 3.4 0.9 0.6
----------------- ------------------ ---------------- ----------------------
Total Domestic ........ $ 63.5 $ 40.0 10.2 8.7
----------------- ------------------ ---------------- ----------------------
Rimu/Kauri .................... 4.4 3.5 1.0 1.0
TAWN .......................... 6.8 8.6 2.7 3.9
----------------- ------------------ ---------------- ----------------------
Total New Zealand .... $ 11.2 $ 12.1 3.7 4.9
----------------- ------------------ ---------------- ----------------------
Total ........ $ 74.7 $ 52.1 13.9 13.6
================== ================== ================ ======================
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
The following table provides additional information regarding our oil,
NGL and gas sales:
Net Sales Volume Average Sales Price
---------------- -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
------------ ----------- ----------- ------------- ---------- ----------- ----------
2004
- ----
Three Months Ended September 30:
Domestic ...................... 1,008 151 3.2 10.2 $41.60 $26.44 $5.47
New Zealand ................... 68 100 2.8 3.7 $47.75 $18.63 $2.21
------------ ----------- ----------- -------------
Total ................... 1,076 251 6.0 13.9 $41.99 $23.33 $3.97
============ =========== =========== =============
2003
- ----
Three Months Ended September 30:
Domestic ...................... 757 179 3.2 8.7 $29.33 $17.96 $4.63
New Zealand ................... 160 68 3.5 4.9 $28.83 $13.76 $1.87
------------ ----------- ----------- -------------
Total ................... 917 247 6.7 13.6 $29.24 $16.81 $3.17
============ =========== =========== =============
Oil and gas sales in the third quarter of 2004 increased by 43%, or
$22.6 million, from the level of those revenues for the same period in
2003. The increase in production volumes during the third quarter of 2004
was primarily from our Lake Washington area.
In the third quarter of 2004, our $22.6 million increase in oil, NGL,
and gas sales resulted from:
oPrice variances that had a $20.1 million favorable impact on sales, of
which $13.7 million was attributable to the 44% increase in average
oil prices received, $4.7 million was attributable to the 25% increase
in average gas prices received, and $1.6 million was attributable to
the 39% increase in average NGL prices received; and
oVolume variances that had a $2.5 million favorable impact on sales,
with $4.6 million of increases coming from the 159,000 Bbl increase in
oil sales volumes, $0.1 million of increases due to the 3,000 Bbl
increase in NGL sales volumes, partially offset by a $2.2 million
decrease attributable to the 0.7 Bcf decrease in gas sales volumes.
Costs and Expenses. Our total expenses in the third quarter of 2004
increased $15.1 million, or 37%, compared to expenses in the same period
in 2003. The majority of the increase was due to debt retirement costs of
$6.8 million related to the repurchase of a portion of our Senior
Subordinated Notes due 2009, an increase of $3.8 million in depreciation,
depletion and amortization, a $2.0 million increase in severance taxes,
and a $1.2 million increase in lease operating costs.
Our third quarter of 2004 general and administrative expenses, net,
increased $0.7 million, or 20%, from the level of such expenses in the
same 2003 period. This increase was due primarily to an increase in
salaries and benefits, increased costs related to our on going compliance
efforts with the Sarbanes-Oxley Act, as well as higher costs in our New
Zealand operations due to the increased currency exchange rate of the New
Zealand dollar as compared to the U.S. dollar. Our general and
administrative expenses per Mcfe produced were $0.32 per Mcfe in the third
quarter of 2004 and $0.27 in the 2003 period. The portion of supervision
fees recorded as a reduction of general and administrative expenses were
$1.6 million for the third quarter of 2004 and $0.8 million for the same
period in 2003.
