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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 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 27,419,169 Shares
($.01 Par Value) (Outstanding at July 31, 2003)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets
- June 30, 2003 and December 31, 2002 3
Consolidated Statements of Income
- For the Three-month and Six-month periods ended
June 30, 2003 and 2002 5
Consolidated Statements of Stockholders' Equity
- June 30, 2003 and December 31, 2002 6
Consolidated Statements of Cash Flows
- For the Six-month periods ended June 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 18
Item 3. Quantitative and Qualitative Disclosures About Market Risk 28
Item 4. Controls and Procedures 29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 30
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 30
SIGNATURES 32
2
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
June 30, 2003 December 31, 2002
------------------------ -------------------------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 2,126,109 $ 3,816,107
Accounts receivable -
Oil and gas sales 23,159,943 17,360,716
Associated limited partnerships
and joint ventures 355,767 191,964
Joint interest owners 1,317,110 3,364,846
Other current assets 9,267,270 5,034,566
------------------------ -------------------------
Total Current Assets 36,226,199 29,768,199
------------------------ -------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 1,215,614,432 1,150,633,802
Unproved properties not being amortized 67,714,851 69,603,481
------------------------ -------------------------
1,283,329,283 1,220,237,283
Furniture, fixtures, and other equipment 10,046,269 9,595,944
------------------------ -------------------------
1,293,375,552 1,229,833,227
Less-Accumulated depreciation, depletion,
and amortization (534,825,713) (504,323,773)
------------------------ -------------------------
758,549,839 725,509,454
------------------------ -------------------------
Other Assets:
Deferred income taxes 1,477,765 2,680,585
Deferred charges 8,539,981 9,047,621
------------------------ -------------------------
10,017,746 11,728,206
------------------------ --------------------------
$ 804,793,784 $ 767,005,859
======================== =========================
See accompanying notes to consolidated financial statements.
3
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
June 30, 2003 December 31, 2002
------------------------ ------------------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 42,679,095 $ 43,028,708
Payable to associated limited partnerships --- 91,126
Undistributed oil and gas revenues 4,377,245 3,764,350
------------------------ ------------------------
Total Current Liabilities 47,056,340 46,884,184
------------------------ ------------------------
Long-Term Debt 331,812,331 324,271,973
Deferred Income Taxes 36,270,418 30,776,518
Asset Retirement Obligation 9,519,611 ---
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,
27,943,869 and 27,811,632 shares issued, and 27,416,841
and 27,201,509 shares outstanding, respectively 279,439 278,116
Additional paid-in capital 334,280,773 333,543,471
Treasury stock held, at cost, 527,018 and
610,123 shares, respectively (7,558,093) (8,749,922)
Retained earnings 53,509,083 40,179,572
Other comprehensive loss, net of taxes (376,118) (178,053)
------------------------ ------------------------
380,135,084 365,073,184
------------------------ ------------------------
$ 804,793,784 $ 767,005,859
======================== ========================
See accompanying notes to consolidated financial statements.
4
SWIFT ENERGY COMPANY
Consolidated Statements of Income
(UNAUDITED)
Three months ended Six months ended
------------------------------ ----------------------------------
06/30/03 06/30/02 06/30/03 06/30/02
-------------- ------------- ---------------- ---------------
Revenues:
Oil and gas sales $ 50,909,250 $ 38,331,342 $ 105,759,549 $ 64,944,183
Fees from limited partnerships
and joint ventures 6,880 49,498 14,935 54,123
Interest income 72,776 26,531 110,468 32,293
Gain on asset disposition --- --- --- 7,332,668
Price-risk management and other, net (271,377) 162,898 (1,667,430) 561,079
-------------- ------------- ---------------- ---------------
50,717,529 38,570,269 104,217,522 72,924,346
-------------- ------------- ---------------- ---------------
Costs and Expenses:
General and administrative, net 3,337,995 2,597,549 6,894,543 4,871,576
Depreciation, depletion and amortization 15,676,549 14,341,510 30,588,312 28,302,274
Accretion of asset retirement obligation 201,903 --- 417,286 ---
Oil and gas production 13,754,411 10,032,445 25,662,064 19,597,852
Interest expense, net 6,672,867 6,079,879 13,357,769 9,959,683
-------------- ------------- ---------------- ---------------
39,643,725 33,051,383 76,919,974 62,731,385
-------------- ------------- ---------------- ---------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle 11,073,804 5,518,886 27,297,548 10,192,961
Provision for Income Taxes 3,852,378 1,934,794 9,591,185 3,589,059
-------------- ------------- ---------------- ---------------
Income Before Cumulative Effect of Change
in Accounting Principle 7,221,426 3,584,092 17,706,363 6,603,902
Cumulative Effect of Change in Accounting
Principle (net of taxes) --- --- 4,376,852 ---
-------------- ------------- ---------------- ---------------
Net Income $ 7,221,426 $ 3,584,092 $ 13,329,511 $ 6,603,902
============== ============= ================ ===============
Per share amounts -
Basic: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.26 $ 0.13 $ 0.65 $ 0.26
Cumulative Effect of Change in
Accounting Principle --- --- (0.16) ---
-------------- ------------- ---------------- ---------------
Net Income $ 0.26 $ 0.13 0.49 0.26
============== ============= ================ ===============
Diluted: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.26 $ 0.13 $ 0.65 $ 0.25
Cumulative Effect of Change in
Accounting Principle --- --- (0.16) ---
-------------- -------------- ---------------- ---------------
Net Income $ 0.26 $ 0.13 $ 0.49 $ 0.25
============== ============= ================ ===============
Weighted Average Shares Outstanding 27,311,170 26,566,357 27,277,156 25,723,981
============== ============= ================ ===============
See accompanying notes to consolidated financial statements.
