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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2003
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
(281) 874-2700
(Address and telephone number of principal executive offices)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes X No
Indicate the number of shares outstanding of each of the Registrant's classes of
common stock, as of the latest practicable date.
Common Stock 27,444,262 Shares
($.01 Par Value) (Outstanding at October 31, 2003)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets
- September 30, 2003 and December 31, 2002 3
Consolidated Statements of Income
- For the Three-month and Nine-month periods ended
September 30, 2003 and 2002 5
Consolidated Statements of Stockholders' Equity
- September 30, 2003 and December 31, 2002 6
Consolidated Statements of Cash Flows
- For the Nine-month periods ended September 30, 2003 and 2002 7
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 19
Item 3. Quantitative and Qualitative Disclosures About Market Risk 30
Item 4. Controls and Procedures 31
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 32
Item 2. Changes in 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 None
Item 6. Exhibit Index and Reports on Form 8-K 32
SIGNATURES 33
2
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, 2003 December 31, 2002
------------------------ -------------------------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 2,678,315 $ 3,816,107
Accounts receivable -
Oil and gas sales 23,335,323 17,360,716
Associated limited partnerships
and joint ventures 143,190 191,964
Joint interest owners 1,400,790 3,364,846
Other current assets 4,695,602 5,034,566
------------------------ -------------------------
Total Current Assets 32,253,220 29,768,199
------------------------ -------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 1,264,918,011 1,150,633,802
Unproved properties not being amortized 65,642,790 69,603,481
------------------------ --------------------------
1,330,560,801 1,220,237,283
Furniture, fixtures, and other equipment 10,204,883 9,595,944
------------------------ -------------------------
1,340,765,684 1,229,833,227
Less-Accumulated depreciation, depletion,
and amortization (551,095,515) (504,323,773)
------------------------ -------------------------
789,670,169 725,509,454
------------------------ -------------------------
Other Assets:
Deferred income taxes 433,591 2,680,585
Deferred charges 8,279,976 9,047,621
------------------------ -------------------------
8,713,567 11,728,206
------------------------ -------------------------
$ 830,636,956 $ 767,005,859
======================== =========================
See accompanying notes to consolidated financial statements.
3
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, 2003 December 31, 2002
------------------------ ------------------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 51,681,138 $ 43,028,708
Payable to associated limited partnerships 514,309 91,126
Undistributed oil and gas revenues 5,527,236 3,764,350
------------------------ ------------------------
Total Current Liabilities 57,722,683 46,884,184
------------------------ ------------------------
Long-Term Debt 336,233,381 324,271,973
Deferred Income Taxes 39,248,246 30,776,518
Asset Retirement Obligation 9,834,695 ---
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000
shares authorized, none outstanding --- ---
Common stock, $.01 par value, 85,000,000
shares authorized, 27,968,640 and 27,811,632
shares issued, and 27,441,622 and 27,201,509
shares outstanding, respectively 279,686 278,116
Additional paid-in capital 334,418,690 333,543,471
Treasury stock held, at cost, 527,018 and
610,123 shares, respectively (7,558,093) (8,749,922)
Retained earnings 60,571,708 40,179,572
Other comprehensive loss, net of taxes (114,040) (178,053)
------------------------ ------------------------
387,597,951 365,073,184
------------------------ ------------------------
$ 830,636,956 $ 767,005,859
======================== ========================
See accompanying notes to consolidated financial statements.
4
SWIFT ENERGY COMPANY
Consolidated Statements of Income
(UNAUDITED)
Three months ended Nine months ended
------------------------------ ---------------------------------
09/30/03 09/30/02 09/30/03 09/30/02
-------------- ------------- ---------------- --------------
Revenues:
Oil and gas sales $ 52,087,321 $ 36,592,329 $ 157,846,870 $ 101,536,512
Fees from limited partnerships
and joint ventures 5,577 5,830 20,512 59,953
Interest income 26,279 158,664 136,747 190,957
Gain on asset disposition --- --- --- 7,332,668
Price-risk management and other, net (566,655) (186,014) (2,234,085) 375,065
-------------- ------------- ---------------- --------------
51,552,522 36,570,809 155,770,044 109,495,155
-------------- ------------- ---------------- --------------
Costs and Expenses:
General and administrative, net 3,670,416 2,497,413 10,564,959 7,368,989
Depreciation, depletion and amortization 16,042,377 13,487,437 46,630,689 41,789,711
Accretion of asset retirement obligation 206,475 --- 623,761 ---
Oil and gas production 13,730,467 11,004,641 39,392,531 30,602,493
Interest expense, net 6,749,419 6,647,968 20,107,188 16,607,651
-------------- ------------- ---------------- --------------
40,399,154 33,637,459 117,319,128 96,368,844
-------------- ------------- ---------------- --------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle 11,153,368 2,933,350 38,450,916 13,126,311
Provision for Income Taxes 4,090,743 986,344 13,681,928 4,575,403
-------------- ------------- ---------------- --------------
Income Before Cumulative Effect of Change
in Accounting Principle 7,062,625 1,947,006 24,768,988 8,550,908
Cumulative Effect of Change in Accounting
Principle (net of taxes) --- --- 4,376,852 ---
-------------- ------------- ---------------- --------------
Net Income $ 7,062,625 $ 1,947,006 $ 20,392,136 $ 8,550,908
============== ============= ================ ==============
Per share amounts -
Basic: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.26 $ 0.07 $ 0.91 $ 0.33
Cumulative Effect of Change in
Accounting Principle --- --- (0.16) ---
-------------- ------------- ---------------- --------------
Net Income $ 0.26 $ 0.07 $ 0.75 $ 0.33
============== ============= ================ ==============
Diluted: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.26 $ 0.07 $ 0.90 $ 0.32
Cumulative Effect of Change in
Accounting Principle --- --- (0.16) ---
-------------- ------------- ---------------- --------------
Net Income $ 0.26 $ 0.07 $ 0.74 $ 0.32
============== ============= ================ ==============
Weighted Average Shares Outstanding 27,424,195 26,889,186 27,326,169 26,112,382
============== ============= ================ ==============
See accompanying notes to consolidated financial statements.
5
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Accumulated
Additional Other
Common Paid-in Treasury Retained Comprehensive
Stock (1) Capital Stock Earnings Loss Total
---------- -------------- ------------- -------------- --------------- --------------
Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ 28,256,345 $ - $ 312,652,720
Stock issued for benefit plans
(38,149 shares) 292 617,960 127,795 - - 746,047
Stock options exercised
(112,995 shares) 1,130 1,206,413 - - - 1,207,543
Public stock offering
(1,725,000 shares) 17,250 30,465,809 - - - 30,483,059
Employee stock purchase plan
(9,801 shares) 98 122,343 - - - 122,441
Stock issued in acquisitions
(520,000 shares) 3,000 4,958,126 3,155,074 - - 8,116,200
Comprehensive income:
Net income - - - 11,923,227 - 11,923,227
Change in fair value of
cash flow hedges, net of
income tax - - - - (178,053) (178,053)
--------------
Total comprehensive income - - - - - 11,745,174
---------- -------------- ------------- -------------- --------------- --------------
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) (2) 1 (408,178) 1,191,829 - - 783,652
Stock options exercised
(100,338 shares) (2) 1,003 869,450 - - - 870,453
Employee stock purchase plan
(56,574 shares) (2) 566 413,947 - - - 414,513
Comprehensive income:
Net income (2) - - - 20,392,136 - 20,392,136
Change in fair value of
cash flow hedges, net of
income tax (2) - - - - 64,013 64,013
--------------
Total comprehensive income (2) - - - - - 20,456,149
---------- -------------- ------------- -------------- --------------- --------------
Balance, September 30, 2003 (2) $ 279,686 $ 334,418,690 $ (7,558,093) $ 60,571,708 $ (114,040) $ 387,597,951
========== ============== ============= ============== =============== ==============
(1)$.01 par value
(2) Unaudited
See accompanying notes to consolidated financial statements.
6
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Period Ended September 30,
-----------------------------------------------
2003 2002
--------------------- --------------------
Cash Flows From Operating Activities:
Net income $ 20,392,136 $ 8,550,908
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 46,630,689 41,789,711
Accretion of asset retirement obligation 623,761 ---
Deferred income taxes 13,375,807 4,554,165
Gain on asset disposition --- (7,332,668)
Other 658,524 728,917
Change in assets and liabilities -
(Increase) decrease in accounts receivable, excluding
income taxes receivable (3,895,748) 1,263,553
Increase in accounts payable and accrued liabilities 1,860,038 5,539,810
Decrease in income taxes receivable --- 600,000
--------------------- --------------------
Net Cash Provided by Operating Activities 84,022,059 55,694,396
--------------------- --------------------
Cash Flows From Investing Activities:
Additions to property and equipment (101,510,935) (132,521,779)
Proceeds from the sale of property and equipment 3,839,714 11,525,547
Net cash distributed as operator of
oil and gas properties (989,176) (4,247,012)
Net cash received (distributed) as operator of partnerships
and joint ventures 471,957 (26,527,633)
Other (89,635) 68,388
--------------------- --------------------
Net Cash Used in Investing Activities (98,278,075) (151,702,489)
--------------------- --------------------
Cash Flows From Financing Activities:
Proceeds from long-term debt --- 200,000,000
Net proceeds from (payments of) bank borrowings 11,900,000 (129,500,000)
Net proceeds from issuances of common stock 1,218,224 31,330,384
Payments of debt issuance costs --- (6,257,428)
--------------------- --------------------
Net Cash Provided by Financing Activities 13,118,224 95,572,956
--------------------- --------------------
Net Decrease in Cash and Cash Equivalents (1,137,792) (435,137)
Cash and Cash Equivalents at Beginning of Period 3,816,107 2,149,086
--------------------- --------------------
Cash and Cash Equivalents at End of Period $ 2,678,315 $ 1,713,949
===================== ====================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized $ 17,825,296 $ 10,511,529
Cash paid during period for income taxes $ 306,121 $ 2,500
Non-cash investing activity:
Issuance of common stock in acquisitions $ --- $ 8,116,200
See accompanying notes to consolidated financial statements.
7
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
(1) GENERAL INFORMATION
The consolidated financial statements included herein have been
prepared by Swift Energy Company and are unaudited, except for the balance
sheet at December 31, 2002, which has been prepared from the audited
financial statements at that date. The financial statements reflect
necessary adjustments, all of which were of a recurring nature, and are in
the opinion of our management necessary for a fair presentation. Certain
information and footnote disclosures normally included in financial
statements prepared in accordance with accounting principles generally
accepted in the United States have been omitted pursuant to the rules and
regulations of the Securities and Exchange Commission. We believe that the
disclosures presented are adequate to allow the information presented not
to be misleading. The consolidated financial statements should be read in
conjunction with the audited financial statements and the notes thereto
included in the latest Form 10-K and Annual Report.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Oil and Gas Properties
We follow the "full-cost" method of accounting for oil and gas property
and equipment costs. Under this method of accounting, all productive and
nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Under the full-cost
method of accounting, such costs may be incurred both prior to and after
the acquisition of a property and include lease acquisitions, geological
and geophysical services, drilling, completion, and equipment. Internal
costs incurred that are directly identified with exploration, development,
and acquisition activities undertaken by us for our own account, and which
are not related to production, general corporate overhead or similar
activities, are also capitalized. Interest costs related to unproved
properties are also capitalized to unproved oil and gas properties.