Depreciation, depletion, and amortization of our oil and gas
properties, or DD&A, increased $3.8 million, or 24%, in the third quarter
of 2004 from 2003 levels. Domestically, DD&A increased $3.5 million in the
2004
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
period, mainly due to higher production in the period, and the DD&A rate
per Mcfe of production increased to $1.49 from $1.33 in the comparable
2003 period mainly due to increases in future development costs and oil
and gas property additions, which increased our full-cost pool balance. In
New Zealand, DD&A increased $0.3 million in the 2004 period as the DD&A
rate per Mcfe of production increased to $1.26 from $0.90 in the 2003
period mainly due to increases in future development costs and oil and gas
property additions, which increased our full-cost pool balance in New
Zealand. Our overall DD&A rate per Mcfe of production was $1.43 in the
third quarter of 2004 and $1.18 in the comparable 2003 period.
We recorded $0.2 million of accretion on our asset retirement
obligation in both the third quarter of 2004 and 2003.
Our lease operating costs per Mcfe produced were $0.71 in the third
quarter of 2004 and $0.64 in the same period of 2003. There were no
supervision fees recorded as a reduction to production costs for the third
quarter of 2004 and $0.5 million for the same 2003 period. Our lease
operating costs in the third quarter of 2004 increased $1.2 million, or
14%, over the level of such expenses in the comparable 2003 period.
Approximately $1.1 million of the increase in lease operating costs during
the third quarter of 2004 was related to our domestic operations, which
increased due to higher production and facility repairs in our Lake
Washington area in that period and the reduction to 2003 expense of $0.5
million from supervision fees. Despite a decrease in production in New
Zealand, production costs increased by $0.1 million in the third quarter
of 2004 primarily due to the continued development of our Kauri field and
the increased currency exchange rate of the New Zealand dollar as compared
to the U.S. dollar.
Severance and other taxes in the third quarter of 2004 increased $2.0
million, or 40%, 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 third quarter of 2004.
Severance and other taxes, as a percentage of oil and gas sales, were
approximately 9.5% and 9.7% in the third quarters of 2004 and 2003,
respectively.
Interest expense on our Senior Subordinated Notes due 2012, including
amortization of debt issuance costs, totaled $4.8 million in both the
third quarter of 2004 and 2003. Interest expense on our Senior
Subordinated Notes due 2009 which were repurchased in the second and third
quarters of 2004, including amortization of debt issuance costs, totaled
$0.8 million in the third quarter of 2004 and $3.3 million in 2003.
Interest expense on our bank credit facility, including commitment fees
and amortization of debt issuance costs, totaled $0.3 million in both the
third quarter of 2004 and 2003. Interest expense on our Senior Notes due
2011, issued in June 2004, was $3.0 million in the third quarter of 2004.
The total interest cost in the third quarter of 2004 was $8.9 million, of
which $1.6 million was capitalized. The total interest cost in the third
quarter of 2003 was $8.4 million, of which $1.7 million was capitalized.
In the third quarter of 2004, we incurred $6.8 of debt retirement costs
related to the redemption of the remaining portion of our Senior
Subordinated Notes due 2009. The costs were comprised of approximately
$4.8 million of premiums paid to redeem the notes, $1.6 million to
write-off unamortized debt issuance costs and $0.4 million to write-off
unamortized debt discount.
The overall effective tax rate was 27.4% and 36.7% for the third
quarters of 2004 and 2003, respectively. The effective tax rate for the
third quarter of 2004 was lower than the statutory tax rates primarily due
to reductions from the New Zealand statutory rate attributable to the
currency effect on the New Zealand deferred tax calculation, along with
reductions to the domestic statutory tax rate due to changes from prior
year tax estimates that are updated after we file the prior year's tax
return and the adjustment of a domestic tax contingency.
Net Income. Our net income in the third quarter of 2004 of $14.1
million was 100% higher, and Basic EPS of $0.51 was 96% higher, than our
third quarter of 2003 net income of $7.1 million and Basic EPS of $0.26.
Our Diluted EPS in the third quarter of 2004 of $0.50 was 94% higher than
our 2003 Diluted EPS of $0.26. These amounts increased in the 2004 period
as oil and gas revenues increased due to higher commodity prices and
increased domestic production.