5
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Accumulated
Additional Retained Other
Common Paid-in Treasury Earnings Comprehensive
Stock (1) Capital Stock (Deficit) 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
(75,567 shares)(2) 756 731,533 - - - 732,289
Employee stock purchase plan
(56,574 shares)(2) 566 413,947 - - - 414,513
Comprehensive income:
Net income (2) - - - 13,329,511 - 13,329,511
Change in fair value of
cash flow hedges, net of
income tax (2) - - - - (198,065) (198,065)
---------------
Total comprehensive income (2) - - - - - 13,131,446
---------- -------------- ------------- -------------- --------------- ---------------
Balance, June 30, 2003 (2) $ 279,439 $ 334,280,773 $ (7,558,093) $ 53,509,083 $ (376,118) $ 380,135,084
========== ============== ============= ============== =============== ===============
(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 June 30,
------------------------------------------------
2003 2002
--------------------- --------------------
Cash Flows From Operating Activities:
Net income $ 13,329,511 $ 6,603,902
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 30,588,312 28,302,274
Accretion of asset retirement obligation 417,286 ---
Deferred income taxes 9,460,394 3,585,238
Gain on asset disposition --- (7,332,668)
Other 211,966 577,360
Change in assets and liabilities -
Increase in accounts receivable, excluding
income taxes receivable (5,375,296) (61,937)
Increase in accounts payable and accrued liabilities 512,816 3,311,435
Decrease in income taxes receivable --- 600,000
--------------------- --------------------
Net Cash Provided by Operating Activities 53,521,841 35,585,604
--------------------- --------------------
Cash Flows From Investing Activities:
Additions to property and equipment (62,260,796) (102,631,965)
Proceeds from the sale of property and equipment 755,450 9,594,403
Net cash distributed as operator of
oil and gas properties (1,956,188) (6,749,977)
Net cash distributed as operator of partnerships
and joint ventures (254,929) (17,419,671)
Other (86,372) 195,180
--------------------- --------------------
Net Cash Used in Investing Activities (63,802,835) (117,012,030)
--------------------- --------------------
Cash Flows From Financing Activities:
Proceeds from long-term debt --- 200,000,000
Net proceeds from (payments of) bank borrowings 7,500,000 (134,000,000)
Net proceeds from issuances of common stock 1,090,996 31,248,720
Payments of debt issuance costs --- (6,165,559)
--------------------- --------------------
Net Cash Provided by Financing Activities 8,590,996 91,083,161
--------------------- --------------------
Net Increase (Decrease) in Cash and Cash Equivalents (1,689,998) 9,656,735
Cash and Cash Equivalents at Beginning of Period 3,816,107 2,149,086
--------------------- --------------------
Cash and Cash Equivalents at End of Period $ 2,126,109 $ 11,805,821
===================== ====================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized $ 12,831,097 $ 5,560,282
Cash paid during period for income taxes $ 130,791 $ 2,500
Non-cash investing activity:
Issuance of common stock in acquisitions $ --- $ 4,204,200
See accompanying notes to consolidated financial statements.
7
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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.
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.
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.
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.
8
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
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 unhedged
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.
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.
Earnings Per Share
Basic earnings per share ("Basic EPS") has 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
assumes, 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 six-month periods ended June 30, 2003 and 2002:
Three Months Ended June 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 $ 7,221,426 27,311,170 $ .26 $ 3,584,092 26,566,357 $ .13
Stock Options --- 108,323 --- 390,804
-------------- ------------ ------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 7,221,426 27,419,493 $ .26 $ 3,584,092 26,957,161 $ .13
-------------- ------------ -------------- ------------
9
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Six Months Ended June 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 $ 17,706,363 27,277,156 $ .65 $ 6,603,902 25,723,981 $ .26
Stock Options --- 85,976 --- 422,158
-------------- ------------ -------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 17,706,363 27,363,132 $ .65 $ 6,603,902 26,146,139 $ .25
-------------- ------------ -------------- ------------
Options to purchase approximately 2.9 million shares of common stock,
at an average exercise price of $16.66 were outstanding at June 30, 2003.
Approximately 1.6 million and 1.7 million options to purchase shares were
not included in the computation of Diluted EPS, for the three months and
six months ended June 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.
