UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
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(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2005
Commission File Number 1-8754
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SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in its Charter)
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TEXAS 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Drive, Suite 400
Houston, Texas 77060
(Address of principal executive offices) (Zip Code)
(281) 874-2700
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes |X| No |_|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes |X| No |_|
Indicate the number of shares outstanding of each of the
Issuer's classes of common stock, as of the latest practicable date.
Common Stock 28,595,381 Shares
($.01 Par Value) (Outstanding at July 31, 2005)
(Class of Stock)
1
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2005
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets 3
- June 30, 2005 and December 31, 2004
Condensed Consolidated Statements of Income 4
- For the Three month and Six month periods ended June 30, 2005 and 2004
Condensed Consolidated Statements of Stockholders' Equity 5
- For the Six month period ended June 30, 2005 and
year ended December 31, 2004
Condensed Consolidated Statements of Cash Flows 6
- For the Six month periods ended June 30, 2005 and 2004
Notes to Condensed Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition 19
and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk 31
Item 4. Controls and Procedures 32
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders 33
Item 5. Other Information None
Item 6. Exhibits 33
SIGNATURES 34
2
CONDENSED CONSOLIDATED BALANCE SHEETS
SWIFT ENERGY COMPANY
June 30, 2005 December 31, 2004
------------------- ------------------
ASSETS
Current Assets:
Cash and cash equivalents $ 27,728,290 $ 4,920,118
Accounts receivable -
Oil and gas sales 46,260,907 38,029,409
Joint interest owners 606,591 1,013,938
Other current assets 15,064,295 10,422,531
------------------- -------------------
Total Current Assets 89,660,083 54,385,996
------------------- -------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 1,581,386,007 1,479,681,903
Unproved properties not being amortized 80,994,868 80,121,509
------------------- -------------------
1,662,380,875 1,559,803,412
Furniture, Fixtures, and Other Equipment 14,099,878 12,820,622
------------------- -------------------
1,676,480,753 1,572,624,034
Less-Accumulated Depreciation, Depletion, and Amortization (702,299,352) (649,185,874)
------------------- -------------------
974,181,401 923,438,160
------------------- -------------------
Other Assets:
Deferred income taxes --- 1,666,058
Debt issuance costs 8,598,414 9,148,977
Restricted assets 1,914,856 1,933,956
------------------- -------------------
10,513,270 12,748,991
------------------ -------------------
$ 1,074,354,754 $ 990,573,147
=================== ===================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 29,411,912 $ 29,406,877
Accrued capital costs 30,243,537 22,489,467
Accrued interest 8,506,743 9,209,192
Undistributed oil and gas revenues 7,840,625 7,512,755
------------------- -------------------
Total Current Liabilities 76,002,817 68,618,291
Long-Term Debt 350,000,000 357,500,000
Deferred Income Taxes 97,876,922 73,106,580
Asset Retirement Obligation 16,584,569 17,176,136
Lease Incentive Obligation 158,724 ---
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000
shares authorized, none outstanding --- ---
Common stock, $.01 par value, 85,000,000 share
authorized,
29,005,618 and 28,570,632 shares issued, and
28,556,174 and 28,089,764 shares outstanding,
respectively 290,056 285,706
Additional paid-in capital 350,179,003 343,536,298
Treasury stock held, at cost, 449,444 and
480,868 shares, respectively (6,445,586) (6,896,245)
Unearned Compensation (2,059,168) (1,728,585)
Retained Earnings 192,095,111 138,524,301
Accumulated Other Comprehensive Income (Loss), Net of Taxes (327,694) 450,665
------------------- -------------------
533,731,722 474,172,140
------------------- -------------------
$ 1,074,354,754 $ 990,573,147
=================== ==--===============
See accompanying notes to condensed consolidated financial statements.
3
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
SWIFT ENERGY COMPANY
Three Months Ended Six Months Ended
------------------------------ -------------------------------
06/30/05 06/30/04 06/30/05 06/30/04
------------- -------------- -------------- ---------------
Revenues:
Oil and gas sales $ 104,922,400 $ 71,824,789 $ 200,443,733 $ 137,778,559
Price-risk management and other, net (622,475) (781,054) (523,124) (1,379,094)
------------- -------------- -------------- ---------------
104,299,925 71,043,735 199,920,609 136,399,465
------------- -------------- -------------- ---------------
Costs and Expenses:
General and administrative, net 4,995,887 4,175,559 9,870,195 8,205,233
Depreciation, depletion and amortization 28,777,631 19,509,056 52,983,009 37,804,740
Accretion of asset retirement obligation 187,495 160,259 374,002 330,735
Lease operating costs 11,565,223 10,435,813 22,614,005 20,061,793
Severance and other taxes 10,708,754 6,927,269 19,911,835 13,173,828
Interest expense, net 6,286,894 7,143,389 12,630,903 14,044,564
Debt retirement cost --- 2,691,243 --- 2,691,243
------------- -------------- -------------- ---------------
62,521,884 51,042,588 118,383,949 96,312,136
------------- -------------- -------------- ---------------
Income Before Income Taxes 41,778,041 20,001,147 81,536,660 40,087,329
Provision for Income Taxes 13,896,383 7,103,220 27,965,850 12,601,548
------------- -------------- -------------- ---------------
Net Income $ 27,881,658 $ 12,897,927 $ 53,570,810 $ 27,485,781
============= ============== ============== ===============
Per Share Amounts
Basic: Net Income $ 0.98 $ 0.46 $ 1.90 $ 0.99
============= ============== ============== ===============
Dilute: Net Income $ 0.96 $ 0.46 $ 1.86 $ 0.98
============= ============== ============== ===============
Weighted Average Shares Outstanding 28,376,518 27,742,444 28,268,733 27,647,636
============= ============== ============== ===============
See accompanying notes to condensed consolidated financial statements.
4
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SWIFT ENERGY COMPANY
Additional Other
Common Paid-In Treasury Unearned Retained Comprehensive
Stock(1) Capital Stock Compensation Earnings Income(Loss) Total
--------- ------------ ------------ ------------ ------------ ------------- -------------
Balance December 31, 2003 $ 280,111 $334,865,204 $ (7,558,093)$ --- $ 70,073,384 $ (269,342)$ 397,391,264
========= ============ ============ ============ ============ ============= =============
Stock issued for benefit plans (46,150
shares) --- 166,298 661,848 --- --- --- 828,146
Stock options exercised (509,105 shares) 5,091 4,260,882 --- --- --- --- 4,265,973
Tax benefits from exercise of stock
options --- 1,956,555 --- --- --- --- 1,956,555
Employee stock purchase plan (50,418
shares) 504 502,097 --- --- --- --- 502,604
Issuance of restricted stock --- 1,785,262 --- (1,785,262) --- --- ---
Amortization of restricted stock --- --- --- 56,677 --- --- 56,677
Net income --- --- --- --- 68,450,917 --- 68,450,917
Other comprehensive income --- --- --- --- --- 720,007 720,007
------------- -------------
Total Comprehensive Income 69,170,924
--------- ------------ ------------ ------------ ------------ ------------- -------------
Balance December 31, 2004 $ 285,706 $343,536,298 $ (6,896,245)$ (1,728,585)$138,524,301 $ 450,665 $ 474,172,140
========= ============ ============ ============ ============ ============= =============
Stock issued for benefit plans (31,424
shares) --- 435,134 450,659 --- --- --- 885,793
Stock options exercised (403,550 shares) 4,036 3,489,967 --- --- --- --- 3,494,003
Tax benefits from exercise of stock
options 1,213,728 1,213,728
Issuance of restricted stock --- 861,522 --- (600,719) --- --- 260,803
Employee stock purchase plan (31,436
shares) 314 642,354 --- --- --- --- 642,668
Amortization of restricted stock --- --- --- 270,136 --- --- 270,136
Net income --- --- --- --- 53,570,810 --- 53,570,810
Other Comprehensive Loss --- --- --- --- --- (778,359) (778,359)
-------------
Total Comprehensive Income 52,792,451
--------- ------------ ------------ ------------ ------------ ------------- -------------
Balance June 30, 2005 $ 290,056 $350,179,003 $ (6,445,586)$ (2,059,168)$192,095,111 $ (327,694)$ 533,731,722
========= ============ ============ ============ ============ ============= =============
(1) $.01 Par Value
See accompanying notes to condensed consolidated financial statements.