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Results of Operations - Nine Months Ended September 30, 2004 and 2003
Revenues. Our revenues in the first nine months of 2004 increased by
36% compared to revenues in the same period in 2003, due primarily to
increases in oil prices and production from our Lake Washington and AWP
areas domestically and our Rimu/Kauri area in New Zealand. Substantially
all of our net revenues for the first nine months of 2004 and 2003 were
from oil and gas sales. In the first nine months of 2004, oil production
made up 47% of total production, natural gas made up 41% and NGL
represented 12%. In the first nine months of 2003, natural gas production
made up 54% of total production, oil production made up 37% and NGL
represented 9%.
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:
Nine Months Ended September 30,
---------------------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
- ---- -------------------------------------- ----------------------------------------
2004 2003 2004 2003
---- ---- ---- ----
AWP Olmos ..................... $ 36.2 $ 34.6 6.9 6.4
Brookeland .................... 13.8 12.3 2.7 2.9
Lake Washington ............... 98.8 40.4 16.1 8.3
Masters Creek ................. 16.0 21.3 2.9 4.6
Other ......................... 13.1 15.0 2.2 2.8
----------------- ------------------ ---------------- ----------------------
Total Domestic ........ $ 177.9 $ 123.6 30.8 25.0
----------------- ------------------ ---------------- ----------------------
Rimu/Kauri .................... 13.8 6.8 3.2 2.0
TAWN .......................... 20.7 27.4 8.5 12.8
----------------- ------------------ ---------------- ----------------------
Total New Zealand ..... $ 34.5 $ 34.2 11.7 14.8
----------------- ------------------ ---------------- ----------------------
Total .......... $ 212.4 $ 157.8 42.5 39.8
================= ================== ================ ======================
The following table provides additional information regarding our oil,
NGL and gas sales:
Net Sales Volume Average Sales Price
---------------- -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) Bcfe) (Bbl) (Bbl) (Mcf)
------------ ----------- ----------- ------------- ------------ ----------- -----------
2004
- ----
Nine Months Ended September 30:
Domestic ...................... 3,047 540 9.3 30.8 $37.58 $23.29 $5.48
New Zealand ................... 296 257 8.3 11.7 $39.26 $17.62 $2.20
------------ ----------- ----------- -------------
Total ................... 3,343 797 17.6 42.5 $37.72 $21.46 $3.93
============ =========== =========== =============
2003
- ----
Nine Months Ended September 30:
Domestic ...................... 2,010 419 10.4 25.0 $29.96 $20.18 $5.30
New Zealand ................... 418 213 11.0 14.8 $29.03 $13.33 $1.74
------------ ----------- ----------- -------------
Total ................... 2,428 632 21.4 39.8 $29.80 $17.87 $3.46
============ =========== =========== =============
Oil and gas sales in the first nine months of 2004 increased by 35%, or
$54.6 million, from the level of those revenues for the same period in
2003. The increase in production volumes during the first nine months of
2004 was primarily from our Lake Washington and AWP Olmos areas
domestically, and the Rimu/Kauri area in New Zealand.
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
In the first nine months of 2004, our $54.6 million increase in oil,
NGL, and gas sales resulted from:
oPrice variances that had a $37.5 million favorable impact on sales, of
which $26.5 million was attributable to the 27% increase in average
oil prices received, $8.2 million was attributable to the 13% increase
in average gas prices received and $2.8 million was attributable to
the 20% increase in average NGL prices received; and
oVolume variances that had a $17.1 million favorable impact on sales,
with $27.2 million of increases coming from the 914,000 Bbl increase
in oil sales volumes, $3.0 million of increases due to the 165,000 Bbl
increase in NGL sales volumes, partially offset by $13.1 million in
decreases attributable to the 3.8 Bcf decrease in gas sales volumes.
Costs and Expenses. Our total expenses in the first nine months of 2004
increased $34.5 million, or 29%, compared to expenses in the same period in
2003. The majority of the increase was due to an $11.0 million increase in
depreciation, depletion and amortization, $9.5 million of debt retirement
costs related to the repurchase of our Senior Subordinated Notes due 2009,
a $6.0 million increase in severance taxes, and a $4.8 million increase in
lease operating costs.
As discussed in Note 1 to the Condensed 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 condensed consolidated statement of income.