Interest not capitalized and general and administrative costs related to
production and general overhead are expensed as incurred. Our interests in
oil and gas properties and partnerships are proportionately consolidated.
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 (net of salvage value)-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. 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.
8
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
The cost of unproved properties not being amortized is assessed
quarterly, on a country-by-country basis, to determine whether such
properties have been impaired. In determining whether such costs should be
impaired, we evaluate current drilling results, lease expiration dates,
current oil and gas industry conditions, international economic conditions,
capital availability, foreign currency exchange rates, the political
stability in the countries in which we have an investment, and available
geological and geophysical information. Any impairment assessed is added to
the cost of proved properties being amortized. To the extent costs
accumulate in countries where there are no proved reserves, any costs
determined by management to be impaired are charged to expense.
Full-Cost Ceiling Test. At the end of each quarterly reporting period,
the unamortized cost of oil and gas properties, including gas processing
facilities and capitalized asset retirement obligations, net of related
salvage values and deferred income taxes, is limited to the sum of the
estimated future net revenues from proved properties using hedge adjusted
period-end prices, discounted at 10%, and the lower of cost or fair value
of unproved properties, adjusted for related income tax effects ("Ceiling
Test"). This calculation is done on a country-by-country basis for those
countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There
are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production, timing, and plan
of development. The accuracy of any reserves estimate is a function of the
quality of available data and of engineering and geological interpretation
and judgment. Results of drilling, testing, and production subsequent to
the date of the estimate may justify revision of such estimate.
Accordingly, reserves estimates are often different from the quantities of
oil and gas that are ultimately recovered.
Given the volatility of oil and gas prices, it is reasonably possible
that our estimate of discounted future net cash flows from proved oil and
gas reserves could change in the near term. If oil and gas prices decline
from our period-end prices used in the Ceiling Test, even if only for a
short period, it is possible that additional non-cash write-downs of oil
and gas properties could occur in the future.
Accounts Receivable
Included in the total "Accounts receivable" balance, which totaled
$24.9 million at September 30, 2003 on the accompanying balance sheet, was
approximately $2.3 million of receivables related to disputed volumes
produced from 2001 and 2002. Due to this dispute, we have not recorded a
receivable to date with regard to 2003 volumes.
We assess the collectibility of trade and other receivables. Based on
our judgment, we would accrue a reserve when we believe a receivable may
not be collected. At September 30, 2003 and December 31, 2002, we had an
allowance for doubtful accounts of $771,354 and $291,136, respectively.
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.
9
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. Diluted earnings per share ("Diluted EPS") for all periods also
assume, as of the beginning of the period, exercise of stock options using
the treasury stock method. 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, 2003 and 2002:
Three Months Ended September 30,
--------------------------------------------------------------------------------
2003 2002
-------------------------------------- ---------------------------------------
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 $ 7,062,625 27,424,195 $ .26 $ 1,947,006 26,889,186 $ .07
Stock Options --- 259,246 --- 242,283
------------- ----------- ------------- -----------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 7,062,625 27,683,441 $ .26 $ 1,947,006 27,131,469 $ .07
------------- ----------- -------------- -----------
Nine Months Ended September 30,
--------------------------------------------------------------------------------
2003 2002
-------------------------------------- ---------------------------------------
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 $ 24,768,988 27,326,169 $ .91 $ 8,550,908 $26,112,382 $ .33
Stock Options --- 147,158 --- 368,786
-------------- ----------- ------------ ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 24,768,988 27,473,327 $ .90 $ 8,550,908 $26,481,168 $ .32
------------- ----------- ------------ -----------
Options to purchase approximately 2.9 million shares of common stock,
at an average exercise price of $16.61 were outstanding at September 30,
2003. Approximately 1.3 million and 1.6 million options to purchase shares
were not included in the computation of Diluted EPS, for the three months
and nine months ended September 30, 2003, because the options were
antidilutive in that the option price was greater than the average closing
market price of the common shares during those periods.
10
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Other Comprehensive Loss
We follow the provisions of SFAS No. 130 "Reporting Comprehensive
Income," which establishes standards for reporting comprehensive income. In
addition to net income, comprehensive income or loss includes all changes
to equity during a period, except those resulting from investments and
distributions to the owners of the Company. At September 30, 2003, we
recorded $178,188, net of taxes of $64,148, 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
months ended September 30, 2003 were as follows:
Gross Value Tax Effect Net of Tax Value
---------------- --------------- ----------------
Balance at December 31, 2002 $ 278,208 $ 100,155 $ 178,053
Change in fair value of cash flow hedges 1,891,210 680,836 1,210,374
Effect of cash flow hedges settled
during the period (1,991,230) (716,843) (1,274,387)
---------------- --------------- ----------------
Balance at September 30, 2003 $ 178,188 $ 64,148 $ 114,040
================ =============== ================
Total comprehensive income was $7.3 million and $1.8 million for the
third quarters of 2003 and 2002. For the nine-month periods ended September
30, 2003 and 2002, total comprehensive income was $20.5 million and $8.4
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. Had compensation
expense for these plans been determined based on the fair value of the
options using the Black-Scholes option pricing model, and 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,
-----------------------------------------------
2003 2002
--------------------- -------------------
Net Income: As Reported $7,062,625 $1,947,006
Stock-based employee compensation expense
determined under fair value method
for all awards, net of tax (1,024,734) (1,110,573)
--------------------- -------------------
Pro Forma $6,037,891 $836,433
Basic EPS: As Reported $.26 $.07
Pro Forma $.22 $.03
Diluted EPS: As Reported $.26 $.07
Pro Forma $.22 $.03
11
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Nine Months Ended September 30,
-------------------------------------------------
2003 2002
---------------------- -------------------
Net Income: As Reported $20,392,136 $8,550,908
Stock-based employee compensation expense
determined under fair value method fo
all awards, net of tax (3,048,052) (3,321,059)
---------------------- -------------------
Pro Forma $17,344,084 $5,229,849
Basic EPS: As Reported $.75 $.33
Pro Forma $.63 $.20
Diluted EPS: As Reported $.74 $.32
Pro Forma $.63 $.20
Pro forma compensation cost reflected above may not be representative
of the cost to be expected in future periods.
Price-Risk Management Activities
We follow SFAS No. 133, which requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. The statement also establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in
the balance sheet as either an asset or a liability measured at its fair
value. Special hedge accounting for qualifying hedges would allow the gains
and losses on derivatives to offset related results on the hedged item in
the consolidated statements of income and would require that a company
formally document, designate, and assess the effectiveness of transactions
that receive hedge accounting.
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 protection price floors and collars. During the third quarters of 2003
and 2002, we recognized net losses of $598,766 and $181,595, respectively,
relating to our derivative activities. During the first nine months of 2003
and 2002 we recognized net losses of $2,399,435 and $201,474, respectively,
relating to our derivative activities. Approximately $5,789 and $162,727 of
the losses recognized in the 2003 and 2002 periods, respectively, were
unrealized, as the contracts were still open. This activity is recorded in
"Price-risk management and other, net" on the accompanying statements of
income. At September 30, 2003, we had recorded $178,188 of derivative
losses, net of tax effects of $64,148, 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 2003 was 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, 2003, we had in place price floors in effect
through the December 2003 contract month for natural gas and through
November 2003 for crude oil. The natural gas price floors cover notional
volumes of 1,050,000 MMBtu with a weighted average floor price of $4.75 per
MMBtu. The crude oil price floors cover notional volumes of 180,000 barrels
of oil, with a weighted average floor price of $27.58 per barrel. When we
entered into the preceding transactions, with the exception of several
November natural gas floors, they were designated as a hedge of the
variability in cash flows associated with the forecasted sale of our oil
and natural gas production. Changes in the fair value of a hedge that is
highly effective and is designated and qualifies as a cash flow hedge, to
the extent that the hedge is effective, are initially recorded in
12
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Other Comprehensive Income (Loss). When the hedged transactions are
recorded upon the actual sale of oil and natural gas, these gains or losses
are transferred from "Other comprehensive income (loss) and recorded in
"Price-risk management and other, net" on the consolidated statement of
income. Several of our November contract month natural gas floors became
ineffective, as accounted for under special hedge accounting treatment,
during the second quarter of 2003. These natural gas floors have been
marked to market each period with any gain or loss recorded in "Price-risk
management and other, net" on the consolidated statement of income. The
fair value of our derivatives are computed using the Black-Scholes option
pricing model and are periodically verified against quotes from brokers. At
September 30, 2003, the fair values of the derivative instruments were as
follows: gas price floors represented an asset of $322,080 and crude oil
price floors represented an asset of $95,899. These instruments are
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.
Over time, accretion of the liability is recognized each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Upon settlement of the liability, an entity either settles the obligation
for its recorded amount or incurs a gain or loss upon settlement. This
standard requires us to record a liability for the fair value of our
dismantlement and abandonment costs, excluding salvage values. SFAS No. 143
was adopted by us effective January 1, 2003. Upon adoption of SFAS No. 143
effective January 1, 2003, we recorded an asset retirement obligation of
$8.9 million, an addition to oil and gas properties of $2.0 million and a
non-cash charge of $4.4 million (net of $2.5 million of deferred taxes),
which is recorded as a Cumulative Effect of Change in Accounting Principle.
The following provides a roll-forward of our asset retirement obligation:
Asset Retirement Obligation recorded as of January 1, 2003 $ 8,934,320
Accretion expense for the nine months ended September 30, 2003 623,761
Additions due to new wells and facilities construction 546,350
Reductions due to sold and abandoned wells (332,327)
Increase due to currency exchange rate fluctuations 62,591
----------------
Asset Retirement Obligation as of September 30, 2003 $ 9,834,695
----------------
The pro forma effect on the first quarter of 2002, assuming adoption of
SFAS No. 143 effective January 1, 2002, would have included a non-cash
charge of $3.7 million (net of $2.1 million of deferred taxes), which would
have been recorded as a Cumulative Effect of Change in Accounting
Principle. The following table displays our pro forma results for the three
and nine months ended September 30, 2002, had we adopted SFAS No. 143
effective January 1, 2002.
13
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
------------------- ---------------------
Net Income:
Actual - as reported $ 1,947,006 $ 8,550,908
Pro Forma $ 1,841,047 $ 4,520,396
Basic EPS:
Actual - as reported $ .07 $ .33
Pro Forma $ .07 $ .17
Diluted EPS:
Actual - as reported $ .07 $ .32
Pro Forma $ .07 $ .17
New Accounting Principles
In January 2003, the FASB issued Interpretation No. 46 "Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research
Bulletin No. 51" (the "Interpretation"). The Interpretation will
significantly change 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. These provisions apply immediately to variable interests in
VI's created after January 15, 2003 and are effective for periods ending
after December 15, 2003 for VIE's in which the Company holds a variable
interest that it acquired prior to February 1, 2003. The Company is still
evaluating the impact of this new interpretation.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity."
