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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 March 31, 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 27,284,710 Shares
($.01 Par Value) (Outstanding at April 30, 2003)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets
- March 31, 2003 and December 31, 2002 3
Consolidated Statements of Income
- For the Three-month periods ended March 31, 2003 and 2002 5
Consolidated Statements of Stockholders' Equity
- March 31, 2003 and December 31, 2002 6
Consolidated Statements of Cash Flows
- For the Three-month periods ended March 31, 2003 and 2002 7
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 16
Item 3. Quantitative and Qualitative Disclosures About Market Risk 23
Item 4. Controls and Procedures 24
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 25
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. Exhibits and Reports on Form 8-K 25
SIGNATURES 26
CERTIFICATIONS 26
2
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
March 31, 2003 December 31, 2002
------------------------ -------------------------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 4,318,286 $ 3,816,107
Accounts receivable -
Oil and gas sales 25,678,344 17,360,716
Associated limited partnerships
and joint ventures 387,773 191,964
Joint interest owners 343,840 3,364,846
Other current assets 6,342,388 5,034,566
------------------------ -------------------------
Total Current Assets 37,070,631 29,768,199
------------------------ -------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 1,178,749,844 1,150,633,802
Unproved properties not being amortized 69,386,559 69,603,481
------------------------ -------------------------
1,248,136,403 1,220,237,283
Furniture, fixtures, and other equipment 9,870,932 9,595,944
------------------------ -------------------------
1,258,007,335 1,229,833,227
Less-Accumulated depreciation, depletion,
and amortization (519,199,697) (504,323,773)
------------------------ -------------------------
738,807,638 725,509,454
------------------------ -------------------------
Other Assets:
Deferred income taxes 1,874,962 2,680,585
Deferred charges 8,795,894 9,047,621
------------------------ -------------------------
10,670,856 11,728,206
------------------------ -------------------------
$ 786,549,125 $ 767,005,859
======================== =========================
See accompanying notes to consolidated financial statements.
3
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
March 31, 2003 December 31, 2002
------------------------ ------------------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 36,180,080 $ 43,028,708
Payable to associated limited partnerships --- 91,126
Undistributed oil and gas revenues 6,138,030 3,764,350
------------------------ ------------------------
Total Current Liabilities 42,318,110 46,884,184
------------------------ ------------------------
Long-Term Debt 329,991,985 324,271,973
Deferred Income Taxes 33,197,744 30,776,518
Asset Retirement Obligation 9,185,546 ---
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, 27,811,728 and 27,811,632
shares issued, and 27,284,710 and 27,201,509
shares outstanding, respectively 278,117 278,116
Additional paid-in capital 333,143,877 333,543,471
Treasury stock held, at cost, 527,018 and
610,123 shares, respectively (7,558,093) (8,749,922)
Retained earnings 46,287,657 40,179,572
Other comprehensive loss, net of taxes (295,818) (178,053)
------------------------ ------------------------
371,855,740 365,073,184
------------------------- ------------------------
$ 786,549,125 $ 767,005,859
======================== ========================
See accompanying notes to consolidated financial statements.
4
SWIFT ENERGY COMPANY
Consolidated Statements of Income
(UNAUDITED)
Three months ended
-----------------------------------------------
03/31/03 03/31/02
---------------------- --------------------
Revenues:
Oil and gas sales $ 54,850,299 $ 26,612,841
Fees from limited partnerships
and joint ventures 8,055 4,625
Interest income 37,692 5,762
Gain on asset disposition --- 7,332,668
Price-risk management and other, net (1,396,053) 398,181
---------------------- --------------------
53,499,993 34,354,077
---------------------- --------------------
Costs and Expenses:
General and administrative, net 3,556,548 2,274,027
Depreciation, depletion and amortization 14,911,763 13,960,764
Accretion of asset retirement obligation 215,383 ---
Oil and gas production 11,907,653 9,565,407
Interest expense, net 6,684,902 3,879,804
---------------------- --------------------
37,276,249 29,680,002
---------------------- --------------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle 16,223,744 4,674,075
Provision for Income Taxes 5,738,807 1,654,265
---------------------- --------------------
Income Before Cumulative Effect of Change
in Accounting Principle 10,484,937 3,019,810
Cumulative Effect of Change in Accounting
Principle (net of taxes) 4,376,852 ---
---------------------- --------------------
Net Income $ 6,108,085 $ 3,019,810
====================== ====================
Per share amounts -
Basic: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.38 $ 0.12
Cumulative Effect of Change in
Accounting Principle (0.16) ---
---------------------- --------------------
Net Income $ 0.22 $ 0.12
====================== ====================
Diluted: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.38 $ 0.12
Cumulative Effect of Change in
Accounting Principle (0.16) ---
---------------------- --------------------
Net Income $ 0.22 $ 0.12
====================== ====================
Weighted Average Shares Outstanding 27,243,142 24,881,604
====================== ====================
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 (399,594) 1,191,829 - - 792,236
Comprehensive income:
Net income (2) - - - 6,108,085 - 6,108,085
Change in fair value of
cash flow hedges, net of