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. We had no such changes to
equity in the first six months of 2002. The components of accumulated other
comprehensive loss and related tax effects for the six months ended June
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 1,749,822 629,936 1,119,886
Effect of cash flow hedges settled
during the period (1,440,346) (518,525) (921,821)
---------------- --------------- ---------------
Balance at June 30, 2003 $ 587,684 $ 211,566 $ 376,118
================= =============== ================
10
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
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 June 30,
-----------------------------------------------
2003 2002
-------------------- ---------------------
Net Income: As Reported $7,221,426 $3,584,092
Stock-based employee compensation expense
determined under fair value method for
all awards, net of tax (1,041,376) (1,120,426)
-------------------- ---------------------
Pro Forma $6,180,050 $2,463,666
Basic EPS: As Reported $.26 $.13
Pro Forma $.23 $.09
Diluted EPS: As Reported $.26 $.13
Pro Forma $.23 $.09
Six Months Ended June 30,
-----------------------------------------------
2003 2002
-------------------- ---------------------
Net Income: As Reported $13,329,511 $6,603,902
Stock-based employee compensation expense
determined under fair value method for
all awards, net of tax (2,023,318) (2,210,485)
-------------------- ---------------------
Pro Forma $11,306,193 $4,393,417
Basic EPS: As Reported $.49 $.26
Pro Forma $.41 $.17
Diluted EPS: As Reported $.49 $.25
Pro Forma $.41 $.17
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
11
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
measured at its fair value. Special hedge accounting for qualifying hedges
would allow the gains and losses on derivatives to offset related results
on the hedged item in the income statements and 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 second quarters of 2003
and 2002, we recognized net losses of $382,396 and $105,597, respectively,
relating to our derivative activities. During the first six months of 2003
and 2002 we recognized net losses of $1,800,669 and $19,879, respectively,
relating to our derivative activities. Approximately $24,470 and $105,597
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 June 30, 2003, we had recorded $376,118 of derivative losses,
net of tax effects of $211,566, 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 six 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 June 30, 2003, we had entered into certain crude oil "collar"
financial transactions in effect through the July 2003 contract month. The
crude oil collars cover notional volumes of 90,000 barrels for the price
floors and 36,000 barrels for the price ceilings, with a floor price of $23
per barrel and a ceiling price of $28.50 per barrel. We also had in place
price floors in effect through the December 2003 contract month for natural
gas and through August 2003 for crude oil. The natural gas price floors
cover notional volumes of 2,475,000 MMBtu with a weighted average floor
price of $4.54 per MMBtu. The crude oil price floors cover notional volumes
of 120,000 barrels of oil, with a weighted average floor price of $25.50
per barrel. When we entered into the preceding transactions, with the
exception of several September and 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 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
income statement. The fair value of our derivatives are computed using the
Black-Scholes option pricing model and are periodically verified against
quotes from brokers. At June 30, 2003, the fair values of the derivative
instruments were as follows: crude oil collars represented a liability of
$105,237, natural gas price floors represented an asset of $268,675 and
crude oil price floors represented an asset of $13,538. 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 mandatory 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
12
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
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 six months ended June 30, 2003 417,286
Additions due to new wells and facilities construction 387,073
Reductions due to sold and abandoned wells (219,068)
----------------
Asset Retirement Obligation as of June 30, 2003 $ 9,519,611
----------------
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 six months ended June 30, 2002, had we adopted SFAS No. 143 effective
January 1, 2002.
Three Months Ended Six Months Ended
June 30, 2002 June 30, 2002
---------------------- --------------------
Net Income:
Actual - as reported $ 3,584,092 $ 6,603,902
Pro Forma $ 3,328,102 $ 2,482,313
Basic EPS:
Actual - as reported $ .13 $ .26
Pro Forma $ .13 $ .10
Diluted EPS:
Actual - as reported $ .13 $ .25
Pro Forma $ .12 $ .09
New Accounting Principle
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
VIE's created after January 15, 2003 and are effective beginning in the
third quarter of 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.
13
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
(3) LONG-TERM DEBT
Our long-term debt as of June 30, 2003 and December 31, 2002, is as
follows:
June 30, December 31,
2003 2002
------------------ -------------------
Bank Borrowings $ 7,500,000 $ ---
Senior Notes due 2009 124,312,331 124,271,973
Senior Notes due 2012 200,000,000 200,000,000
------------------ -------------------
Long-Term Debt $ 331,812,331 $ 324,271,973
------------------ -------------------
The unamortized discount on the Senior Notes due 2009 was $687,669 and
$728,027 at June 30, 2003 and December 31, 2002, respectively.
Bank Borrowings
Under our $300.0 million credit facility with a syndicate of nine
banks, at June 30, 2003 we had $7.5 million in outstanding borrowings and
no outstanding borrowings at year-end 2002. At June 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 June 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
$7.5 million borrowed at June 30, 2003, $5.0 million was borrowed at the
LIBOR rate plus applicable margin, which was 2.56%. 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 reconfirmed by our bank group with a $195.0 million borrowing base on
May 1, 2003. We requested that the commitment amount with our bank group be
reduced to $150 million effective May 9, 2003. Under the terms of the
credit facility, we can increase this commitment amount back to the total
amount of the borrowing base at our discretion, subject to the terms of the
credit agreement. The next borrowing base review is scheduled for November
2003.
Senior Notes Due 2009
At June 30, 2003, our Senior Notes due 2009 consisted of $125.0 million
of 10.25% Senior Subordinated Notes due 2009. The 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 the Senior Notes is payable
semiannually on February 1 and August 1. On or after August 1, 2004, the
Senior Notes are redeemable for cash at the option of Swift, with certain
restrictions, at 105.125% of principal, declining to 100% in 2007. Upon
certain changes in control of Swift, each holder of Senior Notes will have
the right to require us to repurchase the Senior Notes at a purchase price
in cash equal to 101% of the principal amount, plus accrued and unpaid
interest to the date of purchase. The terms of our Senior Notes include,
among other restrictions, a limit on repurchases by Swift of its common
stock. We are currently in compliance with the provisions of the indenture
governing the Senior Notes.