This statement sets standards for classifying and measuring certain
financial instruments with characteristics of both liabilities and equity.
This statement is effective for periods ending after December 15, 2003. The
Company is still evaluating the impact of this new interpretation.
The Securities and Exchange Commission ("SEC") commented that acquired
oil and gas drilling rights should be classified as an intangible asset
pursuant to FASB No. 142 "Goodwill and Other Intangible Assets." The SEC
has not required companies to apply this classification and we classify the
costs of oil and gas drilling rights as property and equipment. The
Emerging Issues Task Force, a subset of FASB, will address this issue at a
later date. If the SEC's comment on this issue is adopted in the future, we
may be required to reclassify these costs from property and equipment to
intangible assets on our balance sheet.
14
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
(3) LONG-TERM DEBT
Our long-term debt as of September 30, 2003 and December 31, 2002, is
as follows:
September 30, December 31,
2003 2002
------------------ -------------------
Bank Borrowings $ 11,900,000 $ ---
Senior Notes due 2009 124,333,381 124,271,973
Senior Notes due 2012 200,000,000 200,000,000
------------------ -------------------
Long-Term Debt $ 336,233,381 $ 324,271,973
------------------ -------------------
The unamortized discount on the Senior Notes due 2009 was $666,619 and
$728,027 at September 30, 2003 and December 31, 2002, respectively.
Bank Borrowings
Under our $300.0 million credit facility with a syndicate of ten banks,
at September 30, 2003 we had $11.9 million in outstanding borrowings and no
outstanding borrowings at year-end 2002. At September 30, 2003, the credit
facility consisted of a $300.0 million secured revolving line of credit
with a $150.0 million commitment amount. The interest rate is either (a)
the lead bank's prime rate (4% at September 30, 2003) or (b) the adjusted
London Interbank Offered Rate ("LIBOR") plus the applicable margin
depending on the level of outstanding debt. The applicable margin is based
on the ratio of the outstanding balance to the last calculated borrowing
base. Of the $11.9 million borrowed at September 30, 2003, $5.0 million was
borrowed at the LIBOR rate plus applicable margin, which was 2.37%. Our
credit facility extends until October 1, 2005.
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 Company
stock of $15.0 million, requirements as to maintenance of certain minimum
financial ratios (principally pertaining to working capital, debt, and
equity ratios), and limitations on incurring other debt or repurchasing our
existing Senior Notes. Since inception, no cash dividends have been
declared on our common stock. We are currently in compliance with the
provisions of this agreement. The credit facility is secured by our
domestic oil and gas properties. We have also pledged 65% of the stock in
our two active New Zealand subsidiaries as collateral for this credit
facility. The borrowing base is re-determined at least every six months and
was recently reconfirmed by our bank group and increased to $250.0 million
effective November 1, 2003, an increase of $55.0 million from the previous
level of $195.0 million. We previously 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 2004.
15
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Senior Notes Due 2009
At September 30, 2003, our Senior Notes due 2009 consisted of $125.0
million of 10.25% Senior Subordinated Notes due 2009. These Senior Notes
were issued at 99.236% of the principal amount on August 4, 1999, and will
mature on August 1, 2009. The notes are unsecured senior subordinated
obligations and are subordinated in right of payment to all our existing
and future senior debt, including our bank debt. Interest on these Senior
Notes is payable semiannually on February 1 and August 1. On or after
August 1, 2004, these notes are redeemable for cash at the option of Swift,
with certain restrictions, at 105.125% of principal, declining to 100% in
2007. Upon certain changes in control of Swift, each holder of these notes
will have the right to require Swift to repurchase the notes at a purchase
price in cash equal to 101% of the principal amount, plus accrued and
unpaid interest to the date of purchase. The terms of these Senior Notes
include, among other restrictions, a limit on repurchases by Swift of its
common stock. We are currently in compliance with the provisions of the
indenture governing the these notes.
Senior Notes Due 2012
At September 30, 2003, our Senior Notes due 2012 consisted of $200.0
million of 9.375% Senior Subordinated Notes due 2012. These Senior Notes
were issued at 100% of the principal amount on April 11, 2002, and will
mature on May 1, 2012. The notes are unsecured senior subordinated
obligations and are subordinated in right of payment to all our existing
and future senior debt, including our bank debt. Interest on these Senior
Notes is payable semiannually on May 1 and November 1. On or after May 1,
2007, these notes are redeemable for cash at the option of Swift, with
certain restrictions, at 104.688% of principal, declining to 100% in 2010.
In addition, prior to May 1, 2005, we may redeem up to 33.33% of the Senior
Notes with the proceeds of qualified offerings of our equity at 109.375% of
the principal amount of these notes, together with accrued and unpaid
interest. Upon certain changes in control of Swift, each holder of Senior
Notes will have the right to require Swift to repurchase the 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 our these Senior
Notes include, among other restrictions, a limit on repurchases by Swift of
its common stock. We are currently in compliance with the provisions of the
indenture governing these notes.
(4) STOCKHOLDERS' EQUITY
In March 2002, we issued 220,000 shares of our common stock, along with
cash consideration as an effective date adjustment, to acquire all of the
New Zealand assets of Antrim Oil and Gas Limited ("Antrim"). At the time,
these 220,000 shares, with a fair market value of $4.2 million, were issued
out of treasury shares, and resulted in an increase to paid-in capital of
$1.0 million and a decrease in the value of our treasury shares of $3.2
million. In April 2002, we issued 1,725,000 shares of common stock in a
public offering, at a price of $18.25 per share. Gross proceeds from this
offering were $31,481,250, with issuance costs of $998,191. In September
2002, we issued 300,000 shares of our common stock with a fair market value
of $3.9 million, along with $2.7 million in cash, to acquire the interests
owned by Bligh Oil and Minerals N.L. ("Bligh") in the Swift operated
Rimu/Kauri and TAWN permits, mining licenses and facilities in New Zealand.
(5) FOREIGN ACTIVITIES
As of September 30, 2003, our gross capitalized oil and gas property
costs in New Zealand totaled approximately $200.1 million. Approximately
$166.0 million has been included in the proved properties portion of our
oil and gas properties, while $34.1 million is included as unproved
properties. Our functional currency in New Zealand is the U.S. dollar.
16
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
(6) SEGMENT INFORMATION
Below is a summary of financial information by country:
Three Months Ended September 30,
----------------------------------------------------------------------------------------------
2003 2002
-------------------------------------------- ---------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- -------------- ------------- ------------- ------------- -------------
Oil and gas sales $ 39,974,435 $ 12,112,886 $ 52,087,321 $ 28,454,804 $ 8,137,525 $ 36,592,329
Costs and Expenses:
Depreciation, depletion and
amortization 11,645,480 4,396,897 16,042,377 10,196,179 3,291,258 13,487,437
Accretion of asset retirement
obligation 151,188 55,287 206,475 --- --- ---
Oil and gas production 10,260,211 3,470,256 13,730,467 8,444,530 2,560,111 11,004,641
------------- -------------- ------------- ------------- ------------- ------------
Income from oil and gas operations $ 17,917,556 $ 4,190,446 $ 22,108,002 $ 9,814,095 $ 2,286,156 $ 12,100,251
Other revenues (1) (534,799) (21,520)
General and administrative, net 3,670,416 2,497,413
Interest expense, net 6,749,419 6,647,968
Income before income taxes and
Cumulative Effect of Change in
Accounting Principle $ 11,153,368 $ 2,933,350
============= =============
Nine Months Ended September 30,
---------------------------------------------------------------------------------------------
2003 2002
-------------------------------------------- --------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- -------------- ------------- ------------- ------------- -------------
Oil and gas sales $ 123,693,311 $ 34,153,559 $ 157,846,870 $ 82,202,092 $ 19,334,420 $ 101,536,512
Costs and Expenses:
Depreciation, depletion and
amortization 32,508,198 14,122,491 46,630,689 34,210,133 7,579,578 41,789,711
Accretion of asset retirement
obligation 448,711 175,050 623,761 --- --- ---
Oil and gas production 29,532,116 9,860,415 39,392,531 25,141,686 5,460,807 30,602,493
------------- -------------- ------------- ------------- ------------- -------------
Income from oil and gas operations $ 61,204,286 $ 9,995,603 $ 71,199,889 $ 22,850,273 $ 6,294,035 $ 29,144,308
Other revenues (1) (2,076,826) 7,958,643
General and administrative, net 10,564,959 7,368,989
Interest expense, net 20,107,188 16,607,651
Income before income taxes and
Cumulative Effect of Change in
Accounting Principle $ 38,450,916 $ 13,126,311
============= =============
Property, Plant and Equipment, net $ 616,251,046 $ 173,419,123 $ 789,670,169 $ 551,583,952 $ 158,976,243 $ 710,560,195
============= ============== ============= ============= ============= =============
(1) Other revenues consist of Fees from limited partnerships and joint ventures,
Interest income, Gain on asset disposition and Price-risk management and other,
net on the accompanying consolidated statements of income.
17
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
(7) ACQUISITIONS AND DISPOSITIONS
New Zealand. Through our subsidiary, Swift Energy New Zealand Limited
("SENZ"), we acquired Southern Petroleum (NZ) Exploration Limited
("Southern NZ") in January 2002 for approximately $51.4 million in cash. We
allocated $36.1 million of the acquisition price to "Proved properties,"
$10.0 million to "Unproved properties," $4.9 million to "Deferred income
taxes" and $0.4 million to "Other current assets" on our Consolidated
Balance Sheet. Southern NZ was an affiliate of Shell New Zealand and owns
interests in four onshore producing oil and gas fields, hydrocarbon
processing facilities, and pipelines connecting the fields and facilities
to export terminals and markets. This acquisition was accounted for by the
purchase method of accounting.
In March 2002, we purchased through our subsidiary, SENZ, all of the
New Zealand assets owned by Antrim for 220,000 shares of Swift Energy
Company common stock valued at $4.2 million with an effective date
adjustment of approximately $0.5 million for total consideration of $4.7
million.
In September 2002, we purchased through our subsidiary, SENZ, Bligh's
5% working interest in permit 38719 and 5% interest in the Rimu petroleum
mining permit 38151, along with its 3.24% working interest in the four TAWN
petroleum mining licenses, for 300,000 shares of Swift Energy Company
common stock valued at $3.9 million, along with $2.7 million in cash for
total consideration of $6.6 million.
Russia. In 1993, we entered into a Participation Agreement with Senega,
a Russian Federation joint stock company, to assist in the development and
production of reserves from two fields in western Siberia and received a 5%
net profits interest. We also purchased a 1% net profits interest. Our
investment in Russia was fully impaired in the third quarter of 1998. In
March 2002, we received $7.5 million for our investment in Russia. Although
the proceeds from sales of oil and gas properties are generally treated as
a reduction of oil and gas property costs, because we had previously
charged to expense all $10.8 million of cumulative costs relating to our
Russian activities, this cash payment, net of transaction expenses,
resulted in recognition of a $7.3 million non-recurring gain on asset
disposition in the first quarter of 2002.