Our first nine months of 2004 general and administrative expenses, net,
increased $2.0 million, or 19%, from the level of such expenses in the
same 2003 period. This increase is due primarily to increased costs
related to our on going compliance efforts with the Sarbanes-Oxley Act, an
increase in salaries and benefits, as well as higher costs in our New
Zealand operations due to the increased currency exchange rate of the New
Zealand dollar as compared to the U.S. dollar. Our general and
administrative expenses per Mcfe produced were $0.30 per Mcfe in the first
nine months of 2004 and $0.27 in the same 2003 period. The portion of
supervision fees recorded as a reduction of general and administrative
expenses was $4.0 million for the first nine months of 2004 and $2.2
million for the same 2003 period.
Depreciation, depletion, and amortization of our oil and gas
properties, or DD&A, increased $11.0 million, or 24%, in the first nine
months of 2004 from 2003 levels for the same period. Domestically, DD&A
increased $12.0 million in the first nine months of 2004, mainly due to
higher production in the period, and the DD&A rate per Mcfe of production
increased to $1.45 from $1.30 in the comparable 2003 period mainly due to
increases in future development costs and oil and gas property additions,
which increased our full-cost pool balance. In New Zealand, DD&A decreased
by $1.0 million in the 2004 period due to decreased production in the
period even though the DD&A per Mcfe of production increased to $1.13 from
$0.95 mainly due to increases in future development costs and oil and gas
property additions, which increased our full-cost pool balance in New
Zealand. Our overall DD&A rate per Mcfe of production was $1.36 in the
first nine months of 2004 and $1.17 in the comparable 2003 period.
We recorded $0.5 million of accretion on our asset retirement
obligation in the first nine months of 2004 and $0.6 million in the
comparable 2003 period.
Our lease operating costs per Mcfe produced were $0.70 in the first
nine months of 2004 and $0.63 in the same period of 2003. There were no
supervision fees recorded as a reduction to production costs for the first
nine months of 2004 and $1.5 million for the same 2003 period. Our lease
operating costs in the first nine months of 2004 increased $4.8 million,
or 19%, over the level of such expenses in the comparable 2003 period.
Approximately $4.0 million of the increase in lease operating costs during
the first nine months of 2004 was related to our domestic operations,
which increased due to higher production from our Lake Washington and
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
AWP Olmos areas in that period and the reduction of 2003 expense of $1.5
million from supervision fees. Despite a decrease in production in New
Zealand, production costs increased by $0.8 million in the first nine
months of 2004 primarily due to the continued development of our Kauri
field and the increased currency exchange rate of the New Zealand dollar
as compared to the U.S. dollar.
Severance and other taxes in the first nine months of 2004 increased
$6.0 million, or 42%, over the level of such expenses in the comparable
2003 period. The increase was due primarily to higher commodity prices and
increased Lake Washington, AWP Olmos, and Rimu/Kauri production. Severance
taxes on oil in Louisiana are 12.5% of oil sales, therefore as our
percentage of oil production, which comes from Lake Washington increases,
the overall percentage of severance costs to sales will increase.
Severance and other taxes, as a percentage of oil and gas sales, were
approximately 9.5% and 9.0% in the first nine months of 2004 and 2003,
respectively.
Interest expense on our Senior Subordinated Notes due 2012, including
amortization of debt issuance costs, totaled $14.4 million in the first
nine months of 2004 and $14.3 million in the 2003 period. Interest expense
on our Senior Subordinated Notes due 2009 which were repurchased in the
second and third quarters of 2004, including amortization of debt issuance
costs, totaled $7.4 million in the first nine months of 2004 and $9.9
million in the 2003 period. Interest expense on our bank credit facility,
including commitment fees and amortization of debt issuance costs, totaled
$1.1 million in the first nine months of both 2004 and 2003. Interest
expense on our Senior Notes due 2011, issued in June 2004, was $3.2
million in the first nine months of 2004. The total interest cost in the
first nine months of 2004 was $26.1 million, of which $4.7 million was
capitalized. The total interest cost in the first nine months of 2003 was
$25.3 million, of which $5.2 million was capitalized.