5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
SWIFT ENERGY COMPANY
Period Ended June 30,
------------------------------------------
2005 2004
-------------------- -------------------
Cash Flows From Operating Activities:
Net income $ 53,570,810 $ 27,485,781
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization 52,983,009 37,804,740
Accretion of asset retirement obligation 374,002 330,735
Deferred income taxes 27,565,850 12,195,548
Debt retirement cost --- 2,691,243
Other 117,924 363,958
Change in assets and liabilities -
Increase in accounts receivable (4,738,848) (3,445,623)
Increase in accounts payable and accrued liabilities 113,433 962,744
Decrease in accrued interest (702,449) (1,300,178)
-------------------- -------------------
Net Cash Provided by Operating Activities 129,283,731 77,088,948
-------------------- -------------------
Cash Flows From Investing Activities:
Additions to property and equipment (101,766,582) (85,926,359)
Proceeds from the sale of property and equipment 2,339,634 1,274,935
Net cash distributed as operator of oil and gas properties (3,840,937) (5,781,399)
Net cash received as operator of
partnerships and joint ventures 243,286 224,482
Other 50,105 (17,607)
-------------------- -------------------
Net Cash Used in Investing Activities (102,974,494) (90,225,948)
-------------------- -------------------
Cash Flows From Financing Activities:
Proceeds from long-term debt --- 150,000,000
Payments of long-term debt --- (32,076,000)
Net payments of bank borrowings (7,500,000) (15,900,000)
Net proceeds from issuances of common stock 3,998,935 2,923,516
Payments of debt retirement costs --- (1,792,017)
Payments of debt issuance costs --- (4,205,542)
-------------------- -------------------
Net Cash Provided by (Used in) Financing Activities (3,501,065) 98,949,957
-------------------- -------------------
Net Increase in Cash and Cash Equivalents 22,808,172 85,812,957
===================== ===================
Cash and Cash Equivalents at Beginning of Period 4,920,118 1,066,280
--------------------- -------------------
Cash and Cash Equivalents at End of Period $ 27,728,290 $ 86,879,237
===================== ===================
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period for Interest, Net of
Amounts Capitalized $ 12,798,576 $ 14,774,142
Cash Paid During Period for Income Taxes $ 400,000 $ 406,000
See accompanying notes to condensed consolidated financial statements.
6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SWIFT ENERGY COMPANY
(1) General Information
The condensed consolidated financial statements included herein
have been prepared by Swift Energy Company and reflect necessary
adjustments, all of which were of a recurring nature, and are in the
opinion of our management necessary for a fair presentation. Certain
information and footnote disclosures normally included in financial
statements prepared in accordance with accounting principles generally
accepted in the United States have been omitted pursuant to the rules
and regulations of the Securities and Exchange Commission. We believe
that the disclosures presented are adequate to allow the information
presented not to be misleading. The condensed consolidated financial
statements should be read in conjunction with the audited financial
statements and the notes thereto included in the latest Form 10-K and
Annual Report.
(2) Summary of Significant Accounting Policies
Property and Equipment
We follow the "full-cost" method of accounting for oil and gas
property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration,
development, and acquisition of oil and gas reserves are capitalized.
Such costs may be incurred both prior to and after the acquisition of a
property and include lease acquisitions, geological and geophysical
services, drilling, completion, and equipment. Internal costs incurred
that are directly identified with exploration, development, and
acquisition activities undertaken by us for our own account, and which
are not related to production, general corporate overhead, or similar
activities, are also capitalized. For the six months ended June 30,
2005 and 2004, such internal costs capitalized totaled $8.8 million and
$6.2 million, respectively. Interest costs are also capitalized to
unproved oil and gas properties. For the six months ended June 30, 2005
and 2004, capitalized interest on unproved properties totaled $3.5
million, and $3.2 million, respectively. Interest not capitalized and
general and administrative costs related to production and general
overhead are expensed as incurred.
No gains or losses are recognized upon the sale or disposition of
oil and gas properties, except in transactions involving a significant
amount of reserves or where the proceeds from the sale of oil and gas
properties would significantly alter the relationship between
capitalized costs and proved reserves of oil and gas attributable to a
cost center. Internal costs associated with selling properties are
expensed as incurred.
Future development costs are estimated property-by-property based
on current economic conditions and are amortized to expense as our
capitalized oil and gas property costs are amortized.
We compute the provision for depreciation, depletion, and
amortization ("DD&A") of oil and gas properties by the
unit-of-production method. Under this method, we compute the provision
by multiplying the total unamortized costs of oil and gas
properties--including future development costs, gas processing
facilities, and both capitalized asset retirement obligations and
undiscounted abandonment costs of wells to be drilled, net of salvage
values, but excluding costs of unproved properties--by an overall rate
determined by dividing the physical units of oil and gas produced
during the period by the total estimated units of proved oil and gas
reserves at the beginning of the period. This calculation is done on a
country-by-country basis, and the period over which we will amortize
these properties is dependent on our production from these properties
in future years. Furniture, fixtures, and other equipment, recorded at
cost, are depreciated by the straight-line method at rates based on the
estimated useful lives of the property, which range between three and
20 years. Repairs and maintenance are charged to expense as incurred.
Renewals and betterments are capitalized.
Geological and geophysical ("G&G") costs incurred on developed
properties are recorded in "Proved Properties" and therefore subject to
amortization. G&G costs incurred that are directly associated with
specific unproved properties are capitalized in "Unproved properties"
and evaluated as part of the total capitalized costs associated with a
prospect.
The cost of unproved properties not being amortized is assessed
quarterly, on a country-by-country basis, to determine whether such
properties have been impaired. In determining whether such costs should
7
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
be impaired, we evaluate current drilling results, lease expiration
dates, current oil and gas industry conditions, international economic
conditions, capital availability, foreign currency exchange rates, the
political stability in the countries in which we have an investment,
and available geological and geophysical information. Any impairment
assessed is added to the cost of proved properties being amortized. To
the extent costs accumulate in countries where there are no proved
reserves, any costs determined by management to be impaired are charged
to expense.
Full-Cost Ceiling Test
At the end of each quarterly reporting period, the unamortized
cost of oil and gas properties, including gas processing facilities,
capitalized asset retirement obligations, net of related salvage values
and deferred income taxes, and excluding the recognized asset
retirement obligation liability is limited to the sum of the estimated
future net revenues from proved properties, excluding cash outflows
from recognized asset retirement obligations, including future
development and abandonment costs of wells to be drilled, using
period-end prices, adjusted for the effects of hedging, discounted at
10%, and the lower of cost or fair value of unproved properties,
adjusted for related income tax effects ("Ceiling Test"). Our hedges at
June 30, 2005 consisted of natural gas and crude oil price floors with
strike prices lower than the period end price and thus did not
materially affect prices used in this calculation. This calculation is
done on a country-by-country basis.
The calculation of the Ceiling Test and provision for DD&A 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 estimates.
Accordingly, reserves estimates are often different from the quantities
of oil and gas that are ultimately recovered. Our reserves estimates
are prepared in accordance with Securites and Exhange Commission
guidelines; and, are audited on an annual basis at year-end by a firm
of independent petroleum engineers in accordance with standards
approved by the Board of Directors of the Society of Petroleum
Engineers.
Given the volatility of oil and gas prices, it is reasonably
possible that our estimate of discounted future net cash flows from
proved oil and gas reserves could change in the near term. If oil and
gas prices decline from our period-end prices used in the Ceiling Test,
even if only for a short period, it is possible that non-cash
write-downs of oil and gas properties could occur in the future.
Principles of Consolidation
The accompanying consolidated financial statements include the
accounts of Swift Energy Company and our wholly owned subsidiaries,
which are engaged in the exploration, development, acquisition, and
operation of oil and natural gas properties, with a focus on inland
waters and onshore oil and natural gas reserves in Louisiana and Texas,
as well as oil and natural gas reserves in New Zealand. Our undivided
interests in gas processing plants, and investments in six oil and gas
limited partnerships where we are the general partner are accounted for
using the proportionate consolidation method, whereby our proportionate
share of each entity's assets, liabilities, revenues, and expenses are
included in the appropriate classifications in the accompanying
consolidated financial statements. Intercompany balances and
transactions have been eliminated in preparing the accompanying
consolidated financial statements.