18
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Over the last several years, we have emphasized adding reserves through
drilling activity, while adding reserves through strategic purchases of
producing properties when oil and gas prices were at lower levels and other
market conditions were appropriate. We used this flexible strategy of
employing both drilling and acquisitions to add more reserves than we
depleted through production during such period.
CONTRACTUAL COMMITMENTS AND OBLIGATIONS
Our contractual commitments for the remainder of 2003 and the next four
years and thereafter as of September 30, 2003 are as follows:
2003 2004 2005 2006 2007 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
Non-cancelable operating lease
commitments $ 547,591 $ 2,191,495 $ 523,755 $ 190,676 $ 190,676 $ 186,834 $ 3,831,027
Capital commitments due to
pipeline operators 400,426 -- -- -- -- -- 400,426
Asset Retirement Obligation (1) 1,068,558 651,679 -- 3,441,209 300,079 4,373,170 9,834,695
Drilling Rig Commitments 2,535,000 -- -- -- -- -- 2,535,000
Senior Notes due 2009 (2) -- -- -- -- -- 125,000,000 125,000,000
Senior Notes due 2012 (2) -- -- -- -- -- 200,000,000 200,000,000
Credit Facility which expires in
October 2005 (3) -- -- 11,900,000 -- -- -- 11,900,000
----------- ------------ ------------- ----------- ---------- ------------- -------------
$ 4,551,575 $ 2,843,174 $ 12,423,755 $ 3,631,885 $ 490,755 $ 329,560,004 $ 353,501,148
=========== ============ ============= =========== ========== ============= =============
(1)Amounts shown by year are the net present value, discounted to September 30,
2003.
(2)These amounts do not include the interest obligation, which is paid
semiannually.
(3)These amounts exclude a $0.8 million standby letter of credit outstanding
under this facility.
COMMODITY PRICE TRENDS AND UNCERTAINTIES
Oiland natural gas prices historically have been volatile and are
expected to continue to be volatile in the future. Worldwide supply
disruptions, such as the reduction in crude oil production from Venezuela,
together with perceived risks associated with the war between the United
States and Iraq, along with other factors, have caused the price of oil to
increase significantly in the first nine months of 2003 when compared to
historical prices. Other factors such as actions taken by OPEC, worldwide
economic conditions, and weather conditions can cause wide fluctuations in
the price of oil. Natural gas prices increased significantly in the first
quarter of 2003 when compared to historical prices, and have since declined
somewhat. North American weather conditions, the industrial and consumer
demand for natural gas, storage levels of natural gas, and the availability
and accessibility of natural gas deposits in North America can cause wide
fluctuations in the price of natural gas. All of such factors are beyond
our control.
19
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 2003, we largely relied upon our net
cash provided by operating activities of $84.0 million and proceeds from
bank borrowings of $11.9 million to fund capital expenditures of $101.5
million. During the first nine months of 2002, we principally relied upon
our net cash provided by operating activities of $55.7 million, net
proceeds from the public issuance of long-term debt of $195.0 million and
net proceeds of our public stock offering of $30.5 million, less the
repayment of bank borrowings of $129.5 million, to fund capital
expenditures of $132.5 million.
Net Cash Provided by Operating Activities. For the first nine months of
2003, net cash provided by our operating activities was $84.0 million,
representing a 51% increase as compared to $55.7 million generated during
the first nine months of 2002. The $28.3 million increase was primarily due
to an increase of $56.3 million in oil and gas sales for the first nine
months of 2003, attributable to higher commodity prices and production,
offset in part by production cost increases due to significant Lake
Washington facility enhancements and workovers, along with scheduled plant
shutdowns for maintenance in New Zealand and an increase in interest
expense attributed to the replacement of our bank borrowings in April 2002
with the Senior Notes due 2012 that carry a higher interest rate and a
longer term.
Accounts Receivable. In early 2003, a dispute arose with a third party
regarding the level of volumes we produced and delivered through a
gathering system covered by a production handling agreement. Outside audits
were conducted related to these volumes produced and delivered to such
third party during 2001, 2002 and a portion of 2003. As a result of these
audits, we have made claim for payment of additional volumes produced
during those periods. Included in the accompanying consolidated balance
sheet is approximately $2.3 million of receivables related to these
disputed volumes produced in 2001 and 2002. Due to this dispute, we have
not recorded a receivable to date with regard to 2003 volumes. We believe
that we will prevail in this dispute and currently anticipate mediation,
arbitration or legal action to resolve this claim.
Existing Credit Facility. We had $11.9 million in outstanding
borrowings under our credit facility at September 30, 2003, and no
outstanding borrowings at December 31, 2002. At September 30, 2003, our
credit facility consisted of a $300.0 million revolving line of credit with
a $150.0 million commitment amount. The borrowing base is re-determined at
least every six months and was recently reconfirmed by our bank group and
increased to $250.0 million, effective November 1, 2003, an increase of
$55.0 million from the previous level of $195.0 million. We previously
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. Our revolving credit facility
includes, among other restrictions, requirements as to maintenance of
certain minimum financial ratios (principally pertaining to working
capital, debt, and equity ratios), and limitations on incurring other debt.
We are in compliance with the provisions of this agreement.
Debt Maturities. Our credit facility extends until October 1, 2005. Our
$125.0 million Senior Notes mature August 1, 2009 and our $200.0 million
Senior Notes mature May 1, 2012.
Working Capital. Our working capital decreased from a deficit of $17.1
million at December 31, 2002, to a deficit of $25.5 million at September
30, 2003. The decrease was primarily due to an increase in accrued
liabilities due to our drilling activities in the first nine months of
2003.
Capital Expenditures. During the first nine months of 2003, we used
$101.5 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
Domestic activities of $77.3 million as follows:
o $53.6 million for drilling costs, both development and exploratory;
20
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
o $14.2 million for the construction of production and surface
facilities, mainly in our Lake Washington area.
o $7.6 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $1.5 million of producing property acquisitions; and
o $0.4 million primarily for computer equipment, software, furniture,
and fixtures.
New Zealand activities of $24.2 million as follows:
o $14.7 million for drilling costs, both development and exploratory;
o $4.8 million on prospect costs, principally seismic and geological
costs;
o $4.2 million for the construction of production facilities and
pipelines;
o $0.3 million for property acquisitions; and
o $0.2 million for fixed assets.
We have spent considerable time and capital in 2003 on significant
facility capacity upgrades in the Lake Washington field to increase
facility capacity to more than 20,000 barrels per day ('b/d') for crude oil
up from 9,000 b/d capacity in the first quarter 2003. Facility upgrades,
most of which have been recently completed, and the commissioning of these
upgrades, have led to numerous planned production shut-in periods during
the third and fourth quarters of 2003. We have upgraded three production
platforms, added new compression for the gas lift system, and installed a
new oil delivery system and permanent barge loading facility.
We drilled or participated in drilling 48 domestic development wells
and seven domestic exploratory wells in the first nine months of 2003, 42
of the development wells and five exploratory wells were in the Lake
Washington area. Five domestic exploratory wells and 40 of the domestic
development wells were completed. In New Zealand, the Kauri-E1, Kauri-E2
and Kauri-F1 were completed, while the Kauri-A4 began producing into the
Rimu Production Station (RPS). The re-entry of the Tuihu exploration well
was plugged and abandoned in October 2003.
For the remaining three months of 2003, we expect to make capital
expenditures of approximately $48 to $55 million (depending on the level
and costs of actual drilling activities and on commodity prices). We
anticipate that our fourth quarter 2003's internally generated cash flows
together with our available bank borrowings, will be sufficient to finance
our remaining 2003 capital expenditures. We currently estimate total
capital expenditures for 2003 to be approximately $150 to $157 million.
Capital expenditures for 2002 were $155.2 million.
During the last three months of 2003, we anticipate drilling or
participating in the drilling of up to an additional 23 domestic wells,
with an emphasis in the Lake Washington area while undertaking activity in
our Brookeland, Masters Creek and South Texas areas again. Our capital
projects also include facility upgrades and planning for our 3-D seismic
work in Lake Washington. In addition, we plan on drilling an additional
well in New Zealand.
Our 2003 capital expenditures continue to be focused on developing and
producing long-lived oil reserves in Lake Washington and in the Rimu/Kauri
area in New Zealand. With this focus, we expect our 2003 total
21
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
production to increase by 7% to 9% over 2002 levels primarily from the Lake
Washington and TAWN areas, while we expect production in our other core
areas to decrease as limited new drilling is currently budgeted to offset
the natural production decline of these properties. This drilling focus
should help add long-lived oil reserves and should help develop an overall
lesser production decline curve, which would extend our average reserve
life and emphasize the balancing of our reserves between oil and gas.
We currently anticipate that our capital expenditures for 2004 will
range between $150 and $170 million. Depending on a number of factors, such
as commodity pricing, production levels, and the level and success of
planned non-core property dispositions, our internally generated cash flows
are expected to fund a majority of these expenditures. Although current
plans do not call for extensive use of our bank credit facility in 2004, we
believe that our recently increased bank borrowing base will continue to
stay at or near its current level, as our proved reserve base continues to
grow. If oil and gas prices were to drop precipitously on a sustained
basis, it would negatively affect our liquidity and cash flows, including
our ability to stay in compliance with certain financial covenants under
our credit facility. We would reduce the level of our capital expenditures
in response to any such precipitous drop in prices, as we would deem
necessary.
RESULTS OF OPERATIONS - Three Months Ended September 30, 2003 and 2002
Revenues. Our revenues in the third quarter of 2003 increased by 41% to
$51.6 million compared to revenues of $36.6 million in the same period in
2002, primarily due to increases in oil and gas prices and our increased
production.
Oil and gas sales revenues of $52.1 million in the third quarter of
2003 increased by 42%, or $15.5 million, from the level of those revenues
for the comparable 2002 period. Our net sales volumes of 13.6 Bcfe in the
third quarter of 2003 increased by 12%, or 1.4 Bcfe, over net sales volumes
in the comparable 2002 period. Average prices received for oil increased to
$29.24 per Bbl in the third quarter of 2003 from $26.17 per Bbl in the
comparable 2002 period. Average gas prices received increased to $3.17 per
Mcf in the third quarter of 2003 from $2.32 per Mcf in the 2002 period.
Average natural gas liquids (Ngl) prices increased to $16.81 per Bbl in the
third quarter of 2003 from $13.58 per Bbl in the comparable 2002 period.
The increase in production during the 2003 period was predominantly from
our Lake Washington and New Zealand areas.
In the third quarter of 2003, our $15.5 million increase in oil and gas
sales resulted from:
o Price variances that had a $9.8 million favorable impact on sales,
of which $5.7 million was attributable to the 37% increase in
average gas prices received and $4.1 million was attributable to the
15% increase in the average combined oil and Ngl prices received;
and
o Volume variances that had a $5.7 million favorable impact on sales,
with $5.9 million of the increase coming from the 256,000 Bbl
increase in oil and Ngl sales volumes, offset by a $0.2 million
decrease coming from the 0.1 Bcf decrease in gas sales volumes.