income tax (2) - - - - (117,765) (117,765)
-------------
Total comprehensive income (2) - - - - - 5,990,320
---------- --------------- ------------- ------------- --------------- -------------
Balance, March 31, 2003 (2) $ 278,117 $ 333,143,877 $ (7,558,093) $ 46,287,657 $ (295,818) $ 371,855,740
========== =============== ============= ============= =============== =============
(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 March 31,
-----------------------------------------------
2003 2002
--------------------- -------------------
Cash Flows From Operating Activities:
Net income $ 6,108,085 $ 3,019,810
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 14,911,763 13,960,764
Accretion of asset retirement obligation 215,383 ---
Deferred income taxes 5,738,807 1,653,112
Gain on asset disposition --- (7,332,668)
Other 291,780 161,479
Change in assets and liabilities -
(Increase) decrease in accounts receivable, excluding
income taxes receivable (7,076,900) 117,972
Increase (decrease) in accounts payable and accrued
liabilities 2,233,028 (1,346,838)
Decrease in income taxes receivable --- 600,000
--------------------- -------------------
Net Cash Provided by Operating Activities 26,798,798 10,833,631
--------------------- -------------------
Cash Flows From Investing Activities:
Additions to property and equipment (26,335,122) (83,041,243)
Proceeds from the sale of property and equipment 551,263 7,522,775
Net cash distributed as operator of
oil and gas properties (5,889,986) (10,591,271)
Net cash distributed as operator of partnerships
and joint ventures (286,935) (23,089,369)
Other (35,839) 33,082
--------------------- -------------------
Net Cash Used in Investing Activities (31,996,619) (109,166,026)
--------------------- -------------------
Cash Flows From Financing Activities:
Net proceeds from bank borrowings 5,700,000 97,000,000
Net proceeds from issuances of common stock --- 346,908
Payments of debt issuance costs --- (347,185)
--------------------- -------------------
Net Cash Provided by Financing Activities 5,700,000 96,999,723
--------------------- -------------------
Net Increase (Decrease) in Cash and Cash Equivalents 502,179 (1,332,672)
Cash and Cash Equivalents at Beginning of Period 3,816,107 2,149,086
--------------------- -------------------
Cash and Cash Equivalents at End of Period $ 4,318,286 $ 816,414
===================== ===================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized $ 4,939,154 $ 6,934,950
Cash paid during period for income taxes $ --- $ ---
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
MARCH 31, 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
MARCH 31, 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 periods ended March 31, 2003 and 2002:
Three Months Ended March 31,
-----------------------------------------------------------------------------------
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 $ 10,484,937 27,243,142 $ .38 $ 3,019,810 24,881,604 $ .12
Stock Options --- 66,734 --- 465,061
------------- ----------- ------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 10,484,937 27,309,876 $ .38 $ 3,019,810 25,346,665 $ .12
------------- ----------- ------------- ------------
9
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
MARCH 31, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Options to purchase approximately 3.0 million shares of common stock,
at an average exercise price of $16.59 were outstanding at March 31, 2003.
Approximately 1.7 million options to purchase shares were not included in
the computation of Diluted EPS, for the three months ended March 31, 2003,
because the options were antidilutive as 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 in
the first quarter of 2002. The components of accumulated other
comprehensive loss and related tax effects for the three months ended
March 31, 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 1,295,882 466,517 829,365
Effect of cash flow hedges settled
during the period (1,111,875) (400,275) (711,600)
---------------- --------------- ----------------
Balance at March 31, 2003 $ 462,215 $ 166,397 $ 295,818
================ =============== ================
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 March 31,
----------------------------------------------
2003 2002
--------------------- ------------------
Net Income: As Reported $6,108,085 $3,019,810
Stock-based employee compensation
expense determined under fair value
method for all awards, net of tax (981,942) (1,090,059)
--------------------- ------------------
Pro Forma $5,126,143 $1,929,751
Basic EPS: As Reported $.22 $.12
Pro Forma $.19 $.08
Diluted EPS: As Reported $.22 $.12
Pro Forma $.18 $.08
Pro forma compensation cost reflected above may not be representative
of the cost to be expected in future periods.
10
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
MARCH 31, 2003 (UNAUDITED) AND DECEMBER 31, 2002
Price Risk Management Activities
We follow SFAS No. 133 which requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. The statement also establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in
the balance sheet as either an asset or a liability measured at its fair
value. Special hedge accounting for qualifying hedges would allow the
gains and losses on derivatives to offset related results on the hedged
item in the income statements and would require that a company formally
document, designate, and assess the effectiveness of transactions that
receive hedge accounting. SFAS No. 133, as amended by SFAS No. 137 and
SFAS No. 138, was adopted by us effective January 1, 2001.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the
purchase of protection price floors and collars. During the first three
months of 2003 and 2002 we recognized net losses of $1,418,274 and net
gains of $85,718, respectively, relating to our derivative activities.