In the first nine months of 2004, we incurred $9.5 million of debt
retirement costs related to the repurchase and redemption of our Senior
Subordinated Notes due 2009. The costs were comprised of approximately
$6.5 million of premiums paid to repurchase the notes, $2.2 million to
write-off unamortized debt issuance costs, $0.6 million to write-off
unamortized debt discount and approximately $0.2 million of other costs.
The overall effective tax rate was 30.1% and 35.6% for the first nine
months of 2004 and 2003, respectively. The effective tax rate for the
first nine months of 2004 was lower than the statutory tax rates primarily
due to reductions from the New Zealand statutory rate attributable to the
currency effect on the New Zealand deferred tax calculation, along with
reductions to the domestic statutory tax rate due to changes from prior
year tax estimates that are updated after we file the prior year's tax
return.
Net Income. Our net income in the first nine months of 2004 of $41.6
million was 104% higher, and Basic EPS of $1.50 was 101% higher, than our
first nine months of 2003 net income of $20.4 million and Basic EPS of
$0.75. Our Diluted EPS in the first nine months of 2004 of $1.47 was 98%
higher than our 2003 Diluted EPS of $0.74. These amounts increased in the
2004 period as oil and gas revenues 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 nine
months of 2003, offset somewhat by the charge for debt retirement costs in
the 2004 period.
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Contractual Commitments and Obligations
Our contractual commitments for the remainder of 2004 and the next five
years and thereafter as of September 30, 2004 are as follows:
Remainder
of 2004 2005 2006 2007 2008 2009 Thereafter Total
--------------------------------------------------------------------------------------------
(In thousands)
Non-cancelable operating lease (1)...... $ 536 $2,430 $2,484 $2,482 $2,450 $2,339 $ 13,025 $ 25,746
Asset Retirement Obligation (2) ........ 943 515 515 515 515 515 7,237 10,755
Drilling Rig and Seismic ................. 7,184 --- --- --- --- --- --- 7,184
Senior Notes due 2011 (3) .............. --- --- --- --- --- --- 150,000 150,000
Senior Subordinated Notes due 2012 (3) . --- --- --- --- --- --- 200,000 200,000
Credit Facility (4) .................... --- --- --- --- 6,200 --- --- 6,200
--------------------------------------------------------------------------------------------
Total ............................. $8,663 $2,945 $2,999 $2,997 $9,165 $2,854 $370,262 $399,885
============================================================================================
(1)Our office lease in Houston, Texas extends until 2015.
(2)Amounts shown by year are the fair values at September 30, 2004.
(3)These amounts do not include the interest obligation, which is paid
semi-annually.
(4)The credit facility expires in October 2008 and these amounts exclude a $0.8
million standby letter of credit outstanding under this facility.
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 nine months of 2004 when compared to
longer-term historical prices, and has recently hit record highs. Factors
such as worldwide supply disruptions, worldwide economic conditions,
fluctuating currency exchange rates, and actions taken by OPEC can cause
wide fluctuations in the price of oil. Domestic natural gas prices
continue to remain high when compared to longer-term historical prices.
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 domestic natural gas. Such
factors are beyond our control.
Income Tax Regulations
The tax laws in the jurisdictions we operate in are continuously
changing and professional judgments regarding such tax laws can differ.
Although the Internal Revenue Service regulations concerning the recently
enacted American Jobs Creation Act of 2004 have not been issued, we do not
believe this act will have a material impact on our financial position or
cash flow from operations in the near-term.
Liquidity and Capital Resources
During the first nine months of 2004, we largely relied upon our net
cash provided by operating activities of $126.4 million and net proceeds
from the offering of our Senior Notes due 2011 of $150.0 million to fund
capital expenditures of $128.5 million and repurchase $125.0 million of
our Senior Subordinated Notes due 2009. During the first nine months of
2003, we relied upon our net cash provided by operating activities of
26
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
$84.0 million and proceeds from borrowings under our bank credit facility
of $11.9 million to fund capital expenditures of $101.5 million.