22
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our
domestic core areas and New Zealand:
Three Months Ended September 30,
--------------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- --------------------------------------- ----------------------------------
2003 2002 2003 2002
---- ---- ---- ----
AWP Olmos $ 10.5 $ 7.9 2.3 2.8
Brookeland 3.9 3.2 1.0 0.8
Lake Washington 16.6 5.2 3.5 1.2
Masters Creek 5.6 8.1 1.3 2.1
Other 3.4 4.1 0.6 1.2
--------------------- --------------- --------------- ----------------
Total Domestic $ 40.0 $28.5 8.7 8.1
--------------------- --------------- --------------- ----------------
Rimu/Kauri 3.5 1.4 1.0 0.7
TAWN 8.6 6.7 3.9 3.4
--------------------- --------------- --------------- ----------------
Total New Zealand $ 12.1 $ 8.1 4.9 4.1
--------------------- --------------- --------------- ----------------
Total $ 52.1 $36.6 13.6 12.2
===================== =============== =============== ================
Our drilling efforts in the third quarter of 2003 have focused on Lake
Washington, South Texas and New Zealand.
The following table provides additional information regarding our oil
and gas sales:
Net Sales Volume Average Sales Price
---------------- -------------------
Oil Ngl Gas Combined Oil Ngl Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
2002
- ----
Three Months Ended September 30:
Domestic 517 169 4.0 8.1 $26.95 $14.42 $3.06
New Zealand 166 56 2.8 4.1 $23.76 $11.03 $1.28
------- ------- -------- ---------
Total 683 225 6.8 12.2 $26.17 $13.58 $2.32
======= ======= ======== =========
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
======= ======= ======== =========
During the third quarter of 2003, we recognized net losses of $0.6
million relating to our hedging activities, as compared to net losses of
$0.2 million in the 2002 period. This activity is recorded in "Price-risk
management and other, net" on the accompanying consolidated statement of
income.
Revenues from our oil and gas sales comprised substantially all of net
revenues for the third quarters of 2003 and 2002. Natural gas production
made up 49% of our production volumes in the third quarter of 2003 and 55%
in the 2002 period.
Costs and Expenses. Our expenses in the third quarter of 2003 increased
$6.8 million, or 20%, compared to the 2002 period expenses. The majority of
this increase was due to our increased depletion expense and oil
23
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
and gas production costs, both domestically and in New Zealand.
Our net general and administrative expense in the third quarter of
2003, increased $1.2 million, or 47%, from the level of such expenses in
the comparable 2002 period. These increases reflect additional costs needed
to run our increased activities in New Zealand, an increase in franchise
tax expense, and increased costs related to our corporate governance
activities and compliance with the Sarbanes-Oxley Act. Our general and
administrative expenses per Mcfe produced increased to $0.27 per Mcfe in
the third quarter of 2003 from $0.20 per Mcfe in the comparable 2002
period. The portion of supervision fees netted from general and
administrative expenses was $0.8 million for the both the third quarters of
2003 and 2002.
Depreciation, depletion, and amortization of our assets, or DD&A,
increased $2.6 million, or 19%, in the third quarter of 2003 from the 2002
period. Domestically, DD&A increased $1.4 million due to increased
production in the 2003 period, offset somewhat by higher reserve volumes
that were added primarily through our Lake Washington activities. In New
Zealand, our production increased in the 2003 period in both the Rimu/Kauri
and TAWN areas, which increased DD&A in the third quarter 2003. Our DD&A
rate per Mcfe of production was $1.18 in the third quarter of 2003 and
$1.10 in the comparable 2002 period, reflecting these variations in per
unit cost of reserves additions.
We recorded $0.2 million of accretion on our asset retirement
obligation in the third quarter of 2003 associated with the adoption of
SFAS No. 143 implemented effective January 1, 2003.
Our production costs increased $2.7 million in the third quarter of
2003, or 25%, and were $1.01 and $0.90 per Mcfe in the third quarter of
2003 and 2002, respectively. Due to the 18% increase in production during
the third quarter of 2003, our New Zealand operations contributed $0.9
million of the cost increase in the period. Domestic severance taxes
increased $1.3 million in the third quarter of 2003, due to higher
commodity prices and production. The portion of supervision fees netted
from production costs was $0.5 million for the third quarters of 2003 and
2002.
Interest expense on our Senior Notes due 2009, including amortization
of debt issuance costs, totaled $3.3 million in both the third quarter of
2003 and 2002. Interest expense on our Senior Notes due 2012, including
amortization of debt issuance costs, totaled $4.8 million in the third
quarter of 2003 and $4.7 million in the third quarter of 2002. Interest
expense on our credit facility, including commitment fees and amortization
of debt issuance costs, totaled $0.3 million in the third quarter of 2003
and $0.4 million in the same period in 2002. The total interest cost in the
third quarter of 2003 was $8.4 million, of which $1.7 million was
capitalized. The total interest cost in the third quarter of 2002 was $8.4
million, of which $1.8 million was capitalized. We capitalize that portion
of interest related to our unproved properties.
Net Income. Our net income in the third quarter of 2003 of $7.1 million
was 263% higher and Basic EPS of $0.26 were 256% higher than our third
quarter of 2002 net income of $1.9 million and Basic EPS of $0.07. Our
Diluted EPS in the third quarter of 2003 of $0.26 were also 256% higher
than our third quarter of 2002 Diluted EPS of $0.07. These amounts
increased in the 2003 period as oil and gas sales increased due to higher
commodity prices and our increased production.
RESULTS OF OPERATIONS - Nine Months Ended September 30, 2003 and 2002
Revenues. Our revenues in the first nine months of 2003 increased by
42% to $155.8 million compared to revenues of $109.5 million in the same
period in 2002, primarily due to increases in oil and gas prices and, to a
lesser extent, our increased production.
Oil and gas sales revenues of $157.8 million in the first nine months
of 2003 increased by 55%, or $56.3 million, from the level of those
revenues for the comparable 2002 period. Our net sales volumes of 39.8 Bcfe
in the first nine months of 2003 increased by 7%, or 2.6 Bcfe, over net
sales volumes in the comparable 2002 period. Average prices received for
oil increased to $29.80 per Bbl in the first nine months of 2003 from
$26.50 per Bbl in the comparable 2002
24
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
period. Average gas prices received increased to $3.46 per Mcf in the first
nine months of 2003 from $2.21 per Mcf in the 2002 period. Average natural
gas liquids (Ngl) prices increased to $17.87 per Bbl in the first nine
months of 2003 from $11.77 per Bbl in the comparable 2002 period. The
increase in production during the 2003 period was from our Lake Washington
and New Zealand areas. Our domestic Ngl volumes decreased in the first nine
months of 2003, as it was more profitable to sell high Btu natural gas than
to strip out ethane and other Ngls from the gas stream.
In the first nine months of 2003, our $56.3 million increase in oil and
gas sales resulted from:
o Price variances that had a $49.2 million favorable impact on sales,
of which $26.8 million was attributable to the 56% increase in
average gas prices received and $22.4 million was attributable to
the 37% increase in the average combined oil and Ngl prices
received; and
o Volume variances that had a $7.1 million favorable impact on sales,
with $4.1 million of the increase coming from the 206,000 Bbl
increase in oil and Ngl sales volumes, and $3.0 million of the
increase coming from the 1.4 Bcf increase in gas sales volumes.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our
domestic core areas and New Zealand:
Nine Months Ended September 30,
-------------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- -------------------------------------- -----------------------------------
2003 2002 2003 2002
---- ---- ---- ----
AWP Olmos $34.6 $ 24.1 6.4 8.4
Brookeland 12.3 9.2 2.9 3.1
Lake Washington 40.4 12.1 8.3 3.1
Masters Creek 21.3 25.5 4.6 8.0
Other 15.0 11.3 2.8 4.0
-------------------- -------------- ---------------- ----------------
Total Domestic $ 123.6 $ 82.2 25.0 26.6
-------------------- -------------- ---------------- ----------------
Rimu/Kauri 6.8 2.5 2.0 1.0
TAWN 27.4 16.8 12.8 9.6
-------------------- -------------- ---------------- ----------------
Total New Zealand $ 34.2 $ 19.3 14.8 10.6
-------------------- -------------- ---------------- ----------------
Total $ 157.8 $101.5 39.8 37.2
==================== ============== ================ ================
Our drilling efforts in the first nine months of 2003 have focused on Lake
Washington, AWP Olmos and New Zealand. During 2003, our TAWN natural gas
production in New Zealand was materially higher than original expectations
due to increased natural gas demand in New Zealand and facility
modifications implemented by our New Zealand operations. As a result of
this increased production, which we believe peaked during the third quarter
of 2003, the depletion of our TAWN property during the first nine months of
2003 was at a higher rate than was seen during the comparable 2002 period,
and we expect a higher rate of depletion to continue. We also expect to
conduct future drilling operations to add new supply volumes and install
compression to improve deliverability and recovery of natural gas in the
TAWN area.
25
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
The following table provides additional information regarding our oil
and gas sales:
Net Sales Volume Average Sales Price
---------------- -------------------
Oil Ngl Gas Combined Oil Ngl Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
2002
- ----
Nine Months Ended September 30:
Domestic 1,257 1,110 12.4 26.6 $27.38 $11.91 $2.78
New Zealand 342 145 7.6 10.6 $23.28 $10.76 $1.29
----------- ---------- ---------- ------------
Total 1,599 1,255 20.0 37.2 $26.50 $11.77 $2.21
=========== ========== ========== ============
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
=========== ========== ========== ============
In March 2002, we received $7.5 million for our interest in the Samburg
project located in western Siberia, Russia as a result of the sale by a
third party of its ownership in a Russia joint stock company that owned and
operated the field. Although the proceeds from sales of oil and gas
properties are generally treated as a reduction of oil and gas property
costs, because we had previously charged to expense all $10.8 million of
cumulative costs relating to our Russian activities, this cash payment, net
of transaction expenses, resulted in recognition of a $7.3 million
non-recurring gain on asset disposition in the first quarter of 2002. This
activity was recorded in "Gain on asset disposition" in the accompanying
consolidated statement of income.
During the first nine months of 2003, we recognized net losses of $2.4
million relating to our hedging activities, as compared to net losses of
$0.2 million in the same 2002 period. This activity is recorded in
"Price-risk management and other, net" on the accompanying consolidated
statement of income.
Revenues from our oil and gas sales comprised substantially all of net
revenues for the first nine months of 2003 and 93% of total revenues for
the comparable 2002 period. Natural gas production made up 54% of our
production volumes in the first nine months of both 2003 and 2002.
Costs and Expenses. Our expenses in the first nine months of 2003
increased $21.0 million, or 22%, compared to the same 2002 period expenses.
The majority of the increase was due to our increased oil and gas
production costs, both domestically and in New Zealand, an increase in
depletion expense, both domestically and in New Zealand, and an increase in
interest expense due to replacement of our bank borrowings with our Senior
Notes due 2012.
Our net general and administrative expense in the first nine months of
2003 increased $3.2 million, or 43%, from the level of such expenses in the
comparable 2002 period. These increases reflect additional costs needed for
our increased activities in New Zealand, a reduction in reimbursement from
partnerships we managed as almost all of these partnerships have
liquidated, an increase in franchise tax expense, and increased costs
related to our corporate governance activities and compliance with the
Sarbanes-Oxley Act. Our general and administrative expenses per Mcfe
produced increased to $0.27 per Mcfe in the first nine months of 2003 from
$0.20 per Mcfe in the same 2002 period. The portion of supervision fees
netted from general and administrative expenses was $2.2 million for the
first nine months of 2003 and $2.3 million for the same 2002 period.