14
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Senior Notes Due 2012
At June 30, 2003, our Senior Notes due 2012 consisted of $200.0 million
of 9.375% Senior Subordinated Notes due 2012. The Senior Notes were issued
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 the Senior Notes is payable semiannually on May 1 and November 1. On or
after May 1, 2007, the Senior Notes are redeemable for cash at the option
of Swift, with certain restrictions, at 104.688% of principal, declining to
100% in 2010. In addition, prior to May 1, 2005, we may redeem up to 33.33%
of the Senior Notes with the proceeds of qualified offerings of our equity
at 109.375% of the principal amount of the Senior Notes, together with
accrued and unpaid interest. Upon certain changes in control of Swift, each
holder of Senior Notes will have the right to require us to repurchase the
Senior Notes at a purchase price in cash equal to 101% of the principal
amount, plus accrued and unpaid interest to the date of purchase. The terms
of our Senior Notes include, among other restrictions, a limit on
repurchases by Swift of its common stock. We are currently in compliance
with the provisions of the indenture governing the Senior Notes.
(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
from our treasury shares, and resulted in an increase to paid-in capital of
$1.0 million and a decrease in the value of our treasury stock 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 June 30, 2003, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $189.3 million. Approximately $157.6
million has been included in the proved properties portion of our oil and
gas properties, while $31.7 million is included as unproved properties. Our
functional currency in New Zealand is the U.S. dollar.
15
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2003 (UNAUDITED) AND DECEMBER 31, 2002
(6) SEGMENT INFORMATION
Below is a summary of financial information by country:
Three Months Ended June 30,
------------------------------------------------------------------------------------------
2003 2002
-------------------------------------------- --------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- -------------- ------------- ------------- ------------- -------------
Oil and gas sales $ 39,977,699 $ 10,931,551 $ 50,909,250 $ 31,273,908 $ 7,057,434 $ 38,331,342
Costs and Expenses:
Depreciation, depletion and
amortization 11,065,738 4,610,811 15,676,549 11,852,659 2,488,851 14,341,510
Accretion of asset retirement
obligation 148,082 53,821 201,903 --- --- ---
Oil and gas production 10,099,086 3,655,325 13,754,411 7,937,289 2,095,156 10,032,445
------------- -------------- ------------- ------------ ------------- -------------
Income from oil and gas operations $ 18,664,793 $ 2,611,594 $ 21,276,387 $ 11,483,960 $ 2,473,427 $ 13,957,387
============= ============== ============= ============= ============= =============
Six Months Ended June 30,
------------------------------------------------------------------------------------------
2003 2002
-------------------------------------------- --------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ -------------- ------------- ------------- ------------- -------------
Oil and gas sales $ 83,718,875 $ 22,040,674 $ 105,759,549 $ 53,747,288 $ 11,196,895 $ 64,944,183
Costs and Expenses:
Depreciation, depletion and
amortization 20,862,718 9,725,594 30,588,312 24,013,954 4,288,320 28,302,274
Accretion of asset retirement
obligation 297,523 119,763 417,286 --- --- ---
Oil and gas production 19,271,905 6,390,159 25,662,064 16,697,156 2,900,696 19,597,852
------------- -------------- ------------- ------------- ------------- -------------
Income from oil and gas operations $ 43,286,729 $ 5,805,158 $ 49,091,887 $ 13,036,178 $ 4,007,879 $ 17,044,057
============= ============== ============= ============= ============= =============
Property, Plant and Equipment, net $ 591,373,155 $ 167,176,684 $ 758,549,839 $ 544,996,156 $ 145,716,819 $ 690,712,975
============= ============== ============= ============= ============= =============
16
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 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
common stock valued at $4.2 million and 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 their 3.24% working interest in the four
TAWN petroleum mining licenses, for 300,000 shares of Swift Energy common
stock valued at $3.9 million and $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.
17
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 June 30, 2003 are as follows:
2003 2004 2005 2006 2007 Thereafter Total
---- ---- ---- ---- ---- ------------ -----
Non-cancelable operating lease
commitments $ 1,095,182 $ 2,191,495 $ 523,755 $ 190,676 $ 190,676 $ 186,834 $ 4,378,618
Capital commitments due to
pipeline operators 618,294 -- -- -- -- -- 618,294
Asset Retirement Obligation (1) 1,063,111 631,938 -- 3,414,115 231,246 4,179,201 9,519,611
Drilling Rig Commitments 1,612,750 1,612,750
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) -- -- 7,500,000 -- -- -- 7,500,0000
----------- ------------ ----------- ------------ ----------- ------------ ------------
$ 4,389,337 $ 2,823,433 $ 8,023,755 $ 3,604,791 $ 421,922 $329,366,035 $348,629,273
=========== ============ =========== ============ =========== ============ ============
(1) Amounts shown by year are the net present value, discounted to
June 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
Oil and 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 six 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 the above factors are
beyond our control.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 2003, we largely relied upon our net
cash provided by operating activities of $53.5 million and proceeds from
bank borrowings of $7.5 million to fund capital expenditures of $62.3
million. During the first six months of 2002, we relied upon our net cash
provided by operating activities of $35.6 million, net proceeds from the
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
$134.0 million, to fund capital expenditures of $102.6 million.