Revenue Recognition
Oil and gas revenues are recognized when production is sold to a
purchaser at a fixed or determinable price, when delivery has occurred
and title has transferred, and if collectibility of the revenue is
probable. Processing costs for natural gas and natural gas liquids
("NGLs") that are paid in-kind are deducted from revenues. The Company
uses the entitlement method of accounting in which the Company
recognizes its ownership interest in production as revenue. If our
sales exceed our ownership share of production, the natural gas
balancing payables are reported in "Accounts payable and accrued
liabilities" on the accompanying balance sheet. Natural gas balancing
receivables are reported in "Other current assets" on the accompanying
balance sheet when our ownership share of production exceeds sales. As
of June 30, 2005, we did not have any material natural gas imbalances.
8
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
Accounts Receivable
Included in the "Accounts receivable" balance, which totaled $46.9
million and $39.0 million at June 30, 2005 and December 31, 2004,
respectively, on the accompanying balance sheets, are approximately
$2.3 million of receivables related to hydrocarbon volumes produced
from 2001 and 2002 that have been disputed since early 2003. As a
result of the dispute, we did not record a receivable with regard to
any 2003 disputed volumes and our contract governing these sales
expired in 2003. Based on settlement discussions, we settled our claim
with this counter-party in July 2005 by receiving a cash payment for
less than our gross receivable. Accordingly, in the second quarter of
2005, we increased our reserve for this claim by approximately $0.6
million, which is recorded in "Price-risk management and other, net" on
the accompanying statements of income.
We assess the collectibility of accounts receivable, and based on
our judgment, we accrue a reserve when we believe a receivable may not
be collected. At June 30, 2005 and December 31, 2004, we had an
allowance for doubtful accounts of $1.0 million and $0.5 million,
respectively. The allowance for doubtful accounts has been deducted
from the total "Accounts receivable" balances on the accompanying
balance sheets.
Inventories
We value inventories at the lower of cost or market value. Cost of
crude oil inventory is determined using the weighted average method and
all other inventory is accounted for using the first in, first out
method ("FIFO"). The major categories of inventories, which are
included in "Other current assets" on the accompanying balance sheets,
are shown as follows:
Balance at Balance at
June 30, 2005 December 31, 2004
(000's) (000's)
----------------- ------------------
Materials, Supplies and Tubulars $ 10,759 $ 6,417
Crude Oil 829 770
----------------- ------------------
Total $ 11,588 $ 7,187
================= ==================
Use of Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States (GAAP)
requires us to make estimates and assumptions that affect the reported
amount of certain assets and liabilities and the reported amounts of
certain revenues and expenses during each reporting period. We believe
our estimates and assumptions are reasonable; however, such estimates
and assumptions are subject to a number of risks and uncertainties that
may cause actual results to differ materially from such estimates.
Significant estimates underlying these financial statements include:
o the estimated quantities of proved oil and natural gas
reserves used to compute depletion of oil and natural gas
properties and the related present value of estimated future
net cash flows there from,
o accruals related to oil and gas revenues, capital expenditures
and lease operating expenses,
o the estimated future cost and timing of asset retirement
obligations, and
o estimates made in our income tax calculations.
While we are not aware of any material revisions to any of our
estimates, there will likely be future revisions to our estimates
resulting from matters such as changes in ownership interests, payouts,
joint venture audits, re-allocations by purchasers or pipelines, or
other corrections and adjustments common in the oil and gas industry,
many of which require retroactive application. These types of
adjustments cannot be currently estimated and will be recorded in the
period during which the adjustment occurs.
9
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
Income Taxes
Under SFAS No. 109, "Accounting for Income Taxes," deferred taxes
are determined based on the estimated future tax effects of differences
between the financial statement and tax basis of assets and
liabilities, given the provisions of the enacted tax laws. The
effective tax rates for both the first six months of 2005 and 2004 were
lower than the statutory tax rates primarily due to reductions from the
New Zealand statutory rate attributable to the currency effect on the
New Zealand deferred tax calculation and corrections to the New Zealand
tax basis calculations. In the first six months of 2005, these amounts
were partially offset by higher deferred state income taxes. The first
six months of 2004 included favorable corrections to tax basis amounts
discovered while preparing the prior year's tax returns. The tax laws
in the jurisdictions we operate in are continuously changing and
professional judgments regarding such laws can differ. The Company
continues to evaluate the impact of the recently enacted American Jobs
Creation Act of 2004. We do not believe this act will have a material
impact in the near-term on our financial position or results of
operations.
Accounts Payable and Accrued Liabilities
Included in "Accounts payable and accrued liabilities," on the
accompanying balance sheets, at June 30, 2005 and December 31, 2004 are
liabilities of approximately $5.4 million and $6.9 million,
respectively, representing the amount by which checks issued, but not
presented to the Company's banks for collection, exceeded balances in
the applicable disbursement bank accounts.
Accumulated Other Comprehensive Income (Loss), Net of Income Tax
We follow the provisions of SFAS No. 130, "Reporting Comprehensive
Income," which establishes standards for reporting comprehensive
income. In addition to net income, comprehensive income or loss
includes all changes to equity during a period, except those resulting
from investments and distributions to the owners of the Company. At
June 30, 2005, we recorded $0.3 million, net of taxes of $0.2 million,
of derivative losses in "Accumulated other comprehensive income (loss),
net of income tax" on the accompanying balance sheet. The components of
accumulated other comprehensive income (loss) and related tax effects
for the period ending June 30, 2005 were as follows:
Net of
Gross Value Tax Effect Tax Value
--------------- -------------- ---------------
Other comprehensive income at
December 31, 2004 $ 710,828 $ (260,163) $ 450,665
Change in fair value of cash flow hedges (797,939) 292,045 (505,894)
Effect of cash flow hedges settled
during the period (429,756) 157,291 (272,465)
--------------- -------------- ---------------
Other comprehensive loss at June 30, 2005 $ (516,867) $ 189,173 $ (327,694)
=============== ============== ==============
Total comprehensive income was $28.1 million and $13.0 million for
the second quarters of 2005 and 2004, respectively. Total comprehensive
income was $52.8 million and $27.6 million for the first six months of
2005 and 2004, respectively.
Stock Based Compensation
We account for two stock-based compensation plans under the
recognition and measurement principles of APB Opinion No. 25,
"Accounting for Stock Issued to Employees," and related
interpretations. We issued restricted stock to employees for the first
time in the fourth quarter of 2004, and then to directors in the second
quarter of 2005, and for the period ended June 30, 2005 we recorded
expense related to these shares of $0.3 million in "General and
administrative, net" on the accompanying statements of income. No
stock-based employee compensation cost is reflected in net income for
employee stock options, as all options granted under our plan had an
exercise price equal to the market value of the underlying common stock
on the date of the grant; or in the case of the employee stock purchase
plan, as the purchase price is 85% of the lower of the closing price of
our common stock as quoted on the New York Stock Exchange at the
beginning or end of the plan year or a date during the year chosen by
the participant. Had compensation expense for these plans been
determined based on the fair value of the options consistent with SFAS
10
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
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,
----------------------------------
2005 2004
---------------- --------------
Net Income: As Reported $27,881,658 $12,897,927
Stock-based employee compensation
expense determined under fair value
method for all awards, net of tax (1,113,938) (1,088,520)
---------------- --------------
Pro Forma $26,767,720 $11,809,407
Basic EPS: As Reported $.98 $.46
Pro Forma $.94 $.43
Diluted EPS: As Reported $.96 $.46
Pro Forma $.92 $.42
Six Months Ended June 30,
---------------------------------
2005 2004
---------------- --------------
Net Income: As Reported $53,570,810 $27,485,781
Stock-based employee compensation
expense determined under fair value
method for all awards, net of tax (1,973,089) (2,110,826)
---------------- --------------
Pro Forma $51,597,721 $25,374,955
Basic EPS: As Reported $1.90 $.99
Pro Forma $1.83 $.92
Diluted EPS: As Reported $1.86 $.98
Pro Forma $1.79 $.90
Pro forma compensation cost reflected above may not be
representative of the cost to be expected in future periods. The fair
value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model. We view all awards of stock
compensation as a single award with an expected life equal to the
average expected life of component awards and amortize the award on a
straight-line basis over the life of the award.