Net Cash Provided by Operating Activities. For the first nine months of
2004, net cash provided by operating activities was $126.4 million,
representing a 50% increase as compared to $84.0 million generated during
the first nine months of 2003. The $42.4 million increase was primarily
due to an increase of $54.6 million in oil and gas sales for the 2004
period, attributable to higher commodity prices and increased domestic
production, offset in part by lease operating cost increases due to higher
domestic production, severance taxes due to higher commodity prices. Net
cash provided by operating activities is $6.7 million higher than
announced in our earnings release on November 4, 2004 due to reclassifying
the cash portion of debt retirement cost as a financing activity rather
than an operating activity.
Accounts Receivable. Included in the "Accounts receivable" balance,
which totaled $30.9 million and $27.4 million at September 30, 2004 and
December 31, 2003, respectively, on the accompanying balance sheets, 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 those 2003
disputed volumes.
We assess the collectibility of accounts receivable, and based on our
judgment, we accrue a reserve when we believe a receivable may not be
collected. At September 30, 2004 and December 31, 2003, we had an
allowance for doubtful accounts of $0.5 million. These allowances for
doubtful accounts have been deducted from the total "Accounts receivable"
balances on the accompanying condensed consolidated balance sheets.
Bank Credit Facility. We had $6.2 million in borrowings under our bank
credit facility at September 30, 2004, and $15.9 million in outstanding
borrowings at December 31, 2003. Our bank credit facility at September 30,
2004 consisted of a $400.0 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 November 1, 2004. In June 2004, we renewed this credit facility,
increasing the facility amount to $400.0 million from $300.0 million and
extending its expiration to October 1, 2008 from October 1, 2005. We
maintained the commitment amount at $150.0 million, which amount was set
at our request effective May 9, 2003. Under the terms of our bank credit
facility, we can increase this commitment amount 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 that changed somewhat as the facility was renewed and
extended, requirements to maintain certain minimum financial ratios
(principally pertaining to working capital and EBITDAX), and limitations
on incurring other debt. We are in compliance with the provisions of this
agreement.
Repurchase of Senior Subordinated Notes due 2009. In June 2004, we
repurchased $32.1 million of our Senior Subordinated Notes due 2009
pursuant to a tender offer, and recorded debt retirement costs of $2.7
million related to this repurchase. In July 2004, we repurchased
approximately $0.5 million of these notes, and as of August 1, 2004, we
redeemed the remaining $92.5 million of these notes. We have recorded $6.8
million in the third quarter of 2004 for a total of $9.5 million in debt
retirement costs related to the total repurchase of these notes.
Debt Maturities. Our credit facility extends until October 1, 2008. Our
$150.0 million Senior Notes mature July 15, 2011, and our $200.0 million
Senior Notes mature May 1, 2012.
Working Capital. Our working capital improved from a deficit of $35.2
million at December 31, 2003, to a deficit of $10.7 million at September
30, 2004. The improvement was primarily due to an increase in accounts
receivable due to higher sales prices and accrued volumes at September 30,
2004, along with a reduction in our accrued capital costs in the 2004
period due decreased capital activity when compared to year-end 2003.
27
Capital Expenditures. During the first nine months of 2004, we used
$128.5 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
Domestic activities of $102.7 million as follows:
o $77.8 million for drilling and developmental activity costs;
o $11.4 million of seismic costs, mainly in the Lake Washington area;
o $10.8 million on prospect costs, principally prospect leasehold and
geological costs of unproved prospects;
o $1.7 million relating to costs directly associated with evaluating
potential producing property acquisitions; and
o $1.0 million primarily for computer equipment, software, furniture,
and fixtures.
New Zealand activities of $25.8 million as follows:
o $20.6 million for drilling and developmental activity costs;
o $5.0 million on prospect costs and geological costs of unproved
prospects;
o $0.2 million for furniture and fixtures.
We have spent considerable time and capital in 2003 and the first nine
months of 2004, on significant facility capacity upgrades in the Lake
Washington area to increase facility capacity to approximately 20,000
barrels per day for crude oil, up from 9,000 barrels per day capacity in
the first quarter 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 also began a
seismic acquisition and interpretation program in our Lake Washington area
that should continue through 2005. We are also continuing to work on and
plan for further increases in facility capacity in the Lake Washington
area.