18
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Net Cash Provided by Operating Activities. For the first six months of
2003, net cash provided by our operating activities was $53.5 million,
representing a 50% increase as compared to $35.6 million generated during
the first six months of 2002. The $17.9 million increase was primarily due
to an increase of $40.8 million in oil and gas sales for the first half of
2003, attributable to higher commodity prices, 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 which is attributed to the
replacement of our bank borrowings in April 2002 with the Senior Notes that
carry a higher interest rate and a longer term.
Existing Credit Facility. We had $7.5 million in outstanding borrowings
under our credit facility at June 30, 2003, and no outstanding borrowings
at December 31, 2002. At June 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 reconfirmed by our bank group in May 2003 at $195.0 million. We
requested that the commitment amount with our bank group be reduced to $150
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 improved from a deficit of $17.1
million at December 31, 2002, to a deficit of $10.8 million at June 30,
2003. The improvement was primarily due to an increase in accounts
receivable from oil and gas sales due to higher commodity prices in the
2003 six month period.
Capital Expenditures. During the first six months of 2003, we used
$62.3 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
Domestic activities of $48.2 million as follows:
o $40.4 million for drilling costs, both development and exploratory;
o $6.5 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $1.0 million of producing property acquisitions; and
o $0.3 million spent primarily for computer equipment, software,
furniture, and fixtures.
New Zealand activities of $14.1 million as follows:
o $7.4 million for drilling costs, both development and exploratory;
o $3.3 million on prospect costs, principally seismic and geological
costs;
o $3.0 million for the construction of production facilities and
pipelines;
o $0.3 million for property acquisitions; and
o $0.1 million for fixed assets.
19
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
For the remaining six months of 2003, we expect to make capital
expenditures of approximately $88 million (depending on the level and costs
of actual drilling activities and on commodity prices). We currently
estimate total capital expenditures for 2003 to be approximately $150
million, which reflects the recent 15% increase in the Company's capital
budget. This increase was supported by recent operational results. Capital
expenditures for 2002 of $155.2 million were modestly higher. 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 2003, we believe that our 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.
We drilled or participated in drilling 36 domestic development wells
and two domestic exploratory wells in the first six months of 2003, 33 of
the development wells and both exploratory wells were in the Lake
Washington area. The two domestic exploratory wells and 30 of the domestic
development wells were successful. In New Zealand, the Kauri E-1 and
Kauri-F1 were successfully completed, while the Kauri-A4 began producing
into the Rimu Production Station (RPS).
During the second half of 2003, we anticipate drilling or participating
in the drilling of up to an additional 40 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 initial 3-D seismic work in Lake Washington.
In addition to the Kauri-E2, which is currently drilling, we plan on
drilling an additional two wells in New Zealand.
Our 2003 capital expenditures are 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 production to
increase by 7% to 13% 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.
RESULTS OF OPERATIONS - Three Months Ended June 30, 2003 and 2002
Revenues. Our revenues in the second quarter of 2003 increased by 31%
to $50.7 million compared to revenues of $38.6 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 $50.9 million in the second quarter of
2003 increased by 33%, or $12.6 million, from the level of those revenues
for the comparable 2002 period. Our net sales volumes of 13.3 Bcfe in the
second quarter of 2003 increased by 5%, or 0.6 Bcfe, over net sales volumes
in the comparable 2002 period. Average prices received for oil increased to
$27.97 per Bbl in the second quarter of 2003 from $25.11 per Bbl in the
comparable 2002 period. Average gas prices received increased to $3.47 per
Mcf in the second quarter of 2003 from $2.60 per Mcf in the 2002 period.
Average natural gas liquids (Ngl) prices increased to $15.81 per Bbl in the
second quarter of 2003 from $12.52 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. Our domestic Ngl volumes
decreased in the second quarter 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.
20
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
In the second quarter of 2003, our $12.6 million increase in oil and
gas sales resulted from:
oPrice variances that had a $10.9 million favorable impact on sales, of
which $6.2 million was attributable to the 34% increase in average gas
prices received and $4.7 million was attributable to the 21% increase
in the average combined oil and Ngl prices received; and
oVolume variances that had a $1.7 million favorable impact on sales,
with $1.1 million of the increase coming from the 0.4 Bcf increase in
gas sales volumes, and $0.6 million of the increase coming from the
31,000 Bbl increase in oil and Ngl 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:
Three Months Ended June 30,
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
----
---------------------------------------- ----------------------------------
2003 2002 2003 2002
---- ---- ---- ----
AWP Olmos $ 11.7 $ 9.0 2.1 2.5
Brookeland 4.1 3.5 1.1 1.2
Lake Washington 12.7 4.6 2.7 1.1
Masters Creek 6.3 9.3 1.5 2.6
Other 5.2 4.8 1.1 1.5
--------------------- --------------- --------------- ----------------
Total Domestic $ 40.0 $31.2 8.5 8.9
--------------------- --------------- --------------- ----------------
Rimu/Kauri 1.7 1.1 0.5 0.3
TAWN 9.2 6.0 4.3 3.5
--------------------- --------------- --------------- ----------------
Total New Zealand $ 10.9 $ 7.1 4.8 3.8
--------------------- --------------- --------------- ----------------
Total $ 50.9 $38.3 13.3 12.7
===================== =============== =============== ================
Our drilling efforts in the second quarter of 2003 have focused on Lake
Washington, AWP Olmos 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 June 30:
Domestic 569 278 3.8 8.9 $25.13 $12.77 $3.53
New Zealand 104 51 2.9 3.8 $25.01 $11.18 $1.36
--------- --------- --------- -----------
Total 673 329 6.7 12.7 $25.11 $12.52 $2.60
========= ========= ========= ===========
2003
Three Months Ended June 30:
Domestic 676 140 3.6 8.5 $28.25 $17.07 $5.15
New Zealand 146 71 3.5 4.8 $26.68 $13.36 $1.75
--------- --------- --------- -----------
Total 822 211 7.1 13.3 $27.97 $15.81 $3.47
========= ========= ========= ===========
21
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
During the second quarter of 2003, we recognized net losses of $0.4
million relating to our hedging activities, as compared to net losses of
$0.1 million in the 2002 period. This activity is recorded in "Price-risk
management and other, net" on the accompanying income statement.