Approximately $86,283 of the losses recognized in the 2003 period were
unrealized, as the contracts were still open, while all of the gains
recognized in the comparative 2002 period were realized. This activity is
recorded in "Price-risk management and other, net" on the accompanying
statements of income. At March 31, 2003, we had recorded $295,818 of
derivative losses, net of tax effects of $166,397, 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 three 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 March 31, 2003, we had entered into certain "collar" financial
transactions in effect through the June 2003 contract month. The natural
gas collars cover notional volumes of 400,000 MMBtu for the price floors
and 160,000 MMBtu for the price ceilings, with a weighted average floor
price of $3.00 per MMBtu and a weighted average ceiling price of $5.50 per
MMBtu. The crude oil collars cover notional volumes of 300,000 barrels for
the price floors and 120,000 barrels for the price ceilings, with a
weighted average floor price of $22.70 per barrel and a weighted average
ceiling price of $30.66 per barrel. We also had in place price floors in
effect through the October 2003 contract month for natural gas and May
2003 for crude oil. The natural gas price floors cover notional volumes of
2,700,000 MMBtu with a weighted average floor price of $4.36 per MMBtu.
The crude oil price floors cover notional volumes of 230,000 barrels of
oil, with a weighted average floor price of $26.29 per barrel. As a method
of limiting downside risk associated with our crude oil collars, we have
calls in effect through the June 2003 contract month. The crude oil calls
cover notional volumes of 120,000 barrels of oil, with a weighted average
call price of $50 per barrel of oil. When we entered into the preceding
transactions, with the exception of the April crude oil floors, they were
designated as a hedge of the variability in cash flows associated with the
forecasted sale of its 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 March 31, 2003, the fair values of the derivative
instruments were as follows: natural gas collars represented a liability
of $20,479, crude oil collars represented a liability of $80,760, natural
gas price floors represented an asset of $397,172, crude oil price floors
represented an asset of $64,902 and crude oil calls represented an asset
of $1,169. These instruments are recognized on the balance sheet in "Other
current assets."
11
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
MARCH 31, 2003 (UNAUDITED) AND DECEMBER 31, 2002
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 is recorded as a Cumulative Effect
of Change in Accounting Principle. 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, and a net loss of $0.9 million,
which compares to our actual net income in the first quarter of 2002 of
$3.0 million. Our pro forma first quarter 2002 loss per share for both
Basic EPS and Diluted EPS, assuming adoption of SFAS No. 143 effective
January 1, 2002, would have been $(0.03) per share. Our actual first
quarter 2002 Basic and Diluted EPS was $0.12 per share.
(3) LONG-TERM DEBT
Our long-term debt as of March 31, 2003 and December 31, 2002, is as
follows (in thousands):
March 31, December 31,
2003 2002
----------------- -------------------
Bank Borrowings $ 5,700 $ ---
Senior Notes due 2009 124,292 124,272
Senior Notes due 2012 200,000 200,000
----------------- -------------------
Long-Term Debt $ 329,992 $ 324,272
----------------- -------------------
The unamortized discount on the Senior Notes due 2009 was approximately
$708,000 and $728,000 at March 31, 2003 and December 31, 2002
respectively.
Bank Borrowings
Under our $300.0 million credit facility with a syndicate of nine banks
at March 31, 2003 we had $5.7 million in outstanding borrowings and no
outstanding borrowings at year-end 2002. At March 31, 2003, the credit
facility consisted of a $300.0 million secured revolving line of credit
with a $195.0 million borrowing base. The interest rate is either (a) the
lead bank's prime rate (4.25 % at March 31, 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 $5.7 million borrowed at March 31, 2003, $5.0 million was
borrowed at the LIBOR rate plus applicable margin, which was 2.59%. 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
12
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
MARCH 31, 2003 (UNAUDITED) AND DECEMBER 31, 2002
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 in May 2003 with the same $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 scheduled borrowing base review is November
2003.
Senior Notes Due 2009
Our Senior Notes due 2009 at March 31, 2003, consist of $125,000,000 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.
Senior Notes Due 2012
Our Senior Notes due 2012 at March 31, 2003, consist of $200,000,000 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.
13
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
MARCH 31, 2003 (UNAUDITED) AND DECEMBER 31, 2002
(5) FOREIGN ACTIVITIES
As of March 31, 2003, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $181.3 million. Approximately $151.3
million has been included in the proved properties portion of our oil and
gas properties, while $30.0 million is included as unproved properties.
Our functional currency in New Zealand is the U.S. dollar.
(6) SEGMENT INFORMATION
Below is a summary of financial information by country:
Three Months Ended March 31,
-----------------------------------------------------------------------------------------------
2003 2002
---------------------------------------------- ---------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- -------------- ------------- ------------- ------------- -------------
Oil and gas sales $ 43,741,176 $ 11,109,123 $ 54,850,299 $ 22,473,381 $ 4,139,460 $ 26,612,841
Costs and Expenses:
Depreciation, depletion and
amortization 9,796,980 5,114,783 14,911,763 12,161,295 1,799,469 13,960,764
Accretion of asset retirement
obligation 149,441 65,942 215,383 --- --- ---
Oil and gas production 9,172,819 2,734,834 11,907,653 8,759,867 805,540 9,565,407
------------- -------------- ------------- ------------- ------------- -------------
Income from oil and gas operations $ 24,621,936 $ 3,193,564 $ 27,815,500 $ 1,552,219 $ 1,534,451 $ 3,086,670
============= ============== ============= ============= ============= =============
Property, Plant and Equipment, net $ 575,025,253 $ 163,782,385 $ 738,807,638 $ 543,218,105 $ 142,681,619 $ 685,899,724
============= ============== ============= ============= ============= =============
(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
14
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
MARCH 31, 2003 (UNAUDITED) AND DECEMBER 31, 2002
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.