26
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Depreciation, depletion, and amortization of our assets, or DD&A,
increased $4.8 million, or 12%, in the first nine months of 2003 from the
same 2002 period. Domestically, DD&A decreased $1.7 million due to
decreased production in the same 2003 period, and higher reserve volumes
that were added primarily through our Lake Washington activities. In New
Zealand, our production increased in the first nine months of 2003 in both
the Rimu/Kauri and TAWN areas, which increased DD&A in this period. Our
DD&A rate per Mcfe of production was $1.17 in the first nine months of 2003
and $1.12 in the same 2002 period, reflecting these variations in per unit
cost of reserves additions.
We recorded $0.6 million of accretion on our asset retirement
obligation in the first nine months of 2003 associated with the adoption of
SFAS No. 143 implemented on January 1, 2003.
Our production costs increased $8.8 million in the first nine months of
2003, or 29%, and were $0.99 and $0.82 per Mcfe in the first nine months of
2003 and 2002, respectively. Due to the 41% increase in production during
the first nine months of 2003, our New Zealand operations contributed $4.4
million of the cost increase in the period. Domestic severance taxes
increased $4.4 million in the first nine months of 2003, due to higher
commodity prices. The portion of supervision fees netted from production
costs was $1.5 million for the first nine months of both 2003 and 2002.
Interest expense on our Senior Notes due 2009, including amortization
of debt issuance costs, totaled $9.9 million in both the first nine months
of 2003 and 2002. Interest expense on our Senior Notes due 2012, including
amortization of debt issuance costs, totaled $14.3 million and $8.7 million
in the first nine months of 2003 and 2002, respectively. Interest expense
on our credit facility, including commitment fees and amortization of debt
issuance costs, totaled $1.1 million in the first nine months of 2003 and
$3.3 million in the same period in 2002. The total interest cost in the
first nine months of 2003 was $25.3 million, of which $5.2 million was
capitalized. The total interest cost in the first nine months of 2002 was
$21.9 million, of which $5.3 million was capitalized. We capitalize that
portion of interest related to our unproved properties. The increase in
interest expense in the first nine months of 2003 was attributed to the
replacement of our bank borrowings in April 2002 with the Senior Notes due
2012 that carry a higher interest rate and a longer term.
As discussed in Note 1 to the Consolidated Financial Statements, we
implemented SFAS No. 143 effective 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 consolidated statement of income. This statement requires that the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets be recorded 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. Over time,
accretion of the liability is recognized each period, and the capitalized
cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, the obligation is either settled for its
recorded amount or a gain or loss is incurred upon settlement. This
statement requires that a liability for the fair value of our dismantlement
and abandonment costs, excluding salvage values be recorded.
Net Income. Our net income in the first nine months of 2003 of $20.4
million was 138% higher and Basic EPS of $0.75 were 131% higher than our
first nine months of 2002 net income of $8.6 million and Basic EPS of
$0.33. Our Diluted EPS in the first nine months of 2003 of $0.74 were also
131% higher than our first nine months of 2002 Diluted EPS of $0.32. These
amounts increased in the same 2003 period as oil and gas sales increased
due to higher commodity prices and our increased production.
Related-Party Transactions
We are currently the operator of a limited number of properties owned
by the six remaining affiliated limited partnerships and, accordingly,
charge these entities operating fees. The operating fees charged to the
partnerships were approximately $0.1 million in the first nine months of
2003 and $0.3 million in the 2002
27
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
period, and are recorded as reductions of general and administrative
expense and oil and gas production expense. We also have been reimbursed
for direct, administrative, and overhead costs incurred in conducting the
business of the limited partnerships, which totaled approximately $0.4
million and $0.9 million in the first nine months of 2003 and 2002,
respectively. These lower amounts reflect our continued transition away
from partnerships.
28
SWIFT ENERGY COMPANY MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS-CONTINUED
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.
29
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 discussed in Management's Discussion and Analysis, and such
volatility is expected to continue.
Our price-risk program permits the utilization of derivative instruments
(such as futures, forward and options contracts, and swaps) to mitigate
price risk associated with fluctuations in oil and natural gas prices.
Below is a description of the derivative instruments we have utilized to
hedge our exposure to price risk.
o Price Floors - At September 30, 2003, we had price floors in place
effective through the contract month of December 2003 for natural gas and
through November 2003 for crude oil. The natural gas price floors cover
notional volumes of 1,050,000 MMBtu, with a weighted average floor price of
$4.75 per MMBtu. The crude oil price floors cover notional volumes of
180,000 barrels of oil, with a weighted average floor price of $27.58 per
barrel. Our hedges in place at September 30, 2003 should cover
approximately 25% to 30% of our forecasted fourth quarter 2003 gas
production and 15% to 20% of our forecasted fourth quarter 2003 oil
production.
o New Zealand Gas Contracts - A majority of our gas production in New Zealand
is sold under long-term, fixed-price contracts denominated in New Zealand
dollars. These contracts protect against price volatility, and our revenue
from these contracts will vary only due to fluctuations in volumes
delivered 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 Kiwi. Fluctuations in rates between the New Zealand
Kiwi and U.S. Dollar may impact our financial results from our New Zealand
subsidiaries since we have receivables and liabilities denominated in New
Zealand Kiwi.
Interest Rate Risk
Our Senior Notes have a fixed interest rate, so consequently we are not
exposed to cash flow risk from market interest rate changes on our Senior
Notes. However, there is a risk that market rates will decline and the
required interest payments on our Senior Notes may exceed those payments
based on the current market rate. At September 30, 2003, we had $11.9
million in borrowings under our credit facility, which is subject to
floating rates and therefore susceptible to interest rate fluctuations. The
result of a 10% fluctuation in the bank's base rate would constitute 40
basis points and would not have a material adverse effect on our 2003 cash
flows based on this same level of borrowing.
30
CONTROLS AND PROCEDURES
The Company's chief executive officer and chief financial officer have
evaluated the Company's disclosure controls and procedures, as defined in
Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934
(the "Exchange Act") as of the end of the period covered by this report.
Based on that evaluation, they have concluded that such disclosure controls
and procedures are effective, in all material respects, in communicating to
them on a timely basis material information relating to the Company
required under the Exchange Act to be disclosed in this quarterly report.
There were no significant changes in the Company's internal control over
financial reporting that occurred during the Company's last fiscal quarter
that have materially affected, or are reasonably likely to materially
affect, such control.
31
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation incidental to the Company's business.
Item 2. Changes in Securities and Use of Proceeds - N/A
Item 3. Defaults Upon Senior Securities - N/A
Item 4. Submission of Matters to a Vote of Security Holders - N/A
Item 5. Other Information - N/A
Item 6. Exhibits & Reports on Form 8-K -
(a) Documents filed as part of the report
(3) Exhibits
10.19 Employment Agreement dated as of November 1, 2003 between
Swift Energy Company and James P. Mitchell.
12 Swift Energy Company Ratio of Earnings to Fixed Charges.
31.1 Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
32 Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K filed during the quarter ended September 30,
2003, which are incorporated herein by reference:
On August 6, 2003, the Company filed a Current Report on Form 8-K
that reported under Item 7, "Financial Statements, Pro Forma
Financial Information and Exhibits" and Item 12, "Results of
Operations and Financial Conditions" relating to the press
release announcement of second quarter 2003 earnings.
32
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 14, 2003 By: (original signed by)
----------------- ----------------------------
Alton D. Heckaman, Jr.
Senior Vice President,
Chief Financial Officer
Date: November 14, 2003 By: (original signed by)
----------------- ----------------------------
David W. Wesson
Controller and Principal
Accounting Officer
33
Exhibit 10.19
EMPLOYMENT AGREEMENT
THIS EMPLOYMENT AGREEMENT ("Agreement") is dated this 1st day of
November, 2003, by and between Swift Energy Company, a Texas corporation (the
"Company"), and James P. Mitchell.
W I T N E S S E T H:
WHEREAS, Employee is employed as Senior Vice President-Commercial
Transactions and Land of the Company; and
WHEREAS, the Company and Employee wish to document certain terms of
employment of Employee in such capacity;
NOW, THEREFORE, in consideration of the premises and mutual covenants
herein contained, the Company and Employee hereby agree as follows:
1. Employment and Term of Employment. Subject to the terms and
conditions of this Agreement, the Company hereby agrees to employ Employee, and
Employee hereby agrees to serve as Senior Vice President-Commercial Transactions
and Land of the Company, or in such other position as is mutually acceptable to
both Employee and the Company, for a period commencing on the date hereof
through May 9, 2006, which period shall automatically be extended for an
additional year on May 9 of each year beginning May 9, 2004 (such period, as so
extended at any time, the "Contract Term") unless notice to the contrary is
given not less than 60 days prior to any May 9 of each year beginning May 9,
2004 by either party to this Agreement. The period during which Employee
actually works for and is employed by the Company is hereafter referred to as
the "Term of Employment."
2. Scope of Employment. During the Term of Employment, (i) Employee
will serve as Senior Vice President-Commercial Transactions and Land with the
powers and responsibilities of such position set forth in the bylaws of the
Company, or in such other position as is mutually acceptable to both Employee
and the Company, and Employee will perform diligently to the best of his ability
those duties set forth therein and in this Agreement in a manner that promotes
the interests and goodwill of the Company, (ii) the Company shall not require
Employee to relocate from Houston, Texas, and (iii) the Company may assign
Employee to other duties.
3. Compensation. During the Term of Employment, the Company shall
compensate Employee for his services hereunder in such amount as shall be
determined by the Compensation Committee of the Board of Directors of the
Company from time to time, but such compensation shall not be reduced at any
time in contemplation of, related to, or as a result of, a Change in Control, as
defined in Section 7.
4. Additional Compensation and Benefits. As additional compensation for
Employee's services under this Agreement, during the Term of Employment the
Company agrees to provide Employee with the following reimbursements and
benefits:
(a) The Company shall reimburse Employee for reasonable and
necessary expenses incurred by Employee in furtherance of the Company's
business, including a mileage allowance for all business-related travel
on a per-mile basis at a rate equivalent to that allowed by the
Internal Revenue Service, provided that such expenses are incurred in
accordance with the Company's policies and upon presentation of
documentation in accordance with expense reimbursement policies of the
Company as they may exist from time to time, and submission to the
Company of adequate documentation in accordance with federal income tax
regulations.
(b) Employee may participate in any non-cash benefits provided
by the Company to its
34
employees as they may exist from time to time. Such benefits shall
include leave or vacation time, medical and dental insurance, life
insurance, accidental death and dismemberment insurance, retirement
benefits and disability benefits, as such benefits may hereafter be
provided by the Company in accordance with its policies in force from
time to time.