Revenues from our oil and gas sales comprised 100% of net revenues for
the second quarter of 2003 and 99% of total revenues for the 2002 period.
Natural gas production made up 53% of our production volumes in both the
second quarter of 2003 and 2002.
Costs and Expenses. Our expenses in the second quarter of 2003
increased $6.6 million, or 20%, compared to the 2002 period expenses. The
majority of the increase was due to our increased oil and gas production
costs, both domestically and in New Zealand.
Our general and administrative expenses, net in the second quarter of
2003 increased $0.7 million, or 29%, 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, a reduction in reimbursement
from partnerships we managed as almost all of these partnerships have
liquidated, 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 $0.25 per Mcfe in
the second quarter of 2003 from $0.20 per Mcfe in the 2002 period. The
portion of supervision fees netted from general and administrative expenses
was $0.7 million for the second quarter of 2003 and $0.8 million for the
2002 period.
Depreciation, depletion, and amortization of our assets, or DD&A,
increased $1.3 million, or 9%, in the second quarter of 2003 from the 2002
period. Domestically, DD&A decreased $0.8 million due to decreased
production in the 2003 period, and higher reserve volumes that were added
primarily through our Lake Washington activities. In New Zealand, our
production increased in the 2003 period due primarily to TAWN area
production. Our DD&A rate per Mcfe of production was $1.18 in the second
quarter of 2003 and $1.13 in the 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 second quarter of 2003 associated with the adoption of
SFAS No. 143 implemented effective January 1, 2003.
Our production costs increased $3.7 million in the second quarter of
2003, or 37%, and were $1.04 per Mcfe and $0.79 per Mcfe in the second
quarter of 2003 and 2002, respectively. Due to the 26% increase in
production during the second quarter of 2003, our New Zealand operations
contributed $1.6 million of the cost increase in the period. Domestic
severance taxes increased $1.3 million in the second quarter of 2003, due
to higher commodity prices. Additionally, our production costs increased
due to significant Lake Washington facility enhancements and workovers
performed in several other areas during the second quarter, as well as
scheduled plant shutdowns for maintenance in New Zealand. The portion of
supervision fees netted from production costs was $0.5 million for the
second quarters of 2003 and 2002.
Interest expense on our Senior Notes issued in July 1999, including
amortization of debt issuance costs, totaled $3.3 million in both the
second quarter of 2003 and 2002. Interest expense on our Senior Notes
issued in April 2002, including amortization of debt issuance costs,
totaled $4.8 million in the second quarter of 2003 and $4.0 million in
2002. Interest expense on the credit facility, including commitment fees
and amortization of debt issuance costs, totaled $0.3 million in the second
quarter of 2003 and $0.9 million in the same period in 2002. The total
interest cost in the second quarter of 2003 was $8.4 million, of which $1.7
million was capitalized. The total interest cost in the second quarter of
2002 was $8.2 million, of which $2.1 million was capitalized. We capitalize
that portion of interest related to our unproved properties. The increase
in interest expense in the second quarter of 2003 was attributed to the
replacement of our bank borrowings in April 2002 with the Senior Notes that
carry a higher interest rate.
22
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Net Income. Our net income in the second quarter of 2003 of $7.2
million was 101% higher and Basic EPS of $0.26 were 96% higher than our
second quarter of 2002 net income of $3.6 million and Basic EPS of $0.13.