Price-Risk Management Activities
The Company follows SFAS No. 133, which requires that changes in
the derivative's fair value are 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) is recorded in the balance sheet as either
an asset or a liability measured at its fair value. Hedge accounting
for a qualifying hedge allows the gains and losses on derivatives to
offset related results on the hedged item in the income statements and
requires that a company formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. Changes in
the fair value of derivatives that do not meet the criteria for hedge
accounting, and the ineffective portion of the hedge, are recognized
currently in income.
We have a price-risk management policy to use derivative
instruments to protect against declines in oil and gas prices, mainly
through the purchase of price floors and collars. During the second
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
quarters of 2005 and 2004, we recognized net losses of $0.4 million and
$0.5 million, respectively, relating to our derivative activities.
During the first six months of 2005 and 2004, we recognized net losses
of $0.5 million and $1.1 million, respectively, relating to our
derivative activities. This activity is recorded in "Price-risk
management and other, net" on the accompanying statements of income. At
June 30, 2005, the Company had recorded $0.3 million, net of taxes of
$0.2 million, of derivative losses in "Accumulated other comprehensive
income (loss), net of income tax" 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 2005 and 2004 was not material. We expect
to reclassify all amounts currently held in "Accumulated other
comprehensive income (loss), net of income tax" into the statement of
income within the next six months when the forecasted sale of hedged
production occurs.
At June 30, 2005, we had in place price floors in effect for July
2005 through the December 2005 contract month for natural gas, that
cover a portion of our domestic natural gas production for July 2005 to
December 2005. The natural gas price floors cover notional volumes of
2,300,000 MMBtu, with a weighted average floor price of $5.71 per
MMBtu. Our natural gas price floors in place at June 30, 2005 are
expected to cover approximately 30% to 35% of our estimated domestic
natural gas production from July 2005 to December 2005.
When we entered into these transactions discussed above, they were
designated as a hedge of the variability in cash flows associated with
the forecasted sale of natural gas production. Changes in the fair
value of a hedge that is highly effective and is designated and
documented and qualifies as a cash flow hedge, to the extent that the
hedge is effective, are recorded in "Accumulated other comprehensive
income (loss), net of income tax." When the hedged transactions are
recorded upon the actual sale of oil and natural gas, these gains or
losses are reclassified from "Accumulated other comprehensive income
(loss), net of income tax" and recorded in "Price-risk management and
other, net" on the accompanying statement of income. The fair value of
our derivatives is computed using the Black-Scholes option pricing
model and is periodically verified against quotes from brokers. The
fair value of these instruments at June 30, 2005, was less than $0.1
million and is recognized on the accompanying balance sheet in "Other
current assets."
Supervision Fees
Consistent with industry practice, we charge a supervision fee to
the wells we operate including our wells in which we own up to a 100%
working interest. Supervision fees are recorded as a reduction to
general and administrative, net based on our estimate of the costs
incurred to operate the wells. The total amount of supervision fees
charged to the wells we operate was $3.8 million and $2.5 million in
the first six months of 2005 and 2004, respectively.
Asset Retirement Obligation
In June 2001, the Financial Accounting Standards Board (FASB)
issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The
statement requires entities to record the fair value of a liability for
legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When
the liability is initially recorded, the carrying amount of the related
long-lived asset is increased. The liability is discounted from the
year the well is expected to deplete. Over time, accretion of the
liability is recognized each period, and the capitalized cost is
depreciated on a unit-of-production basis over the useful life of the
related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss
upon settlement. This standard requires us to record a liability for
the fair value of our dismantlement and abandonment costs, excluding
salvage values. Based on our experience and analysis of the oil and gas
services industry, we have not factored a market risk premium into our
asset retirement obligation. SFAS No. 143 was adopted by us effective
January 1, 2003. The following provides a roll-forward of our asset
retirement obligation:
12
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
2005 2004
---------------- ---------------
Asset Retirement Obligation recorded as of January 1 $ 17,639,136 $ 10,137,473
Accretion expense for the six months ended June 30 374,002 330,735
Liabilities incurred for new wells and facilities construction 54,622 191,491
Reductions due to sold, or plugged and abandoned wells (277,604) (216,484)
Decrease due to currency exchange rate fluctuations (19,087) (14,274)
---------------- ---------------
Asset Retirement Obligation as of June 30 $ 17,771,069 $ 10,428,941
---------------- ---------------
At June 30, 2005 and December 31, 2004, approximately $1.2 million
and $0.5 million, respectively, of our asset retirement obligation is
classified as a current liability in "Accounts payable and accrued
liabilities" on the accompanying balance sheets.
New Accounting Pronouncements
In September and November 2004, and March 2005, the EITF discussed
a proposed framework for addressing when a limited partnership should
be consolidated by its general partner, EITF Issue 04-5. The proposed
framework presumes that a sole general partner in a limited partnership
controls the limited partnership, and therefore should consolidate the
limited partnership. The presumption of control can be overcome if the
limited partners have (a) the substantive ability to remove the sole
general partner or otherwise dissolve the limited partnership or (b)
substantive participating rights. The EITF reached a tentative
conclusion on the circumstances in which either kick-out rights or
participating rights would be considered substantive and preclude
consolidation by the general partner and what limited partner's rights
would be considered participating rights that would preclude
consolidation by the general partner. The EITF tentatively concluded
that for kick-out rights to be considered substantive, the conditions
specified in paragraph B20 of FIN 46R should be met. With regard to the
definition of participating rights that would preclude consolidation by
the general partner, the EITF concluded that the definition of those
rights should be consistent with those in EITF Issue 96-16. The EITF
also reached a tentative conclusion on the transition for Issue 04-05.
The FASB ratified the EITF consensus at the June 2005 EITF meeting. We
do not believe this EITF will have a material impact on our
consolidated financial statements because we believe our limited
partners have substantive kick-out rights under paragraph B20 of FIN
46R.
In December 2004, the FASB issued SFAS No. 123R, Share-Based
Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting for
Stock-Based Compensation, and supercedes APB Opinion No. 25, Accounting
for Stock Issued to Employees, and amends SFAS No. 95, Statement of
Cash Flows. SFAS No. 123R requires all employee share-based payments,
including grants of employee stock options, to be recognized in the
financial statements based on their fair values. SFAS No. 123
discontinues the ability to account for these equity instruments under
the intrinsic value method as described in APB Opinion No. 25. SFAS No.
123R requires the use of an option pricing model for estimating fair
value, which is amortized to expense over the service periods. The
requirements of SFAS No. 123R are effective for fiscal periods
beginning after June 15, 2005. SFAS No. 123R permits public companies
to adopt its requirements using one of two methods:
o A "modified prospective" method in which compensation cost is
recognized beginning with the effective date based on the
requirements of SFAS No. 123R for all share-based payments granted
after the effective date and based on the requirements of SFAS No.
123 for all awards granted to employees prior to the adoption date
of SFAS No. 123R that remain unvested on the adoption date.
o A "modified retrospective" method which includes the requirements
of the modified prospective method described above, but also
permits entities to restate either all prior periods presented or
prior interim periods of the year of adoption based on the amounts
previously recognized under SFAS No. 123 for purposes of pro forma
disclosures.
In April 2005, the SEC issued a release announcing that it would
provide for a phased-in implementation process for SFAS No. 123R. As a
result, our required date to adopt SFAS No. 123R is now January 1,
2006. Also in April 2005, the SEC issued Staff Accounting Bulleting No.
13
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
107, Share-Based Payment, which provides guidance on the implementation
of SFAS No. 123R. SAB No. 107 provides guidance on valuing options,
estimating volatility and expected terms of the option awards, and
discusses the SEC's views on share-based payment transactions with
non-employees, the capitalization of compensation cost and accounting
for income tax effects of share-based payment arrangements upon
adoption of SFAS No. 123R.