(c) In the event of Employee's death during the Term of
Employment (i) for a twelve-month period after his death the Company
shall make available at its expense medical and dental insurance
covering Employee's spouse and his dependents ("Dependents") who would
have been covered (if the Term of Employment had continued) by the
Company's medical and dental insurance policies as then in effect or in
effect from time to time and (ii) thereafter for the remainder of the
Contract Term such medical and dental insurance shall be provided to
Employe's spouse and Dependents, with Employee's spouse (or Dependents
or estate, if applicable), to reimburse the Company for the cost for
comparable family coverage under the Company's medical and dental
insurance policies, unless otherwise prohibited by applicable law.
5. Confidentiality.
(a) Employee recognizes that the Company's business involves
the handling of confidential information of both the Company and the
Company's affiliates, subsidiaries, joint venture partners and industry
partners, and requires a confidential relationship between them and the
Company and Employee. The Company's business requires the fullest
practical protection and confidential treatment of unique and
proprietary business and technical information, including but not
limited to inventions, trade secrets, patents, proprietary and
confidential data (including engineering, geophysical, geological and
computer program data) and Employee's knowledge of the Company, its
affiliates, subsidiaries, joint venture partners, industry partners,
customers and contractors (collectively, hereinafter called
"Confidential Information") which is conceived or obtained by Employee
in the course of his employment. Accordingly, during and after
termination of employment by the Company, Employee agrees: (i) to
prevent the disclosure to any third party of all such Confidential
Information; (ii) not to use for Employee's own benefit any of the
Company's Confidential Information, and (iii) not to aid others in the
use of such Confidential Information in competition with the Company or
its affiliates and subsidiaries. These obligations shall exist during
and after any termination of employment hereunder. Notwithstanding
anything else contained herein, the term "Confidential Information"
shall not be deemed to include any general knowledge, skills or
experience acquired by Employee or any knowledge or information known
to the public in general.
(b) Employee agrees that every item of Confidential
Information referred to in this Section 5 which relates to the
Company's present business or which arises or is contemplated to arise
out of use of the Company's time, facilities, personnel or funds prior
to Employee's termination, is the property of the Company.
(c) Employee further agrees that upon termination of his
employment for any reason, he will surrender to the Company all
reports, manuals, procedures, guidelines, documents, writing,
illustrations, models and other such materials produced by him or
coming into his possession by virtue of his employment with the Company
during the period of his employment and agrees that all such materials
are at all times the property of the Company. Employee shall be
entitled to review, inspect and copy any of the Company information or
material necessary for legal or other proceedings to which Employee is
a party defendant by reason of the fact that he is or was an Employee
of the Company.
(d) Employee and the Company acknowledge their respective
execution of an agreement
35
entitled "Inventions, Copyrights, and Confidentiality of Company or
Customer Information Agreement" (the "Inventions Agreement") and hereby
agree that should any provision of this Agreement conflict with any
provision of the Inventions Agreement, the provisions of the Inventions
Agreement shall control.
6. Covenant Not to Compete.
(a) Subject to the provisions of (c) of this section, without
the express prior written consent of the Corporate Governance Committee
of the Company's Board of Directors, Employee will not serve as an
employee, officer, director or consultant, or in any other similar
capacity or make investments (other than open market investments in no
more than five percent (5%) of the outstanding stock of any publicly
traded company) in or on behalf of any person, firm, corporation,
association or other entity whose activities directly compete with the
activities of the Company existing or contemplated as of the date he
last worked on the Company's behalf pursuant to this Agreement, in
those portions or areas of oil and gas basins in which the Company is
active or as to which it has begun study or analysis, where such
employment may involve working for or with, or assisting, such
competitor with activities that are the same as or similar to
activities Employee performed on behalf of the Company; provided,
however, the Company recognizes that any investment made by Employee in
oil and gas properties owned by the Company which investments are made
on the same terms (or terms more favorable to the Company) as those
offered to unaffiliated third parties are specifically excluded from
this section; and
(b) Subject to the provisions of (c) of this section, without
the express prior written consent of the Company, he will not solicit,
recruit or hire, or assist any person, firm, corporation, association
or other entity in the solicitation, recruitment or hiring of any
person engaged by the Company as an employee, officer, director or
consultant.
(c) Employee's obligations under (a) and (b) of this section
shall continue in force during all periods of Employee's employment by
the Company, and after termination of employment for that portion of
the Contract Term remaining during which (x) Employee actually receives
cash payments under this Agreement or (y) Employee would have received
such cash payments but for a lump sum payment being made in lieu
thereof, whichever is longer, provided that (i) if cash payments to be
made by the Company during the remainder of the Contract Term after the
Termination Date (as defined below) are not then being made to Employee
currently or (ii) if there has been a "Change in Control," as defined
below, then the provisions of subsections (a) and (b) of this section
shall have no further force and effect after the date that such
payments stop or the date such Change of Control occurs, respectively.
7. Termination.
(a) Either the Company or Employee may terminate Employee's
employment during the Term of Employment upon 60 days' written notice.
Such termination by the Company shall require the affirmative vote of a
majority of the members of the Board of Directors of the Company then
in office who have been or will have been directors for the two-year
period ending on the date notice of the meeting or written consent to
take such action is first provided to shareholders or directors, as the
case may be, or those directors who have been nominated for election or
elected to succeed such directors by a majority of such directors (the
"Continuing Directors").
In the case of termination of Employee's employment during the
Term of Employment,
36
except in those circumstances covered by Sections 7(b) or (c) below,
Employee shall be paid over a period commencing on the day after the
last day he worked on the Company's behalf pursuant to this Agreement
(the "Termination Date") and continuing (the "Continuation Period") for
one-half of the remainder of the Contract Term. The amount to be paid
shall be equal to the sum of (x) the total salary otherwise payable to
Employee over the period which is one-half of the remainder of the
Contract Term, based upon the salary being paid to the Employee
immediately prior to the Termination Date, plus (y) an additional
amount equal to one week's salary (at Employee's then current salary)
for every year of service to the Company (rounded up to the nearest
full year of service). The total of these amounts shall be referred to
as the "Post Termination Payment." The Post Termination Payment shall
be paid out on a twice per month basis of equal installments during the
Continuation Period so that the Post Termination Payment will be paid
in full to Employee by the end of the Continuation Period.
Additionally, the Company shall provide at its expense for the
Continuation Period such medical and dental coverage as in effect on
the Termination Date. Notwithstanding the foregoing, Employee shall not
receive such compensation if the Company terminates his employment for
Cause. "Cause" shall be defined as (i) commission of fraud against the
Company, its subsidiaries, affiliates or customers, (ii) willful
refusal without proper legal cause, after 30 days' advance written
notice from the Chairman of the Board of the Company and/or the Chief
Executive Officer, or, after a Change in Control, from the Continuing
Directors, to faithfully and diligently perform Employee's duties as
directed in such notice or correct or terminate those practices as
described in such notice, all within the context of a forty-hour per
week schedule, or (iii) breach of Section of this Agreement.
Immediately prior to the date of termination of Employee's
employment under this Agreement by either party, except in those
circumstances covered by Sections 7(b) or 7(c) below, all outstanding
unexercised options to purchase shares of common stock of the Company
(granted on or after the date of this Agreement) held by Employee (as
of the day prior to such termination) shall immediately vest or be
deemed to have vested, and otherwise Employee shall retain such options
with no change in the number of shares covered by such options, the
date such options first become exercisable, the period over which they
are exercisable, or their exercise price.
(b) Change of Control.
(1) In the event Employee's employment is terminated
by the Company, after, by, on account of, or in connection
with, a "Change of Control," as defined below, or in the event
Employee resigns during the Contract Term hereunder following
a "Change in Control," as defined, the Company (i) shall pay
Employee on his last day of employment by the Company a lump
sum equal to the total compensation which otherwise is payable
to Employee for the remainder of the Contract Term, with total
compensation to be based upon the salary being paid to
Employee immediately prior to the Termination Date (without
taking into effect any reduction in salary which may have
taken place after, by, on account of, or in connection with a
Change of Control), plus an additional amount equal to two
weeks' of his then current salary for every year of service to
the Company (rounded up to the nearest full year of service),
and (ii) provide at the Company's expense for the Contract
Term such medical and dental coverage as in effect on the
Termination Date. Effective as of the day prior to such Change
of Control, all outstanding unexercised stock options to
purchase shares of common stock of the Company held by
Employee as of such date will immediately become 100% vested
and 100% exercisable.
(2) Change of Control: "Change of Control," for
purposes of this Agreement, shall be deemed to have occurred
upon the occurrence of any one (or more) of the
37
following events, other than a transaction with another person
controlled by, or under common control with, the Company:
(A) Any person, including a "group" as
defined in Section (3)(d)(3) of the Securities
Exchange Act of 1934, as amended, becomes the
beneficial owner of shares of the voting stock of the
Company with respect to which 40% or more of the
total number of votes for the election of the Board
may be cast;
(B) As a result of, or in connection with,
any cash tender offer, exchange offer, merger or
other business combination, sale of assets or
contested election, or combination of the above,
persons who were directors of the Company immediately
prior to such event shall cease to constitute a
majority of the Board;
(C) The stockholders of the Company shall
approve an agreement providing either for a
transaction in which the Company will cease to be an
independent publicly owned corporation or for a sale
or other disposition of all or substantially all the
assets of the Company; or
(D) A tender offer or exchange offer is made
for shares of the Company's Common Stock (other than
one made by the Company), and shares of Common Stock
are acquired thereunder ("Offer").
(3) Notwithstanding anything to the contrary in this
Agreement, in the event that any payment, distribution, or
other benefit provided by the Company to or for the benefit of
Employee, whether paid or payable or distributed or
distributable pursuant to the terms of this Agreement or
otherwise (a "Payment"), would be subject to the excise tax
imposed by Section 4999 of the Internal Revenue Code of 1986,
as amended, or any interest or penalties with respect to such
excise tax (such excise tax, together with any such interest
or penalties, are hereinafter collectively referred to as the
"Excise Tax"), the Company shall pay to Employee an additional
payment (a "Gross-up Payment") in an amount such that after
payment by Employee of all taxes (including any interest or
penalties imposed with respect to such taxes), including any
Excise Tax imposed on any Gross-up Payment, Employee retains
an amount of the Gross-up Payment equal to the Excise Tax
imposed upon the Payments. The Company and Employee shall make
an initial determination as to whether a Gross-up Payment is
required and the amount of any such Gross-up Payment. Employee
shall notify the Company immediately in writing of any claim
by the Internal Revenue Service, which, if successful, would
require the Company to make a Gross-up Payment (or a Gross-up
Payment in excess of that, if any, initially determined by the
Company and Employee) within fifteen days of the receipt of
such claim. The Company shall notify Employee in writing at
least ten days prior to the due date of any response required
with respect to such claim if it plans to contest such claim.
If the Company decides to contest such claim, Employee shall
cooperate fully with the Company in such action; provided,
however, the Company shall bear and pay directly or indirectly
all costs and expenses (including additional interest and
penalties) incurred in connection with such action and shall
indemnify and hold Employee harmless, on an after-tax basis,
for any Excise Tax or income tax, including interest and
penalties with respect thereto, imposed as a result of the
Compan's action. If, as a result of the Company's action with
respect to a claim, Employee receives a refund of any amount
paid by the Company with respect to such claim, Employee shall
promptly pay such refund to the Company. If the Company fails
to timely notify Employee whether it
38
will contest such claim or the Company determines not to
contest such claim, then the Company shall immediately pay to
Employee the portion of such claim, if any, which it has not
previously paid to Employee.