We drilled or participated in drilling 37 domestic development wells
and four domestic exploratory wells in the first nine months of 2004.
Twenty of the development wells and one exploratory well were in the Lake
Washington area. Thirteen of the development wells were in the AWP Olmos
area. One domestic exploratory well and 31 of the domestic development
wells were completed. In New Zealand, the Kauri-E3, E4, E5 and E6 wells
were completed, five development Manutahi wells were drilled and
completed, and one exploratory Manutahi well was unsuccessful. The Tariki
D1 development well is currently drilling in the TAWN area.
For the last quarter of 2004, we expect to make capital expenditures of
approximately $40 to $50 million. Our current estimated total capital
expenditures for 2004 are approximately $170.0 to $180.0 million,
excluding acquisition costs and net of approximately $3.0 million to $11.0
million in non-core property dispositions. Capital expenditures for 2003
were $144.5 million.
Capital expenditure for 2005 will be dependent upon operational
performance and commodity pricing levels during the year, and we
anticipate these expenditures to approximate our cash flow from operating
activities.
We believe that the anticipated internally generated cash flows for
2004, together with bank borrowings under our bank credit facility, will
be sufficient to finance the costs associated with our currently budgeted
2004 capital expenditures. If producing property acquisitions become
attractive during the fourth quarter of 2004, we will explore the use of
debt and/or equity offerings to fund such activity.
28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
During the last quarter of 2004, we anticipate drilling or
participating in the drilling of up to an additional eight to twelve wells
in the Lake Washington area, an additional 2 wells in the AWP Olmos area,
and several additional wells, with varying working interest percentages,
mainly in South Texas. In addition, we plan on drilling one Kauri well in
New Zealand.
Our 2004 capital expenditures continue to be focused on developing and
producing long-lived reserves in our Lake Washington, AWP Olmos, and
Rimu/Kauri area. We expect our 2004 total production to increase over 2003
levels, primarily from the Lake Washington, AWP Olmos, and Rimu/Kauri
areas. 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.
New Accounting Principles
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. In September 2004, the EITF
issued FASB Staff Position (FSP) 142-2, in which the FASB staff further
concluded that the costs for acquiring contractual mineral rights in oil
and gas properties would continue to be recorded as tangible assets. These
staff positions had no impact on our consolidated financial statements.
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 our financial position or results of operations.
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
29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
employee stock compensation matters. This statement is effective for
interim or annual periods beginning after June 15, 2005. 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 allows that the expense relating
to employee stock options to only be disclosed in the footnotes of the
financial statements. We are evaluating the effects that will result from
future adoption of this proposed statement.
In September 2004, the EITF discussed an issue dealing with how to
evaluate whether a partnership should be consolidated by its general
partner, EITF Issue 04-5. The issue deals with rights held by the limited
partners and how this affects the consolidation of partnerships by the
sole general partner in accordance with generally accepted accounting
principles, absent the existence of these rights held by the limited
partners. The EITF will discuss this issue in the future and we do not
believe this staff position will have a material impact on our
Consolidated Financial Statements.
In September 2004, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the SEC staff's
views regarding SFAS No. 143 and its impact on both the full-cost ceiling
test and the calculation of depletion expense. In accordance with SAB 106,
beginning in the fourth quarter of 2004, undiscounted abandonment cost for
future wells, not recorded at the present time but needed to develop the
proved reserves in existence at the present time, should be included in
the unamortized cost of oil and gas properties, net of related salvage
value, for purposes of computing DD&A. The effect of including
undiscounted abandonment costs of future wells to the undiscounted cost of
oil and gas properties will increase depletion expense in future periods,
however, we currently do not believe such increases will be material.
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.