Our Diluted EPS in the second quarter of 2003 of $0.26 were also 96% higher
than our second quarter of 2002 Diluted EPS of $0.13. 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 - Six Months Ended June 30, 2003 and 2002
Revenues. Our revenues in the first six months of 2003 increased by 43%
to $104.2 million compared to revenues of $72.9 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 $105.8 million in the first six months of
2003 increased by 63%, or $40.8 million, from the level of those revenues
for the comparable 2002 period. Our net sales volumes of 26.1 Bcfe in the
first six months of 2003 increased by 5%, or 1.2 Bcfe, over net sales
volumes in the comparable 2002 period. Average prices received for oil
increased to $30.14 per Bbl in the first six months of 2003 from $22.37 per
Bbl in the comparable 2002 period. Average gas prices received increased to
$3.60 per Mcf in the first half of 2003 from $2.16 per Mcf in the 2002
period. Average natural gas liquids (Ngl) prices increased to $18.55 per
Bbl in the first six months of 2003 from $11.60 per Bbl in the comparable
2002 period. The increase in production during the 2003 period was from our
New Zealand and Lake Washington areas. Our domestic Ngl volumes decreased
in the first six 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 six months of 2003, our $40.8 million increase in oil and
gas sales resulted from:
oPrice variances that had a $38.5 million favorable impact on sales, of
which $21.1 million was attributable to the 66% increase in average
gas prices received and $17.4 million was attributable to the 49%
increase in the average combined oil and Ngl prices received; and
oVolume variances that had a $2.3 million favorable impact on sales,
with $3.2 million of the increase coming from the 1.5 Bcf increase in
gas sales volumes, partially offset by $0.9 million of the decrease
coming from the 50,000 Bbl decrease in oil and Ngl 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:
Six Months Ended June 30,
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- --------------------------------------- -----------------------------------
2003 2002 2003 2002
---- ---- ---- ----
AWP Olmos $24.2 $ 16.2 4.2 5.6
Brookeland 9.4 5.6 2.0 2.4
Lake Washington 23.9 6.9 4.8 1.9
Masters Creek 14.7 17.4 3.1 5.9
Other 11.6 7.6 2.1 2.7
--------------------- --------------- ---------------- -----------------
Total Domestic $ 83.8 $ 53.7 16.2 18.5
---------------------- --------------- ---------------- -----------------
Rimu/Kauri 3.2 1.1 1.0 0.4
TAWN 18.8 10.1 8.9 6.1
---------------------- --------------- ---------------- -----------------
Total New Zealand $ 22.0 $ 11.2 9.9 6.5
---------------------- --------------- ---------------- -----------------
Total $105.8 $ 64.9 26.1 25.0
====================== =============== ================ =================
23
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Our drilling efforts in the first half of 2003 have focused on Lake Washington,
AWP Olmos 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
- ----
Six Months Ended June 30:
Domestic 1,090 590 8.5 18.5 $22.30 $11.75 $2.65
New Zealand 176 89 4.8 6.5 $22.84 $10.59 $1.30
------------ --------- ---------- -----------
Total 1,266 679 13.3 25.0 $22.37 $11.60 $2.16
============ ========= ========== ===========
2003
- ----
Six Months Ended June 30:
Domestic 1,253 240 7.3 16.2 $30.35 $21.83 $5.59
New Zealand 258 145 7.5 9.9 $29.15 $13.12 $1.68
------------ --------- ---------- -----------
Total 1,511 385 14.8 26.1 $30.14 $18.55 $3.60
============ ========= ========== ===========
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 six months of 2003, we recognized net losses of $1.8
million relating to our hedging activities, as compared to net losses of
$0.1 million in the same 2002 period. This activity is recorded in
"Price-risk management and other, net" on the accompanying income
statement.
Revenues from our oil and gas sales comprised 101% of net revenues for
the first six months of 2003 and 89% of total revenues for the 2002 period.
Natural gas production made up 56% of our production volumes in the first
half of 2003 and 53% in the same 2002 period.
Costs and Expenses. Our expenses in the first six months of 2003
increased $14.2 million, or 23%, 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, and an increase in
interest expense due to replacement of our bank borrowings with our Senior
Notes during 2002.
Our general and administrative expenses, net in the first six months of
2003 increased $2.0 million, or 42%, 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, 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 $0.26 per Mcfe in
the first six 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 $1.4 million for the first half of 2003 and $1.5 million for
the same 2002 period.
24
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 $2.3 million, or 8%, in the first six months of 2003 from the
same 2002 period. Domestically, DD&A decreased $3.2 million due to
decreased production in the 2003 period, and higher reserve volumes that
were added primarily through our Lake Washington activities. In New
Zealand, our production increased in the first half of 2003 due primarily
to TAWN area production. Our DD&A rate per Mcfe of production was $1.17 in
the first half of 2003 and $1.13 in the same 2002 period, reflecting these
variations in per unit cost of reserves additions.
We recorded $0.4 million of accretion on our asset retirement
obligation in the first six months of 2003 associated with the adoption of
SFAS No. 143 implemented on January 1, 2003.
Our production costs per Mcfe produced increased $6.1 million in the
first six months of 2003, or 31%, and were $0.98 per Mcfe and $0.79 per
Mcfe in the first six months of 2003 and 2002, respectively. Due to the 55%
increase in production during the first six months of 2003, our New Zealand
operations contributed $3.5 million of the cost increase in the period.
Domestic severance taxes increased $3.0 million in the first six months of
2003, due to higher commodity prices. Additionally, our production costs
increased due to significant Lake Washington facility enhancements and
workovers performed in several other areas as well as scheduled plant
shutdowns for maintenance in New Zealand. The portion of supervision fees
netted from production costs was $1.0 million for the first six months of
both 2003 and 2002.
Interest expense on our Senior Notes issued in July 1999, including
amortization of debt issuance costs, totaled $6.6 million in both the first
six months of 2003 and 2002. Interest expense on our Senior Notes issued in
April 2002, including amortization of debt issuance costs, totaled $9.6
million and $4.0 million in the first six months of 2003 and 2002,
respectively. Interest expense on the credit facility, including commitment
fees and amortization of debt issuance costs, totaled $0.7 million in the
first half of 2003 and $2.9 million in the same period in 2002. The total
interest cost in the first six months of 2003 was $16.9 million, of which
$3.5 million was capitalized. The total interest cost in the first six
months of 2002 was $13.5 million, of which $3.5 million was capitalized. We
capitalize that portion of interest related to our unproved properties. The
increase in interest expense in the first half of 2003 was attributed to
the replacement of our bank borrowings in April 2002 with the Senior Notes
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 six months of 2003 of $13.3
million was 102% higher and Basic EPS of $0.49 were 94% higher than our
first six months of 2002 net income of $6.6 million and Basic EPS of $0.26.