15
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 this period.
CONTRACTUAL COMMITMENTS AND OBLIGATIONS
Our contractual commitments for the remainder of 2003 and next four
years and thereafter as of March 31, 2003 are as follows:
2003 2004 2005 2006 2007 Thereafter Total
---- ---- ---- ---- ---- ---------- -----
Non-cancelable operating lease
commitments $ 1,642,772 $ 2,191,495 $ 523,755 $ 190,676 $ 190,676 $ 186,834 $ 4,926,208
Capital commitments due to
pipeline operators 782,959 -- -- -- -- -- 782,959
Asset Retirement Obligation (1) 1,138,635 688,785 -- 3,238,721 63,240 4,056,165 9,185,546
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) -- -- 5,700,000 -- -- -- 5,700.0000
----------- ----------- ----------- ----------- ----------- ------------- -------------
$ 3,564,366 $ 2,880,280 $ 6,223,755 $ 3,429,397 $ 253,916 $ 329,242,999 $ 345,594,713
=========== =========== =========== =========== =========== ============= =============
(1) Amounts shown by year are the net present value, discounted to
March 31, 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 prior to the war between the United States
and Iraq, along with other factors, have caused the price of oil to
increase significantly in the first quarter 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. 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 three months of 2003, we relied upon our net cash
provided by operating activities of $26.8 million to fund capital
expenditures of $26.3 million. During the first three months of 2002, we
primarily relied upon bank borrowings of $97.0 million and cash provided
by operating activities of $10.8 million to fund capital expenditures of
$83.0 million.
16
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 three months
of 2003, net cash provided by our operating activities was $26.8 million,
representing a 147% increase as compared to $10.8 million generatedduring
the first three months of 2002. The $16.0 million increase was primarily
due to an increase of $28.2 million in oil and gas sales in the 2003
period, attributable to higher commodity prices, offset in part by cost
increases principally related to our increased activities in New Zealand.
Existing Credit Facility. We had $5.7 million in outstanding borrowings
under our credit facility at March 31, 2003, and no outstanding borrowings
at December 31, 2002. At March 31, 2003, our credit facility consisted of
a $300.0 million revolving line of credit with a $195.0 million borrowing
base. The borrowing base is re-determined at least every six months and
was reconfirmed by our bank group in May 2003 with the same $195.0 million
borrowing base. 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 $5.2 million at March 31,
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 period.
Capital Expenditures. During the first three months of 2003, we used
$26.3 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
Domestic activities of $21.0 million as follows:
o $16.6 million for development drilling costs;
o $3.7 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $0.5 million of producing property acquisitions; and
o $0.2 million spent primarily for computer equipment, software,
furniture and fixtures.
New Zealand activities of $5.3 million as follows:
o $2.8 million for drilling costs, both development and exploratory;
o $1.7 million on prospect costs, principally seismic and geological
costs;
o $0.4 million for the construction of production facilities;
o $0.3 million for property acquisitions; and
o $0.1 million for fixed assets.
17
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
For the remaining nine months of 2003, we expect to make capital
expenditures of approximately $74 to $104 million (depending on the level
and costs of actual drilling activities and on commodity prices),
including investments in all areas in which investments were made during
the first three months of the year. We currently estimate total capital
expenditures for 2003 to be between $115 and $130 million, a decrease from
2002 capital expenditures of $155.2 million. Depending on a number of
factors, such as commodity pricing, production levels and the level and
success of planned non-core property dispositions, our internally
generated cash flows are expected to fund a majority of these
expenditures. Although current plans do not call for extensive use of our
bank credit facility in 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 required.
We drilled or participated in drilling 19 domestic development wells in
the first three months of 2003, all in the Lake Washington area. Thirteen
were successful. In New Zealand, the Kauri-F1 was successfully completed
to the shallow Manutahi sandstones, while we continue to evaluate the
Kauri-A4 and Kauri-A1, which underwent fracture stimulation, and the
Rimu-A2A, which underwent CO2 treatment.
For the remaining nine months of 2003, we anticipate drilling or
participating in the drilling of an additional 50 to 60 domestic wells
throughout our core and emerging growth areas, with an emphasis in the
Lake Washington area. In New Zealand, we plan on drilling two wells in
Kauri sand, several Manutahi wells and one to two exploratory wells.
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 12% 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
flatter 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 March 31, 2003 and 2002
Revenues. Our revenues in the first quarter of 2003 increased by 56%
compared to revenues in the same period in 2002, primarily due to
increases in oil and gas prices.
Oil and gas sales revenues in the first quarter of 2003 increased by
106%, or $28.2 million, from the level of those revenues for the
comparable 2002 period. Our net sales volumes in the first 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 $32.73 per Bbl
in the first quarter of 2003 from $19.26 per Bbl in the comparable 2002
period. Average gas prices received increased to $3.71 per Mcf in the
first quarter of 2003 from $1.72 per Mcf in the 2002 period. Average
natural gas liquids (Ngl) prices increased to $21.90 per Bbl in the first
quarter of 2003 from $10.74 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
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. Limited sales
quantities skewed the domestic sales price of Ngls in the first quarter of
2003, and we do not expect to realize these high prices in future periods.