30
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 contracts, swaps, and option
contracts such as floors and collars) 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 September 30, 2004, we had in place price floors in
effect through the March 2005 contract month for natural gas, these cover
our domestic natural gas production for October 2004 to March 2005. The
natural gas price floors cover notional volumes of 950,000 MMBtu, with a
weighted average floor price of $5.63 per MMBtu. Our natural gas hedges in
place at September 30, 2004 are expected to cover approximately 10% to 15%
of our domestic natural gas production from October 2004 to March 2005. At
September 30, 2004, we also had in place price floors in effect from the
January 2005 contract month to the March 2005 contract month for crude
oil, that cover our domestic crude oil production for January 2005 to
March 2005. The crude oil price floors cover notional volumes of 216,000
barrels, with a weighted average floor price of $37.00 per barrel. Our
crude oil hedges in place at September 30, 2004 are expected to cover
approximately 15% to 20% of our domestic crude oil production from January
2005 to March 2005.
oNew Zealand Gas Contracts - All of our current 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, natural
gas and NGL sales contracts , and New Zealand income tax calculations, all
denominated in New Zealand dollars.
31
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS (Continued)
Interest Rate Risk
Our Senior Notes due 2011 and Senior Subordinated Notes due 2012 have
fixed interest rates, consequently we are not exposed to cash flow risk
from market interest rate changes on these notes. However, there is a risk
that market rates will decline and the required interest payments on our
Senior Notes and Senior Subordinated Notes may exceed those payments based
on the current market rate. At September 30, 2004, we had $6.2 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 48 basis points
and would not have a material adverse effect on our 2004 cash flows based
on this same level or a modest level of borrowing.
32
CONTROLS AND PROCEDURES
Our chief executive officer and chief financial officer have evaluated
our disclosure controls and procedures, as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934 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 Swift
Energy as required under the Exchange Act to be disclosed in this report.
There were no significant changes in our internal controls that could
significantly affect such controls subsequent to the date of their
evaluation.
In conjunction with our preparation toward compliance with Section 404
of the Sarbanes-Oxley Act of 2002, including the required management
assessment of the effectiveness of the internal controls over financial
reporting, we continue to evaluate, analyze, document and test the
Company's internal controls over financial reporting. As part of this
process, we are implementing certain enhancements to our internal control
over financial reporting. Based on the work performed to date, including
internal audit procedures and testing, we are currently not aware of any
internal control deficiencies that individually, or in the aggregate,
would constitute a material weakness.
Discussions and updates, with respect to the Section 404 process, are
regularly held with the Company's independent auditors, the Audit
Committee, the Board of Directors and management. The Company can provide
no assurance as to whether management or the Company's independent
auditors will complete their work on a timely basis necessary for the
Company to be in compliance with the SEC's rules. We also can provide no
assurances as to management's conclusions, or those of the Company's
independent auditors, with respect to the effectiveness of the Company's
internal control over financial reporting at December 31, 2004, under
Section 404 of the Sarbanes-Oxley Act.
33
34
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. Sales of Unregistered Securities and Use of Proceeds - None
Item 3. Defaults Upon Senior Securities - None
Item 4. Submission of Matters to a Vote of Security Holders - None
Item 5. Other Information - None
Item 6. 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.
34
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: November 8, 2004 By: (original signed by)
--------------------------- ---------------------------------
Alton D. Heckaman, Jr.
Senior Vice President - Finance and
Chief Financial Officer
Date: November 8, 2004 By: (original signed by)
--------------------------- ---------------------------------
David W. Wesson
Controller and Principal Accounting
Officer
xhibit 31.1
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended
September 30, 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: November 8, 2004
/s/ Terry E. Swift
-----------------------------------------
Terry E. Swift
President and
Chief Executive Officer
36
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
September 30, 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: November 8, 2004
/s/ Alton D. Heckaman, Jr.
-------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President - Finance and
Chief Financial Officer
37
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 September 30, 2004 (the "Report") of Swift Energy Company ("Swift") as
filed with the Securities and Exchange Commission on November 8, 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: November 8, 2004
/s/ Alton D. Heckaman, Jr.
---------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President-Finance and
Chief Financial Officer
Dated: November 8, 2004
/s/ Terry E. Swift
---------------------------------------
Terry E. Swift
President and Chief Executive Officer
38