Our Diluted EPS in the first six months of 2003 of $0.49 were also 95%
higher than our first six months of 2002 Diluted EPS of $0.25. 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 six months of
2003 and $0.2 million in the 2002
25
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 $0.2
million and $0.8 million in the first six months of 2003 and 2002,
respectively. These lower amounts reflect our continued transition away
from partnerships.
26
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.
27
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.
oPrice Floors - At July 31, 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 1,800,000 MMBtu, with a weighted average floor price of $4.55
per MMBtu. The crude oil price floors cover notional volumes of 210,000
barrels of oil, with a weighted average floor price of $27.07 per barrel.
oNew 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 dependant 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 revenues.
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 June 30, 2003, we had $7.5 million in
borrowings under our credit facility, which is subject to floating rates
and therefore susceptible to interest rate fluctuations. The result of a
10% fluctuation in the bank's base rate would constitute 40 basis points
and would not have a material adverse effect on our 2003 cash flows based
on this same level of borrowing.
28
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.
29
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 -
Our annual meeting of shareholders was held on May 13, 2003. At the record date,
27,284,710 shares of common stock were outstanding and entitled to one vote per
share upon all matters submitted at the meeting. At the annual meeting, three
nominees were elected to serve as Directors of Swift for three year terms to
expire at the 2006 annual meeting of shareholders:
FOR AGAINST ABSTENTIONS
--- ------- -----------
NOMINEES FOR DIRECTORS
Raymond E. Galvin 26,168,239 281,221 ---
Clyde W. Smith, Jr. 26,222,031 227,429 ---
Terry E. Swift 26,168,481 280,979 ---
The terms of directors A. Earl Swift, Henry C. Montgomery and Harold H. Withrow
expire at the 2004 annual meeting and the terms of Virgil N. Swift and G. Robert
Evans expire at the 2005 annual meeting.
At the annual meeting, shareholders also approved a proposal to amend the
Company's 2001 Omnibus Stock Compensation Plan to increase the number of shares
subject to the plan by 500,000 shares from 1.5 million shares to 2.0 million
shares. The result of the vote on this proposal was as follows:
FOR AGAINST ABSTENTIONS
--- ------- -----------
PROPOSAL
Amendment to the 2001 Omnibus
Stock Compensation Plan 21,783,932 4,113,548 551,979
Item 5. Other Information - N/A
Item 6. Exhibits & Reports on Form 8-K -
(a) Documents filed as part of the report
(3) Exhibits
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.
30
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 June 30, 2003,
which are incorporated herein by reference:
1. On May 7, 2003, the Company filed a Current Report on Form
8-K that reported under Item 7, "Financial Statements, Pro
Forma Financial Information and Exhibits", Item 9 "Regulation
FD" and Item 12, "Results of Operations and Financial
Conditions" relating to the press release announcement of
first quarter 2003 earnings.
31
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: August 13, 2003 By: (original signed by)
--------------------- ------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President,
Chief Financial Officer
Date: August 13, 2003 By: (original signed by)
--------------------- ------------------------------------
David W. Wesson
Controller and Principal Accounting
Officer
32
Exhibit 12
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
Six months
Years Ended December 31, ended June 30,
-------------------------------------------------------- ----------------
2002 2001 2000 2003
---------------- ------------------ ---------------- ----------------
GROSS G&A 26,074,408 25,974,568 23,793,995 7,070,649
NET G&A 10,564,849 8,186,654 5,585,487 3,556,548
INTEREST EXPENSE, NET 23,274,969 12,627,022 15,968,405 6,684,902
RENT EXPENSE 1,923,451 1,322,618 1,255,474 546,361
NET INCOME BEFORE TAXES 18,408,289 (34,192,333) 93,079,346 16,223,744
CAPITALIZED INTEREST 6,973,480 6,256,222 5,043,206 1,747,097
DEPLETED CAPITALIZED INTEREST 215,433 280,929 307,249 138,484
CALCULATED DATA
- -----------------------------------------------------
UNALLOCATED G&A (%) 40.52% 31.52% 23.47% 50.30%
NON-CAPITAL RENT EXPENSE 779,345 416,862 294,714 274,820
1/3 NON-CAPITAL RENT EXPENSE 259,782 138,954 98,238 91,607
FIXED CHARGES 30,508,231 19,022,198 21,109,849 8,523,606
EARNINGS 42,158,473 (21,145,428) 109,453,238 23,138,736
RATIO OF EARNINGS TO FIXED CHARGES (12/11) 1.38 --- 5.18 2.71
For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expe9nse, capitalized interest, amortization of debt
issuance costs and discounts, and that portion of non-capitalized rental expense
deemed to be the equivalent of interest. Earnings represents income before
income taxes from continuing operations before fixed charges. 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.
33
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: August 13, 2003 (original signed by)
------------------------------------
Terry E. Swift
President and
Chief Executive Officer
34
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: August 13, 2003 (original signed by)
------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President - Finance
Chief Financial Officer
35
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 June 30, 2003 (the "Report") of Swift Energy Company ("Swift") as
filed with the Securities and Exchange Commission on August 12, 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: August 13, 2003 (original signed by)
---------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President-Finance and
Chief Financial Officer
Dated: August 13, 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 June 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.
36