We have elected to adopt the provisions of SFAS No. 123R on
January 1, 2006 using the modified prospective method. As permitted by
Statement 123, the Company currently accounts for share-based payments
to employees using APB Opinion No. 25's intrinsic value method and, as
such, generally recognizes no compensation cost for employee stock
options. Accordingly, the adoption of Statement No. 123R's fair value
method is expected to have a significant impact on our results of
operations. However, it will have no impact on our overall financial
position. We currently use the Black-Scholes formula to estimate the
value of stock options granted to employees and expect to continue to
use this acceptable option valuation model upon the required adoption
of SFAS No. 123R. The significance of the impact of adoption will
depend on levels of outstanding unvested share-based payments on the
date of adoption and share-based payments granted in the future.
However, had we adopted Statement No. 123R in prior periods, the impact
of that standard would have approximated the impact of Statement No.
123 as described in the disclosure of pro forma net income and earnings
per share under "Stock Based Compensation" above.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and
Error Corrections: a replacement of APB Opinion No. 20 and FASB
Statement No. 3. SFAS No. 154 requires voluntary changes in accounting
principles to be applied retrospectively, unless it is impracticable.
SFAS No. 154's retrospective application requirement replaces APB 20's
requirement to recognize most voluntary changes in accounting principle
by including in net income of the period of the change the cumulative
effect of changing to the new accounting principle. If retrospective
application for all prior periods is impracticable, the method used to
report the change and the reason the retrospective application is
impracticable are to be disclosed.
Under SFAS No. 154, retrospective application will be the
transition method in the unusual instance that a newly issued
accounting pronouncement does not provide specific transition guidance.
It is expected that many pronouncements will specify transition methods
other than retrospective. SFAS No. 154 is effective for accounting
changes made in fiscal years beginning after December 15, 2005, and the
adoption of this statement is expected to have no impact on our
financial position or results of operations.
In July 2005, the FASB issued an exposure draft "Accounting for
Uncertain Tax Positions, a proposed interpretation of FASB Statement
No. 109." The proposed interpretation would apply to all open tax
positions under FASB No. 109. The conclusions in this interpretation
include: initial recognition of tax benefits, recognition and
de-recognition of tax positions, measurement of tax benefits and
classifications of tax liabilities. The comment period on this exposure
draft ends in September 2005, and we are currently assessing the
impact, if any, that this interpretation would have on our financial
position and results of operations. The proposal enactment date would
require application effective December 31, 2005.
(3) Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using
the weighted average number of common shares outstanding during the
respective periods. Diluted earnings per share ("Diluted EPS") for all
periods also assumes, as of the beginning of the period, exercise of
stock options and restricted stock grants to employees using the
treasury stock method. Certain of our stock options, that could
potentially dilute Basic EPS in the future, were anti-dilutive for the
three-month and six-month periods ended June 30, 2005 and 2004, and are
discussed below.
The following is a reconciliation of the numerators and
denominators used in the calculation of Basic and Diluted EPS for the
three-month and six-month periods ended June 30, 2005 and 2004:
14
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
Three Months Ended June 30,
----------------------------------------------------------------------------
2005 2004
-------------------------------------- -------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------ ----------- ------------- ------------ ---------- ------------
Basic EPS:
Net Income and Share Amounts $ 27,881,658 28,376,518 $ 0.98 $ 12,897,927 27,742,444 $ 0.46
Dilutive Securities:
Restricted Stock --- 30,579 --- ---
Stock Options --- 601,835 --- 555,300
------------ ----------- ------------ ----------
Diluted EPS:
Net Income and Assumed Share
Conversions $ 27,881,658 29,008,932 $ 0.96 $ 12,897,927 28,297,744 $ 0.46
------------ ----------- ------------ ----------
Six Months Ended June 30,
----------------------------------------------------------------------------
2005 2004
-------------------------------------- -------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------ ----------- ------------- ------------ ---------- ------------
Basic EPS:
Net Income and Share Amounts $ 53,570,810 28,268,733 $ 1.90 $ 27,485,781 27,647,636 $ 0.99
Dilutive Securities:
Restricted Stock --- 25,781 --- ---
Stock Options --- 554,986 --- 504,626
------------ ----------- ------------ ----------
Diluted EPS:
Net Income and Assumed Share
Conversions $ 53,570,810 28,849,500 $ 1.86 $ 27,485,781 28,152,262 $ 0.98
------------ ----------- ------------ ----------
Options to purchase approximately 2.6 million shares at an average
exercise price of $20.10 were outstanding at June 30, 2005, while
options to purchase 2.9 million shares at an average exercise price of
$17.37 were outstanding at June 30, 2004. Approximately 0.3 million and
0.9 million options to purchase shares were not included in the
computation of Diluted EPS for the three-month periods ended June 30,
2005 and 2004, respectively, and approximately 0.7 million and 1.0
million options to purchase shares were not included in the computation
of Diluted EPS for the six-month periods ended June 30, 2005 and 2004,
respectively, because these options were antidilutive in that the
option price was greater than the average closing market price for the
common shares during those periods. Restricted stock grants to
consultants of 15,000 shares, which were issued in the second half of
2004, were not included in the computation of Diluted EPS for the
three-month and six-month periods ended June 30, 2005, as performance
conditions surrounding the vesting of these shares had not occurred.
(4) Long-Term Debt
Our long-term debt, including the current portion, as of June 30,
2005 and December 31, 2004, was as follows (in thousands):
June 30, December 31,
2005 2004
------------------ -------------------
Bank Borrowings $ --- $ 7,500
7-5/8% senior notes due 2011 150,000 150,000
9-3/8% senior subordinated notes due 2012 200,000 200,000
------------------ -------------------
Long-Term Debt $ 350,000 $ 357,500
------------------ -------------------
15
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
Bank Borrowings
At June 30, 2005, we had no outstanding borrowings under our
$400.0 million credit facility with a syndicate of ten banks that has a
borrowing base of $250.0 million and expires in October 2008. At
December 31, 2004, we had $7.5 million in outstanding borrowings under
our credit facility. The interest rate is either (a) the lead bank's
prime rate (6.25% at June 30, 2005), or (b) the adjusted London
Interbank Offered Rate ("LIBOR") plus the applicable margin depending
on the level of outstanding debt. The applicable margin is based on the
ratio of the outstanding balance to the last calculated borrowing base.
In June 2004, we renewed this credit facility, increasing the facility
to $400 million from $300 million and extending its expiration to
October 1, 2008 from October 1, 2005. The other terms of the credit
facility, such as the borrowing base amount and commitment amount,
stayed largely the same. The covenants related to this credit facility
changed somewhat with the extension of the facility and are discussed
below. We incurred $0.4 million of debt issuance costs related to the
renewal of this facility in 2004, which is included in "Debt issuance
costs" on the accompanying balance sheets and will be amortized to
interest expense over the life of the facility.
The terms of our credit facility include, among other
restrictions, a limitation on the level of cash dividends (not to
exceed $5.0 million in any fiscal year), a remaining aggregate
limitation on purchases of our stock of $15.0 million, requirements as
to maintenance of certain minimum financial ratios (principally
pertaining to adjusted working capital ratios and EBITDAX), and
limitations on incurring other debt or repurchasing our 7-5/8% senior
notes due 2011 or 9-3/8% senior subordinated notes due 2012. Since
inception, no cash dividends have been declared on our common stock. We
are currently in compliance with the provisions of this agreement. The
credit facility is secured by our domestic oil and gas properties. We
have also pledged 65% of the stock in our two 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 at $250.0 million effective May 1, 2005. At our request, the
commitment amount with our bank group was reduced to $150.0 million
effective May 9, 2003, and continues at this amount. 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 in November 2005.
Interest expense on the credit facility, including commitment fees
and amortization of debt issuance costs, totaled $0.2 million and $0.5
million for the three-months ended June 30, 2005 and 2004,
respectively, and $0.6 million and $0.9 million for the six-months
ended June 30, 2005 and 2004, respectively. The amount of commitment
fees included in interest expense, net was $0.1 million for both the
three-months ended June 30, 2005 and 2004, respectively, and $0.3
million and $0.2 million for the six-months ended June 30, 2005 and
2004, respectively.