(c) In the event of termination due to Employee's death or as
a result of total and permanent disability (as defined in the Company's
long-term disability plan, or if the Company has no long-term
disability plan in effect at the time of Employee's disability,
permanent disability shall have the meaning provided in Section
22(e)(3) of the Code, as used herein "Permanent Disability") during the
Term of Employment, the Company shall pay to the estate of Employee or
Employee, as applicable, in the year of death or the year thereafter
(as designated by Employee's estate), or the day after his employment
terminates by reason of Permanent Disability, a lump sum payment equal
to the total compensation which otherwise is payable to Employee if he
worked for one-half of the Contract Term remaining as of the date of
death or the day prior to termination of employment by reason of
Permanent Disability, with total compensation to be based upon the
salary being paid to Employee immediately prior to the date of death or
Permanent Disability, plus (ii) an amount equal to one week's salary
for every year of service to the Company (rounded up to the nearest
full year of service). On the date of Employee's death or Permanent
Disability, all outstanding unexercised stock options to purchase
shares of common stock of the Company held by Employee immediately
prior to such date will immediately become 100% vested and 100%
exercisable by Employee's estate or by Employee, as applicable, and
remain exercisable until expiration of each option under its original
term.
(d) In the event Employe's employment is terminated in those
circumstances covered by Sections 7(a) or 7(b) above or by reason of
Permanent Disability, the Company shall, for a one-year period
following Employee's Termination Date, pay the scheduled premium
payments (on or before their due dates) on any universal life insurance
policy covering Employee's life which is in force immediately prior to
the Termination Date; provided, however, that the Company shall be
obligated to pay any such premiums only to the extent that, and on the
same basis as, payments are made by the Company on the universal life
insurance policies covering other employees of the Company with same or
similar coverage.
8. Governing Law. This Agreement shall be governed by and construed
under the laws of the State of Texas. Venue and jurisdiction of any action
relating to this Agreement shall lie in Houston, Harris County, Texas.
9. Notice. Any notice, payment, demand or communication required or
permitted to be given by this Agreement shall be deemed to have been
sufficiently given or served for all purposes if delivered personally to and
signed for by the party or to any officer of the party to whom the same is
directed or if sent by registered or certified mail, return receipt requested,
postage and charges prepaid, addressed to such party at its address set forth
below such party's signature to this Agreement or to such other address as shall
have been furnished in writing by such party for whom the communication is
intended. Any such notice shall be deemed to be given on the date so delivered.
10. Severability. In the event any provisions hereof shall be modified
or held ineffective by any court, such adjudication shall not invalidate or
render ineffective the balance of the provisions hereof.
11. Entire Agreement. This Agreement constitutes the sole agreement
between the parties and supersedes any and all other agreements, oral or
written, relating to the subject matter covered by the Agreement with the
exception of certain Indemnity Agreements which may exist between the Company
and Employee, and which remain in force independent of this Agreement.
12. Waiver. Any waiver or breach of any of the terms of this Agreement
shall not operate as a waiver of
39
any other breach of such terms or conditions, or any other terms or conditions,
nor shall any failure to enforce any provisions hereof operate as a waiver of
such provision or any other provision hereof.
13. Assignment. This Agreement is a personal employment contract and
the rights and interests of Employee hereunder may not be sold, transferred,
assigned or pledged.
14. Successors. This Agreement shall be binding upon and inure to the
benefit of the parties hereto and their respective heirs, representatives,
successors and assigns.
15. Disputes.
(a) Subject to Section 15(b) below, if a dispute arises under
this Agreement related to the payment of amounts provided hereunder to
be paid by the Company to Employee or the timing of such payments or
their calculation, and the dispute cannot be settled through direct
discussions, the Company and Employee agree that such disputes shall be
resolved by submitting such disputes to mandatory binding fast-track
arbitration with the American Arbitration Association in Houston,
Texas. The Company will pay the actual fees and expenses of the
arbitrators, and the parties shall bear equally all other expenses of
such arbitration, unless the arbitrators determine that a different
allocation would be more equitable. The award of the arbitrators will
be the exclusive remedy of the parties for such disputes. Nothing in
this Section 15(a) shall prevent either party from seeking provisional
injunctive relief pending arbitration, by applying to any court of
competent jurisdiction.
(b) Section 15(a) to the contrary notwithstanding, it is
expressly agreed that if based upon events which take place after, by,
on account of, or in connection with, a Change of Control it becomes
necessary in Employee's judgment for him to sue the Company in order to
collect amounts to be paid to him under this Agreement or otherwise
enforce his rights under this Agreement, then the Company will be
obligated to pay both its own and Employee's legal fees in such
litigation, including the obligation of the Company to pay Employee's
legal fees within thirty days of receiving invoices therefor from
Employee.
(c) The jurisdiction and venue for resolution of any disputes
involving this Agreement or Employee's employment by the Company shall
be in the state courts of Houston, Harris County, Texas.
16. Lump Sum Payments. If payments to be made under any portion of this
Agreement provide for such payments to be made over a period of time, Employee
and the Company's Board of Directors may agree for such payments to be made in a
lump sum, which shall be determined by discounting the periodic payments using a
discount factor of 8% per annum
40
IN WITNESS WHEREOF, the parties hereto affixed their signatures
hereunder as of the date first above written.
SWIFT ENERGY COMPANY
By: /s/ Terry E. Swift
---------------------
Terry E. Swift
Chief Executive Officer and
President
"EMPLOYEE"
/s/ James P. Mitchell
------------------------
James P. Mitchell
14003 Torrey Village
Houston, Texas 77014
41
Exhibit 12
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
Nine months
Years Ended December 31, Ended
September 30,
---------------------------------------------------------------------- -------------
1998 1999 2000 2001 2002 2003
------------- ------------ ------------- ------------- ------------- -------------
GROSS G&A 21,010,960 20,518,843 23,793,995 25,974,568 26,074,408 22,053,045
NET G&A 3,853,812 4,497,400 5,585,487 8,186,654 10,564,849 10,564,959
INTEREST EXPENSE, NET 8,752,195 14,442,815 15,968,405 12,627,022 23,274,969 20,107,188
RENT EXPENSE 1,117,351 1,272,497 1,255,474 1,322,618 1,923,451 1,610,803
NET INCOME BEFORE TAXES & CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (73,391,581) 29,736,151 93,079,346 (34,192,333) 18,408,289 38,450,916
CAPITALIZED INTEREST 3,849,665 4,142,098 5,043,206 6,256,222 6,973,480 5,156,559
DEPLETED CAPITALIZED INTEREST 292,267 323,124 307,249 280,929 215,433 386,877
CALCULATED DATA
- --------------------------------
UNALLOCATED G&A (%) 18.34% 21.92% 23.47% 31.52% 40.52% 47.91%
NON-CAPITAL RENT EXPENSE 204,944 278,911 294,714 416,862 779,345 771,688
1/3 NON-CAPITAL RENT EXPENSE 68,315 92,970 98,238 138,954 259,782 257,229
FIXED CHARGES 12,670,175 18,677,883 21,109,849 19,022,198 30,508,231 25,520,976
EARNINGS (64,278,804) 44,595,061 109,453,238 (21,145,428) 42,158,473 59,202,210
RATIO OF EARNINGS TO FIXED CHARGES
--- 2.39 5.18 --- 1.38 2.32
============ =========== ============ ============ ============ ============
For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense net (which includes amortization of debt
issuance costs and discounts), capitalized interest and that portion of
non-capitalized rental expense deemed to be the equivalent of interest. Earnings
represents income before income taxes and cumulative effect of change in
accounting principle and from continuing operations before fixed charges
(excluding capitalized interest, net of depletion). Due to the $98.9 million
non-cash charge incurred in the fourth quarter of 2001 caused by a write-down in
the carrying value of oil and gas properties, 2001 earnings were insufficient by
$40.2 million to cover fixed charges in this period. If the $98.9 million
non-cash charge is excluded, the ratio of earnings to fixed charges would have
been 4.09 for 2001. Due to the $90.9 million non-cash charge incurred in the
third quarter of 1998 caused by a write-down in the carrying value of oil and
gas properties, 1998 earnings were insufficient by $76.9 million to cover fixed
charges in this period. If the $90.8 million non-cash charge is excluded, the
ratio of earnings to fixed charges would have been for 2.09 for 1998.
42
Exhibit 31.1
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Swift Energy Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of Swift
Energy as of, and for, the periods presented in this quarterly report;
4. Swift Energy'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 Swift Energy and we 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 Swift Energy, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of Swift Energy's disclosure controls and
procedures and presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this quarterly report based on such evaluation; and
c) disclosed in this quarterly report any changes in Swift Energy Company's
internal control over financial reporting that occurred during Swift Energy
Company's most recent fiscal quarter that has materially affected, or is
reasonably likely to materially affect, Swift Energy Company's internal control
over financial reporting; and
5. Swift Energy's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
Swift Energy Company's auditors and the audit committee of Swift Energy
Company's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably
likely to adversely affect Swift Energy Company'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 Swift Energy Company's internal control
over financial reporting.
Date: November 14, 2003
(original signed by)
-------------------------
Terry E. Swift
President and
Chief Executive Officer
43
Exhibit 31.2
CERTIFICATION
I, Alton D. Heckaman, Jr., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Swift Energy Company;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of Swift
Energy as of, and for, the periods presented in this quarterly report;
4. Swift Energy'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 Swift Energy and we 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 Swift Energy, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of Swift Energy's disclosure controls and
procedures and presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this quarterly report based on such evaluation; and
c) disclosed in this quarterly report any changes in Swift Energy Company's
internal control over financial reporting that occurred during Swift Energy
Company's most recent fiscal quarter that has materially affected, or is
reasonably likely to materially affect, Swift Energy Company's internal control
over financial reporting; and
5. Swift Energy's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
Swift Energy Company's auditors and the audit committee of Swift Energy
Company's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or
operation of internal controls over financial reporting which are reasonably
likely to adversely affect Swift Energy Company'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 Swift Energy Company's internal control
over financial reporting.
Date: November 14, 2003
(original signed by)
------------------------------
Alton D. Heckaman, Jr.
Senior Vice President - Finance
Chief Financial Officer
44
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
quarter ended September 30, 2003 (the "Report") of Swift Energy Company
("Swift") as filed with the Securities and Exchange Commission on November 14,
2003, 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 14, 2003 (original signed by)
---------------------------------
Alton D. Heckaman, Jr.
Senior Vice President-Finance and
Chief Financial Officer
Dated: November 14, 2003 (original signed by)
---------------------------------
Terry E. Swift
President and Chief Executive
Officer
This certification made in accordance with Section 906 of the Sarbanes-Oxley Act
of 2002 is furnished by Swift and accompanies the Quarterly Report on Form 10-Q
of Swift for the period ended September 30, 2003. This certification shall not
be deemed filed by Swift for purposes of Section 18 of the Securities and
Exchange Act of 1934, as amended.
45