18
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
In the first quarter of 2003, our $28.2 million increase in oil and gas
sales resulted from:
oPrice variances that had a $27.7 million favorable impact on sales, of
which $15.2 million was attributable to the 115% increase in average
gas prices received and $12.5 million was attributable to the 90%
increase in the average combined oil and Ngl prices received; and
oVolume variances that had a $0.5 million favorable impact on sales,
with $1.8 million of increases coming from the 1.1 Bcf increase in gas
sales volumes, offset by $1.3 million of decreases coming from the
80,000 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 four
domestic core areas and New Zealand:
Three Months Ended March 31,
----------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- --------------------------------------- -----------------------------------
2003 2002 2003 2002
---- ---- ---- ----
AWP Olmos $ 12.5 $ 7.2 2.0 3.1
Brookeland 4.3 2.5 0.8 1.1
Lake Washington 11.1 2.2 2.0 0.7
Masters Creek 9.4 8.4 1.7 3.3
Other 6.5 2.2 1.2 1.5
--------------------- --------------- ---------------- ----------------
Total Domestic $ 43.8 $22.5 7.7 9.7
--------------------- --------------- ---------------- ----------------
Rimu/Kauri 1.5 0.2 0.5 0.1
TAWN 9.6 3.9 4.7 2.5
--------------------- --------------- ---------------- ----------------
Total New Zealand $ 11.1 $ 4.1 5.2 2.6
--------------------- --------------- ---------------- ----------------
Total $ 54.9 $ 26.6 12.9 12.3
===================== =============== ================ ================
Our drilling efforts in the first three months of 2003 have focused on Lake
Washington 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 March 31:
Domestic 522 312 4.7 9.7 $19.21 $10.85 $1.94
New Zealand 72 38 1.9 2.6 $19.67 $9.81 $1.21
------------ --------- ---------- -----------
Total 594 350 6.6 12.3 $19.26 $10.74 $1.72
============ ========= ========== ===========
2003
- ----
Three Months Ended March 31:
Domestic 578 100 3.6 7.7 $32.80 $28.47 $6.03
New Zealand 112 73 4.1 5.2 $32.36 $12.89 $1.62
------------ --------- ---------- -----------
Total 690 173 7.7 12.9 $32.73 $21.90 $3.71
============ ========= ========== ===========
19
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
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 quarter of 2003, we recognized net losses of $1.4
million relating to our derivative activities, as compared to net gains of
$0.1 million in the 2002 period. In the first quarter of 2003, $0.1
million of the losses were unrealized, while all of the gains recognized
in the 2002 period were realized. This activity is recorded in "Price-risk
management and other, net" on the accompanying income statement.
Revenues from our oil and gas sales comprised 103% of total revenues
for the first quarter of 2003 and 77% of total revenues for the 2002
period. Natural gas production made up 60% of our production volumes in
the first quarter of 2003 and 54% in the 2002 period.
Costs and Expenses. Our expenses in the first quarter of 2003 increased
$7.6 million, or 26%, compared to the 2002 period expenses. The majority
of the increase was due to our increased activities 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 quarter of
2003 increased $1.3 million, or 56%, 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 $0.28
per Mcfe in the first quarter of 2003 from $0.19 per Mcfe in the 2002
period. The portion of supervision fees netted from general and
administrative expenses was $0.7 million for the first quarter of 2003 and
$0.8 million for the 2002 period.
Depreciation, depletion, and amortization of our assets, or DD&A,
increased $1.0 million, or 7%, in the first quarter of 2003 from the 2002
period. Domestically, DD&A decreased $2.4 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 $1.16 in the first
quarter of 2003 and $1.14 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 first quarter of 2003 associated with the adoption of
SFAS No. 143 effective January 1, 2003.
Our production costs per Mcfe produced increased $2.3 million in the
first quarter of 2003, or 24%, and were $0.93 per Mcfe and $0.78 per Mcfe
in the first quarter of 2003 and 2002, respectively. Due to the 97%
increase in production during the first quarter of 2003, our New Zealand
operations contributed $1.9 million of the cost increase in the period.
Domestic severance taxes increased $1.9 million in the first quarter of
2003, due to higher commodity prices, while our controllable lease
operating cost decreased by $1.5 million in the 2003 period. The portion
of supervision fees netted from production costs was $0.5 million for the
first 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
first quarter of 2003 and 2002. Interest expense on our Senior Notes
issued in
20
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
April 2002, including amortization of debt issuance costs, totaled $4.8
million in the first quarter of 2003. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance
costs, totaled $0.4 million in the 2003 first quarter and $2.0 million in
the same period in 2002. The total interest cost in the first quarter of
2003 was $8.5 million, of which $1.8 million was capitalized. The total
interest cost in the first quarter of 2002 was $5.3 million, of which $1.4
million was capitalized. We capitalize that portion of interest related to
our unproved properties. The increase in interest expense in the first
three months of 2003 was attributed to the replacement of our bank
borrowings in April 2002 with the Senior Notes that carry a higher
interest rate.
As discussed in Note 1 to the Consolidated Financial Statements, we
adopted SFAS No. 143 on January 1, 2003. Our adoption of SFAS No. 143
resulted in a one-time net of taxes charge of $4.4 million, which is
recorded as a "Cumulative Effect of Change in Accounting Principle" in the
consolidated statement of income. This statement requires us 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, we either settle the obligation for its
recorded amount or incur 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.