Senior Notes Due 2011
These notes consist of $150.0 million of 7-5/8% senior notes due
2011, which were issued on June 23, 2004 at 100% of the principal
amount and will mature on July 15, 2011. The notes are senior unsecured
obligations that rank equally with all of our existing and future
senior unsecured indebtedness, are effectively subordinated to all our
existing and future secured indebtedness to the extent of the value of
the collateral securing such indebtedness, including borrowing under
our bank credit facility, and rank senior to all of our existing and
future subordinated indebtedness. Interest on these notes is payable
semi-annually on January 15 and July 15, and commenced on January 15,
2005. On or after July 15, 2008, we may redeem some or all of the
notes, with certain restrictions, at a redemption price, plus accrued
and unpaid interest, of 103.813% of principal, declining to 100% in
2010 and thereafter. In addition, prior to July 15, 2007, we may redeem
up to 35% of the notes with the net proceeds of qualified offerings of
our equity at a redemption price of 107.625% of the principal amount of
the notes, plus accrued and unpaid interest. We incurred approximately
$3.9 million of debt issuance costs related to these notes, which is
included in "Debt issuance costs" on the accompanying balance sheets
and will be amortized to interest expense, net over the life of the
notes using the effective interest method. Upon certain changes in
control of Swift Energy, each holder of notes will have the right to
require us to repurchase all or any part of the notes at a purchase
price in cash equal to 101% of the principal amount, plus accrued and
unpaid interest to the date of purchase. The terms of these notes
16
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
include, among other restrictions, a limitation on how much of our own
common stock we may repurchase. We are currently in compliance with the
provisions of the indenture governing these senior notes.
Interest expense on the 7-5/8% senior notes due 2011, including
amortization of debt issuance costs totaled $3.0 million and $0.2
million for the three-months ended June 30, 2005 and 2004,
respectively, and $5.9 million and $0.2 million for the six-months
ended June 30, 2005 and 2004, respectively.
Senior Subordinated Notes Due 2012
These notes consist of $200.0 million of 9-3/8% senior
subordinated notes due May 2012, which were issued on April 16, 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 credit
facility and 7-5/8% senior notes. Interest on these notes is payable
semiannually on May 1 and November 1, and commenced on November 1,
2002. On or after May 1, 2007, we may redeem these notes, with certain
restrictions, at a redemption price, plus accrued and unpaid interest,
of 104.688% of principal, declining to 100% in 2010. In addition, prior
to May 1, 2005, we could have redeemed up to 33.33% of these notes with
the net proceeds of qualified offerings of our equity at 109.375% of
the principal amount of these notes, plus accrued and unpaid interest.
Upon certain changes in control of Swift Energy, each holder of these
notes will have the right to require us to repurchase the notes at a
purchase price in cash equal to 101% of the principal amount, plus
accrued and unpaid interest to the date of purchase. The terms of these
notes include, among other restrictions, a limitation on how much of
our own common stock we may repurchase. We are currently in compliance
with the provisions of the indenture governing these subordinated
notes.
Interest expense on the 9-3/8% senior subordinated notes due 2012,
including amortization of debt issuance costs totaled $4.8 million for
both the three-months ended June 30, 2005 and 2004, and $9.6 million
for both the six-months ended June 30, 2005 and 2004.
Other
The aggregate maturities on our long-term debt are $150 million
for 2011 and $200 million for 2012.
We have capitalized interest on our unproved properties in the
amount of $1.7 million and $1.6 million for the three-months ended June
30, 2005 and 2004, respectively, and $3.5 million and $3.2 million for
the six-months ended June 30, 2005.
(5) Foreign Activities
As of June 30, 2005, our gross capitalized oil and gas property
costs in New Zealand totaled approximately $263.1 million.
Approximately $228.9 million has been included in the "Proved
properties" portion of our oil and gas properties, while $34.2 million
is included as "Unproved properties." Our functional currency in New
Zealand is the U.S. Dollar. Net assets of our New Zealand operations
total $228.7 million at June 30, 2005. In April 2005, Swift Energy New
Zealand ("SENZ") was awarded petroleum mining permit ("PMP") 38155 and
petroleum exploration permit ("PEP") 38495 by the New Zealand
Government. PMP 38155 is for the development of our Kauri Sand and
Manutahi Sand discoveries and covers 8,708 acres and allows us to fully
develop our Kauri area for a primary term of 30 years. Following the
award of PEP 38495, SENZ initiated a farm-in agreement with Mighty
River Power ("MRP"), whereby SENZ agreed to transfer a 50% interest in
the permit to MRP in return for MRP funding various seismic operations
during 2005 and 2006. PEP 38495 is located offshore in the southern
portion of the basin to the south and west of our PEP 38719 and
encompasses approximately 600 square miles.
(6) Acquisitions and Dispositions
In late December 2004, we acquired interests in two fields in
South Louisiana, the Bay de Chene and Cote Blanche Island fields. We
paid approximately $27.7 million in cash for these interests. After
taking into account internal acquisition costs of $2.8 million, our
total cost was $30.5 million. We allocated $27.8 million of the
acquisition price to "Proved properties," and $5.1 million to "Unproved
properties." We also recorded $0.5 million to "Restricted assets," and
recorded a liability of $2.9 million to "Asset retirement obligation"
on our accompanying balance sheet. This acquisition was accounted for
17
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY
by the purchase method of accounting. We made this acquisition to
increase our exploration and development opportunities in South
Louisiana. The revenues and expenses from these properties have been
included in our accompanying statements of income from the date of
acquisition forward, however, given the acquisition was in late
December 2004, these amounts were immaterial for 2004.
(7) Segment Information
The Company has two reportable segments, one domestic and one
foreign, which are in the business of crude oil and natural gas
exploration and production. The accounting policies of the segments are
the same as those described in the summary of significant accounting
policies. We evaluate our performance based on profit or loss from oil
and gas operations before price-risk management and other, net, general
and administrative, net, and interest expense, net. Our reportable
segments are managed separately based on their geographic locations.
Financial information by operating segment is presented below:
Three Months Ended June 30,
-----------------------------------------------------------------------------------
2005 2004
----------------------------------------- ----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- ------------ -------------- ------------- ----------- ------------
Oil and gas sales $ 89,931,241 $ 14,991,159 $ 104,922,400 $ 59,755,056 $12,069,733 $ 71,824,789
Costs and Expenses:
Depreciation, depletion and
amortization 22,558,462 6,219,169 28,777,631 14,903,238 4,605,818 19,509,056
Accretion of asset
retirement obligation 154,166 33,329 187,495 119,699 40,560 160,259
Lease operating costs 8,503,723 3,061,500 11,565,223 7,935,048 2,500,764 10,435,812
Severance and other taxes 9,728,291 980,463 10,708,754 6,062,585 864,685 6,927,270
------------- ------------ -------------- ------------- ----------- ------------
Income from oil and gas
operations $ 48,986,599 $ 4,696,698 $ 53,683,297 $ 30,734,486 $ 4,057,906 $ 34,792,392
Price-risk management and
other, net (622,475) (781,054)
General and administrative,
net 4,995,887 4,175,559
Interest expense, net 6,286,894 7,143,389
Debt retirement cost --- 2,691,243
-------------- ------------
Income Before Income Taxes $ 41,778,041 $ 20,001,147
============== ============
Six Months Ended June 30,
-----------------------------------------------------------------------------------
2005 2004
----------------------------------------- ----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- ------------ -------------- ------------- ----------- ------------
Oil and gas sales $ 166,707,010 $33,736,723 $ 200,443,733 $ 114,421,220 $23,357,339 $137,778,559
Costs and Expenses:
Depreciation, depletion and
amortization 40,232,160 12,750,849 52,983,009 29,421,187 8,383,553 37,804,740
Accretion of asset
retirement obligation 308,023 65,979 374,002 250,247 80,488 330,735
Lease operating costs 16,747,940 5,866,065 22,614,005 14,854,330 5,207,463 20,061,793
Severance and other taxes 17,758,977 2,152,858 19,911,835 11,481,465 1,692,363 13,173,828
------------- ------------ -------------- ------------- ----------- ------------
Income from oil and gas
operations $ 91,659,910 $ 12,900,972 $ 104,560,882 $ 58,413,991 $ 7,993,472 $ 66,407,463
Price-risk management and
other, net (523,124) (1,379,094)
General and administrative,
net 9,870,195 8,205,233
Interest expense, net 12,630,903 14,044,564
Debt retirement cost --- 2,691,243
-------------- ------------
Income Before Income Taxes $ 81,536,660 $ 40,087,329
============== ============
Total Assets $ 845,685,920 $228,668,834 $1,074,354,754 $ 784,300,416 $201,019,347 $985,319,763
============= ============ ============== ============= =========== ============
18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SWIFT ENERGY COMPANY
You should read the following discussion and analysis in
conjunction with our financial information and our condensed
consolidated financial statements and notes thereto included in this
report and our Form 10-K for the year ended December 31, 2004. The
following information contains forward-looking statements. For a
discussion of limitations inherent in forward-looking statements, see
"Forward-Looking Statements" on page 30 of this report.