Net Income Our net income in the first quarter of 2003 of $6.1 million
was 102% higher and basic earnings per share ("Basic EPS") of $0.22 were
83% higher than our first quarter of 2002 net income of $3.0 million and
Basic EPS of $0.12. Our earnings per diluted share ("Diluted EPS") in the
first quarter of 2003 of $0.22 were also 83% higher than our first quarter
of 2002 earnings per diluted share of $0.12. These amounts increased in
the 2003 period as oil and gas sales increased due to higher commodity
prices.
Related-Party Transactions
We have been the operator of a number of properties owned by our
affiliated limited partnerships and, accordingly, charge these entities
operating fees. The operating fees charged to the partnerships were
approximately $0.1 million in both the first three months of 2003 and
2002, 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 $0.1
million and $0.4 million in the first three months of 2003 and 2002,
respectively.
21
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Forward Looking Statements
The statements contained in this report that are not historical facts
are forward-looking statements as that term is defined in Section 21E of
the Securities and Exchange Act of 1934, as amended. Such forward-looking
statements may pertain to, among other things, financial results, capital
expenditures, drilling activity, development activities, cost savings,
production efforts and volumes, hydrocarbon reserves, hydrocarbon prices,
liquidity, regulatory matters and competition. Such forward-looking
statements generally are accompanied by words such as "plan," "future,"
"estimate," "expect," "budget," "predict," "anticipate," "projected,"
"should," "believe" or other words that convey the uncertainty of future
events or outcomes. Such forward-looking information is based upon
management's current plans, expectations, estimates and assumptions, upon
current market conditions, and upon engineering and geologic information
available at this time, and is subject to change and to a number of risks
and uncertainties, and therefore, actual results may differ materially.
Among the factors that could cause actual results to differ materially
are: volatility in oil and gas prices; fluctuations of the prices received
or demand for our oil and natural gas; the uncertainty of drilling results
and reserve estimates; operating hazards; requirements for capital;
general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and government
regulations; as well as the risks and uncertainties discussed herein, and
set forth from time to time in our other public reports, filings and
public statements. Also, because of the volatility in oil and gas prices
and other factors, interim results are not necessarily indicative of those
for a full year.
22
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 April 30, 2003, we had price floors in place effective
through the contract month of October 2003 for natural gas and May 2003
for crude oil. The natural gas price floors cover notional volumes of
2,250,000 MMBtu, with a weighted average floor price of $4.36 per MMBtu.
The crude oil price floors cover notional volumes of 30,000 barrels of
oil, with a weighted average floor price of $26.55 per barrel.
oParticipating Collars - At April 30, 2003, we had certain "collar"
financial transactions in place effective through the June 2003 contract
month. The natural gas collars cover notional volumes of 200,000 MMBtu,
with a floor price of $3.00 per MMBtu and ceiling price of $5.50 per
MMBtu, plus 60% participation by us in prices realized above the ceiling.
The crude oil collars cover notional volumes of 210,000 barrels of oil,
with floor prices ranging from $21.00 to $26.00 per barrel and ceiling
prices ranging from $29.04 to $35.05 per barrel, plus 60% participation by
us in prices realized above these ceilings.
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 the loss of any single oil or gas
customer would materially affect our revenues.
23
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-14(c) and 15d-14(c) under the Securities Exchange Act of 1934
(the "Exchange Act') as of a date within 90 days before the filing of this
report. Based on that evaluation, they have concluded that such disclosure
controls and procedures are effective in alerting them on a timely basis
to material information relating to the Company required under the
Exchange Act to be disclosed in this quarterly report.
There were no significant changes in the Company's internal controls
that could significantly affect such controls subsequent to the date of
their evaluation.
24
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation incidental to the Company's business.
Item 2. Changes in Securities and Use of Proceeds - N/A
Item 3. Defaults Upon Senior Securities - N/A
Item 4. Submission of Matters to a Vote of Security Holders - N/A
Item 5. Other Information - N/A
Item 6. Exhibits & Reports on Form 8-K -
(a) Documents filed as part of the report
(3) Exhibits
3.1 Second Amended and Restated Bylaws of Swift Energy Company
12 Swift Energy Company Ratio of Earnings to Fixed Charges.
99.1 Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K filed during the quarter ended March 31, 2003,
which are incorporated herein by reference: - None
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SWIFT ENERGY COMPANY
(Registrant)
Date: May 13, 2003 By: (original signed by)
----------------- --------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President,
Chief Financial Officer
Date: May 13, 2003 By: (original signed by)
----------------- --------------------------------------
David W. Wesson
Controller and Principal Accounting
Officer
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-14 and 15d-14) for Swift Energy and we have:
a) designed such disclosure controls and procedures 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 as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
26
5. Swift Energy's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Swift Energy's auditors and the audit committee
of Swift Energy's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect Swift Energy's ability to record, process,
summarize and report financial data and have identified for Swift Energy's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in Swift Energy's internal controls; and
6. Swift Energy's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 13, 2003
(original signed by)
--------------------------------------------
Terry E. Swift
President and Chief Executive Officer
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-14 and 15d-14) for Swift Energy and we have:
a) designed such disclosure controls and procedures 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 as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. Swift Energy's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Swift Energy's auditors and the audit committee
of Swift Energy's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect Swift Energy's ability to record, process,
summarize and report financial data and have identified for Swift Energy's
auditors any material weaknesses in internal controls; and
27
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in Swift Energy's internal controls; and
6. Swift Energy's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 13, 2003
(original signed by)
--------------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President,
Chief Financial Officer
28
Exhibit 3.1
29
SECOND AMENDED AND RESTATED BYLAWS OF
SWIFT ENERGY COMPANY
ARTICLE I
SHAREHOLDERS
1. ANNUAL MEETING. The annual meeting of shareholders for the purpose
of electing directors shall be held on such date and time as may be fixed
from time to time by the board of directors and stated in the notice of
the meeting. Any business may be transacted at an annual meeting, except
as otherwise provided by law or by these Bylaws.
2. SPECIAL MEETING. A special meeting of shareholders may be called at
any time by the president or secretary at the request in writing of the
holders of at least ten percent (10%) of the outstanding stock entitled to
be voted at such meeting, or a special meeting of shareholders may be
called at any time by a majority of the members of the board of directors
who are "Continuing Directors," being those directors then in office who
have been or will have been directors for the two year period ending on
the date notice of the meeting or written consent to take such action is
first provided to shareholders, or those directors who have been nominated
for election or elected to succeed such directors by a majority of such
directors, by the chairman of the board, by the vice chairman of the board
or by the president. Only such business shall be transacted at a special
meeting as may be stated or indicated in the notice of such meeting.
3. MANNER AND PLACE OF MEETING. The annual meeting of shareholders may
be held in any manner permitted by law or these Bylaws at any place within
or without the State of Texas designated by the board of directors.
Special meetings of shareholders may be held in any manner permitted by
law or these Bylaws at any place within or without the State of Texas
designated by the chairman of the board or the President, if he shall call
the meeting, or the board of directors, if they shall call the meeting.
Any meeting may be held at any place within or without the State of Texas
designated in a waiver of notice of such meeting held at the principal
office of the corporation unless another place is designated for meetings
in the manner provided herein. Subject to the provisions herein for notice
of meetings, meetings of shareholders may be held by means of conference
telephone or similar communications equipment by means of which all
participants can hear each other.
4. NOTICE. Written or printed notice stating the place, day and hour of
each meeting of shareholders and, in case of a special meeting, the
purpose or purposes for which the meeting is called, shall be delivered
not less than ten (10) nor more than sixty (60) days before the date of
the meeting, either personally or by mail, to each shareholder of record
entitled to vote at such meeting. Whenever any notice is required to be
given to any shareholder, a waiver thereof in writing signed by such
person(s) entitled to such notice (whether signed before or after the time
required for such notice) shall be equivalent to the giving of such
notice.
5. BUSINESS TO BE CONDUCTED AT ANNUAL OR SPECIAL MEETINGBUSINESS TO BE
CONDUCTED AT ANNUAL OR SPECIAL MEETINGBUSINESS TO BE CONDUCTED AT ANNUAL
OR SPECIAL MEETINGBUSINESS TO BE CONDUCTED AT ANNUAL OR SPECIAL
MEETINGBUSINESS TO BE CONDUCTED AT ANNUAL OR SPECIAL MEETINGBUSINESS TO BE
CONDUCTED AT ANNUAL OR SPECIAL MEETINGBUSINESS TO BE CONDUCTED AT ANNUAL
OR SPECIAL MEETING. At an annual meeting of the shareholders, only such
business shall be conducted as shall have been properly brought before the
meeting. To be properly brought before an annual or special meeting
business must be (a) specified in the notice of meeting (or any supplement
thereto) given by or at the direction of the board of directors, (b)
otherwise properly brought before the meeting by or at the direction of
the board of directors, or (c) otherwise properly brought before the
meeting by a shareholder. For business to be properly brought before an
annual or special meeting by a shareholder, the shareholder must have
given timely notice thereof in writing to the secretary of the
corporation. To be timely, a shareholder's notice regarding business to be
conducted at an annual meeting must be delivered to or mailed and received
at the principal executive offices of the corporation, not less than 60
days nor more than 90 days prior to the meeting; provided, however, that
in the event that less than 70 days' notice or prior public disclosure of
the date of the meeting is given or made to shareholders, notice by
30
the shareholder to be timely must be so received not later than the close
of business on the 10th day following the day on which such notice of the
date of the annual meeting was mailed or such public disclosure was made.
To be timely, a shareholder's notice regarding business to be conducted
ata special meeting must be delivered to or mailed and received at the
principal executive offices of the corporation no later than the date the
notice required under Section 4 of this Article I is provided to the
shareholders; provided that, in no event shall the special meeting be held
sooner than forty (40) days after the notice is received by the
corporation. A shareholder's notice to the secretary shall set forth as to
each matter the shareholder proposes to bring before the meeting (a) a
brief description of the business desired to be brought before the meeting
and the reasons for conducting such business at the meeting, (b) the name
and address, as they appear on the corporation's books, of the shareholder
proposing such business, (c) the class and number of shares of the
corporation which are beneficially owned by the shareholder, and (d) any
material interest of the shareholder in such business. Notwithstanding
anything in the Bylaws to the contrary, no business shall be conducted at
any meeting except in accordance with the procedures set forth in this
Section 5. The chairman of the meeting shall, if the facts warrant,
determine and declare to the meeting that business was not properly
brought before the meeting and in accordance with the provisions of this
Section 5, and if he should so determine, he shall so declare to the
meeting and any such business not properly brought before the meeting
shall not be transacted.