Overview
For the second quarter of 2005, our revenues were $104 million, a
47% increase, and our production was 15.9 Bcfe, a 12% increase, in both
cases as compared to second quarter 2004 results. For the first six
months of 2005, we had revenues of $199.9 million and production of
31.4 Bcfe, which is a 47% increase in revenues and a 10% increase in
production over first half of 2004 results. This performance
constitutes a record quarter and record six-month period for Swift
Energy. Our revenues for the first half of 2005 were supported by
record high oil and gas prices in the industry, while at the same time,
our production increased to a historical high for the Company. Our
efforts and capital throughout the first half of 2005 remained focused
on infrastructure improvements, increased production, and the
development of long-lived reserves through exploration and exploitation
activities primarily in southern Louisiana, South Texas and New
Zealand. We expect to continue this focus throughout 2005.
Our overall costs and expenses have increased, and we expect costs
and expenses to continue to increase throughout 2005. The primary
increase in these costs and expenses is due to increased depreciation,
depletion and amortization expense as a result of increased estimates
for future development costs and additional capital expenditures during
the year. The other primary factor for our increased costs and expenses
is due to increased production in Lake Washington along with higher
severance taxes due to increased revenues. Higher severance taxes are
driven by higher production and revenue. We've also seen an increase in
our general and administrative expenses due to an increased workforce,
but our lease operating costs were less than originally anticipated due
to lower than expected chemical, repair and maintenance costs as well
as no significant work-over activity.
Our financial position remains strong and flexible, allowing us to
take advantage of future opportunities in organic growth through
drilling or strategic growth through acquisitions. Our financial ratios
have also improved recently, our debt to PV-10 ratio decreased to 13%
at June 30, 2005 compared to 18% at December 31, 2004, due to higher
crude oil and natural gas prices and a slight decrease in our total
debt. Higher commodity prices have increased our PV-10 value. Our debt
to capitalization ratio was 40% at June 30, 2005 compared to 43% at
year-end 2004, as debt levels decreased slightly in 2005 and retained
earnings increased as a result of the current period profit.
There are a number of factors that support our belief that Swift
Energy's performance for the second half of 2005 will be strong as
well. We believe that strong commodity prices will continue over the
foreseeable future, based in part on forward-strip pricing. The
capacity increase of the facilities in Lake Washington is on schedule
to be completed late in the third quarter of 2005, as planned. Our 3-D
seismic data study of southern Louisiana has yielded its first
exploration success, although further delineation is planned, and an
apparent Palau discovery in New Zealand has early results that are
encouraging, although we remain cautious as the well needs to be
completed and tested. Significant work-over activity is expected to
take place in the second half of 2005, particularly in the Bay de Chene
and Cote Blanche Island fields in southern Louisiana. Our diversified
drilling portfolio positions us for higher impact exploration drilling
as well as expanded exploitation efforts in both the last half of 2005
and into 2006.
Results of Operations - Three Months Ended June 30, 2005 and 2004
Revenues. Our revenues in the second quarter of 2005 increased by
47% compared to revenues in the same period in 2004, due primarily to
an increase in commodity prices and our overall production volumes. Our
production increase was primarily a result of increased crude oil
production from our Lake Washington area and, to a lesser extent, the
Rimu/Kauri area. Revenues from our oil and gas sales comprised
substantially all of our net revenues for the second quarter of both
2005 and 2004. In the second quarter of 2005, oil production made up
54% of total production, natural gas made up 38%, and NGL represented
8%. In the second quarter of 2004, oil production made up 48% of total
production, natural gas made up 41%,
19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
and NGL represented 11%. The increase in the percentage of our total
production from oil is because production from Lake Washington is
almost entirely crude oil, production from this area has increased
significantly as a result of our continued development in the field.
Our second quarter of 2005 weighted average prices increased 31%
to $6.60 per Mcfe from $5.04 in the second quarter of 2004, with per
barrel oil prices appreciating 35% to $50.24 from $37.24 during the
same period in 2004, per Mcfe natural gas prices increasing 12% to
$4.67 from $4.19, and per barrel NGL prices rose 22% to $22.95 from
$18.84.
The following table sets forth our revenues from oil and gas sales
and the volumes underlying those sales from our core areas for the
three months ended June 30, 2005 and 2004, illustrating the changes
between the two periods:
Three Months Ended June 30,
---------------------------------------------------------------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
----
---------------------------------- -------------------------------------
2005 2004 2005 2004
---- ---- ---- ----
AWP Olmos $ 13.0 $ 12.5 1.9 2.1
Brookeland 4.1 4.7 0.7 0.9
Lake Washington 62.1 32.8 7.8 5.5
Masters Creek 4.4 5.4 0.7 1.0
Other 6.3 4.4 0.8 0.7
--------------- ---------------- -------------- --------------------
Total Domestic $ 89.9 $ 59.8 11.9 10.2
--------------- ---------------- --------------- --------------------
Rimu/Kauri 9.2 5.2 1.9 1.2
TAWN 5.8 6.8 2.1 2.9
--------------- ---------------- --------------- --------------------
Total New Zealand $ 15.0 $ 12.0 4.0 4.1
--------------- ---------------- --------------- --------------------
Total $ 104.9 $ 71.8 15.9 14.3
=============== ================ =============== ====================
The following table breaks down our sales volumes by commodity and
provides average sales prices for each commodity for the quarters
ending June 30, 2005 and 2004:
Sales Volume Average Sales Price
------------------------------------ --------------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
-------- ------- ------ --------- ------ ------ --------
2005
----
Three Months Ended June 30:
Domestic 1,339 118 3.2 11.9 $50.21 $25.74 $6.13
New Zealand 87 91 2.9 4.0 $50.82 $19.30 $3.05
-------- ------- ------ ---------
Total 1,426 209 6.1 15.9 $50.24 $22.95 $4.67
======== ======= ====== =========
2004
----
Three Months Ended June 30:
Domestic 1,021 179 3.0 10.2 $37.22 $19.42 $6.09
New Zealand 122 90 2.8 4.1 $37.37 $17.69 $2.13
-------- ------- ------ ---------
Total 1,143 269 5.8 14.3 $37.24 $18.84 $4.19
======== ======= ====== =========
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
In the second quarter of 2005, our $33.1 million increase in oil,
NGL, and natural gas sales over the same period in 2004 resulted from:
o Price variances that had a $22.4 million favorable impact on
sales, of which $18.6 million was attributable to the 35% increase
in average oil prices received, $2.9 million was attributable to
the 12% increase in average gas prices received, and $0.9 million
was attributable to the 22% increase in average NGL prices
received; and
o Volume variances that had a $10.7 million favorable impact on
sales, with $10.5 million of increases coming from the 284,000 Bbl
increase in oil sales volumes, $1.3 million of increases due to
the 0.3 Bcf increase in gas sales volumes, partially offset by a
$1.1 million decrease attributable to the 60,000 Bbl decrease in
NGL sales volumes.
Costs and Expenses. Our expenses in the second quarter of 2005
increased $11.5 million, or 22%, compared to expenses in the same
period of 2004. The increase was mainly due to a $9.3 million increase
in DD&A and a $3.8 million increase in severance and other taxes, both
of which are primarily due to increased production volumes and high oil
and gas prices in the second quarter of 2005. These cost increases in
the second quarter of 2005 were partially offset by debt retirement
costs that were incurred in the second quarter of 2004, which totaled
$2.7 million.