6. QUORUM. Except as otherwise required by law, the Articles of
Incorporation or these Bylaws, the holders of at least a majority of the
outstanding shares entitled to vote thereat and present in person or by
proxy shall constitute a quorum. The shareholders present at any meeting,
though less than a quorum, may adjourn the meeting. No notice of
adjournment, other than the announcement at the meeting, need be given.
7. VOTE REQUIRED TO TAKE ACTION. Except as otherwise provided in these
Bylaws or the articles of incorporation, when a quorum is present at any
meeting, the vote of the holders of a majority of the stock having voting
power present in person or represented by proxy shall decide any question
brought before such meeting, unless the question is one upon which by
express provision of the statutes, of the rules of any exchange or
quotation system upon which securities of the corporation are traded, or
of the articles of incorporation a different vote is required, in which
case such express provision shall govern and control the decision of such
question. In addition to the foregoing voting requirements, the
affirmative vote of the holders of at least sixty-six and two thirds
percent (66-2/3%) of the outstanding shares of the capital stock of the
corporation entitled to vote generally in the election of directors shall
be required to sell, assign or dispose of all or substantially all of the
corporation's assets (consisting of more than fifty percent (50%) of
either the total assets or the total proved reserves of the corporation)
in one or a series of related transactions or to merge, consolidate or
engage in a share exchange with another corporation or other entity, or to
enter into any transaction (including the issuance or transfer of
securities of the corporation), with any holder of 20% or more of the
outstanding capital stock of the corporation, if such transaction is not
approved by a majority of the directors, and any such transaction with a
holder of 20% or more the outstanding capital stock of the corporation
must otherwise comply with Section 13.03 of the Texas Business Corporation
Act (the "TBCA") or successor statute.
8. PROXIES. At all meetings of shareholders, a shareholder may vote
either in person or by proxy executed in writing by the shareholder or by
his duly authorized attorney-in-fact. Such proxies shall be filed with the
corporation before or at the time of the meeting. No proxy shall be valid
after eleven (11) months from the date of its execution unless otherwise
provided in the proxy. Each proxy shall be revocable unless expressly
provided therein to be irrevocable or unless otherwise made irrevocable by
law.
9. VOTING OF SHARES. Each outstanding share of a class entitled to vote
upon a matter submitted to a vote at a meeting of shareholders shall be
entitled to one vote on such matter except to the extent that the voting
rights are limited or denied by the Articles of Incorporation. No
shareholder shall have the right to cumulate his votes in the election of
directors.
10. OFFICERS. The chairman of the board shall preside at and the
secretary shall keep the records of each meeting of shareholders, but in
the absence of the chairman, the president shall perform the chairman's
duties, and in the absence of the secretary and all assistant secretaries,
his duties shall be performed by some person appointed by the presiding
officer.
31
11. LIST OF SHAREHOLDERS. A complete list of shareholders entitled to
vote at each shareholders' meeting, arranged in alphabetical order, with
the address of and number of shares held by each, shall be prepared by the
officer or agent having charge of the stock transfer books and filed at
the registered office of the corporation and shall be subject to
inspection by any shareholder during usual business hours for a period of
ten (10) days prior to such meeting and shall be produced at such meeting
and at all times during such meeting be subject to inspection by any
shareholder.
ARTICLE II
BOARD OF DIRECTORS
1. MANAGEMENT. The business and affairs of the corporation shall be
managed by the board of directors. The board may exercise all such powers
of the corporation and do all such lawful acts and things as are not by
statute, by the Articles of Incorporation or these Bylaws directed or
required to be exercised or done by the shareholders.
2. NUMBER. The board of directors shall consist of seven directors, but
the number of directors may be increased or decreased (provided such
decrease does not shorten the term of any incumbent director) from time to
time by a majority of the Continuing Directors, provided that the number
of directors shall never be less than three nor more than nine.
3. ELECTION AND TERM.
(A)The directors are divided into three classes, as nearly equal in
number as the total number of directors constituting the entire board
permits, with the term of office of one class expiring each succeeding
year. At each annual meeting of shareholders the successors to the class
of directors whose term shall then expire, shall be elected to hold office
until the third succeeding annual meeting or until their respective
successors shall have been elected and qualified, unless removed in
accordance with these Bylaws. Directors need not be shareholders nor
residents of Texas.
(B)Any vacancies in the board of directors for any reason, and any
directorships resulting from any increase in the number of
directors, may be filled by the board of directors, acting by a
majority of the directors then in office, although less than a
quorum, and any directors so chosen shall hold office until the
next election of the class for which such directors shall have
been chosen or until their successors shall be elected and
qualified.
4. DIRECTOR NOMINATION PROCEDURES. Only persons who are nominated in
accordance with the procedures set forth in this Section 4 shall
be eligible for election as directors. Nominations of persons f