Our second quarter 2005 general and administrative expenses, net,
increased $0.8 million, or 20%, from the level of such expenses in the
same 2004 period. This increase was primarily due to an increase in
workforce, resulting in increased salaries and benefits, and due to the
continued costs of compliance initiatives related to the Sarbanes-Oxley
Act. Our net general and administrative expenses per Mcfe produced
increased to $0.31 per Mcfe in the second quarter of 2005 from $0.29
per Mcfe in the same 2004 period. For the second quarters of 2005 and
2004, our capitalized general and administrative costs totaled $4.7
million and $3.3 million, respectively. The portion of supervision fees
recorded as a reduction to general and administrative expenses was $2.1
million for the second quarter of 2005 and $1.2 million for the 2004
period.
DD&A increased $9.3 million, or 48%, in the second quarter of 2005
from the level of those expenses in the same period of 2004.
Domestically, DD&A increased $7.7 million in the second quarter of 2005
predominantly due to increases in our depletable oil and gas property
base including future development costs, higher production in the 2005
period and, to a lesser extent, lower reserve volumes than in the same
2004 period. In New Zealand, DD&A increased by $1.6 million in the
second quarter of 2005 due to increases in the depletable oil and gas
property base and lower reserve volumes than in the same 2004 period.
Our DD&A rate per Mcfe of production was $1.81 and $1.37 in the second
quarters of 2005 and 2004, respectively.
We recorded $0.2 million of accretions to our asset retirement
obligation in both the second quarters of 2005 and 2004.
Our lease operating costs per Mcfe produced were $0.73 in both the
second quarter of 2005 and 2004. Our second quarter 2005 level of lease
operating costs was better than anticipated due to lower than expected
chemical, repair and maintenance costs, as well as no significant
domestic work-over activity taking place in the quarter. Our lease
operating costs in the second quarter of 2005 increased $1.1 million,
or 11%, over the level of such expenses in the same 2004 period.
Approximately $0.6 of the increase was related to our domestic
operations, which increased primarily due to higher production from our
Lake Washington area. Our lease operating costs in New Zealand
increased in the second quarter of 2005 by $0.5 million due to higher
plant operating expenses and an increase in the New Zealand dollar
exchange rate.
In the second quarter of 2005, severance and other taxes increased
$3.8 million, or 55%, over levels in the second quarter of 2004. The
increase was due primarily to higher commodity prices and increased
Lake Washington and, to a lesser extent, Rimu/Kauri production in the
period. Severance taxes on oil in Louisiana are 12.5% of oil sales,
which is higher than in the other states where we have production. As
our percentage of oil production in Louisiana increases, the overall
percentage of severance costs to sales also will increase. Severance
and other taxes, as a percentage of oil and gas sales, were
approximately 10.2% and 9.6% in the second quarters of 2005 and 2004,
respectively.
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Interest expense on our 7-5/8% senior notes due 2011 issued in
June 2004, including amortization of debt issuance costs, totaled $3.0
million in the second quarter of 2005, and $0.2 million in the same
period in 2004. Interest expense on our 9-3/8% senior subordinated
notes due 2012 issued in April 2002, including amortization of debt
issuance costs, totaled $4.8 million in both the second quarter of 2005
and 2004. Interest expense on our 10-1/4% senior subordinated notes
issued in August 1999 and retired in 2004, including amortization of
debt issuance costs, totaled $3.3 million in the second quarter of
2004. Interest expense on our bank credit facility, including
commitment fees and amortization of debt issuance costs, totaled $0.2
million in the second quarter of 2005 and $0.5 million in the same
period in 2004. Our total interest cost in the second quarter of 2005
was $8.0 million, of which $1.7 million was capitalized. Our total
interest cost in the second quarter of 2004 was $8.8 million, of which
$1.6 million was capitalized. We capitalize a portion of interest
related to unproved properties. The decrease of interest expense in the
second quarter of 2005 was primarily attributable to the replacement of
our 10-1/4% senior subordinated notes with our 7-5/8% senior notes.
In the second quarter of 2004, we incurred $2.7 million of debt
retirement costs related to the repurchase of a portion of our 10-1/4%
senior subordinated notes due 2009 pursuant to a tender offer. The
costs were comprised of approximately $1.8 million of premiums paid to
repurchase the notes, $0.6 million to write-off unamortized debt
issuance costs, $0.2 million to write-off unamortized debt discount and
$0.1 million of other costs.
Our overall effective tax rate was 33.3% in the second quarter of
2005 and 35.5% in the same 2004 period. The effective income tax rate
for both the second quarter of 2005 and 2004 was lower than the
statutory tax rates primarily due to reductions from the New Zealand
statutory rate attributable to the currency effect on the New Zealand
deferred tax calculation. Additionally, the second quarter of 2005 rate
is lower due to a favorable correction in the New Zealand tax basis of
oil and gas properties.
Net Income. For the second quarter of 2005, our net income of
$27.9 million was 116% higher, and Basic EPS of $0.98 was 111% higher,
than our second quarter of 2004 net income of $12.9 million and Basic
EPS of $0.46. Our Diluted EPS in the second quarter of 2005 of $0.96
was 111% higher than our second quarter 2004 Diluted EPS of $0.46.
These higher amounts are due to our increased oil and gas revenues,
which in turn were higher due to continued strong commodity prices and
our increased production during the second quarter of 2005.
Results of Operations - Six Months Ended June 30, 2005 and 2004
Revenues. Our revenues in the first six months of 2005 increased by 47%
compared to revenues in the same period in 2004, due primarily to an
increase in commodity prices and production from our Lake Washington
area and, to a lesser extent, Rimu/Kauri area. Revenues from our oil
and gas sales comprised substantially all of net revenues for the first
half of 2005 and 2004. In the first six months of 2005, oil production
made up 52% of total production, natural gas made up 39%, and NGL
represented 9%. In the first six months of 2004, oil production made up
48% of total production, natural gas made up 41%, and NGL represented
11%. The increase in the percentage of our total production from oil is
because production from Lake Washington is almost entirely crude oil,
and production from this area has increased significantly as a result
of our continued development in the field.
Our first six months of 2005 weighted average prices increased 32%
to $6.38 per Mcfe from $4.83 in the first six months of 2004, with per
barrel oil prices appreciating 37% to $49.00 from $35.70 during the
first half of 2004, per Mcfe natural gas prices increasing 14% to $4.46
from $3.91, and per barrel NGL prices rose 21% to $24.94 from $20.60.
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
The following table sets forth our revenue from oil and gas sales
and the volumes underlying those sales from each of our core areas for
the six months ended June 30, 2005 and 2004, illustrating the changes
between the two periods:
Six Months Ended June 30,
---------------------------------------------------------------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
----
---------------------------------- --------------------------------------
2005 2004 2005 2004
---- ---- ---- ----
AWP Olmos $ 24.3 $ 24.3 3.8 4.8
Brookeland 8.1 9.3 1.4 1.9
Lake Washington 113.5 61.6 14.6 10.6
Masters Creek 9.1 10.6 1.5 2.0
Other 11.7 8.6 1.6 1.3
--------------- --------------- --------------- --------------------
Total Domestic $ 166.7 $ 114.4 22.9 20.6
--------------- --------------- --------------- --------------------
Rimu/Kauri 21.7 9.5 4.3 2.2
TAWN 12.0 13.8 4.2 5.7
--------------- --------------- --------------- --------------------
Total New Zealand $ 33.7 $ 23.4 8.5 7.9
--------------- --------------- --------------- --------------------
Total $ 200.4 $ 137.8 31.4 28.5
=============== =============== =============== ====================
The following table breaks down our sales volumes by commodity and
provides average sales prices for each commodity for the six months
ending June 30, 2005 and 2004:
Sales Volume Average Sales Price
------------------------------------ -------------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
-------- ------- ------ --------- ------- -------- --------
2005
----
Six Months Ended June 30:
Domestic 2,523 262 6.2 22.9 $48.79 $29.05 $5.78
New Zealand 224 170 6.2 8.5 $51.35 $18.60 $3.11
-------- ------- ------ ---------
Total 2,747 432 12.4 31.4 $49.00 $24.94 $4.46
======== ======= ====== =========
2004
----
Six Months Ended June 30:
Domestic 2,039 390 6.1 20.6 $35.59 $22.06 $5.49
New Zealand 228 157 5.6 7.9 $36.74 $16.97 $2.20
-------- ------- ------ ---------
Total 2,267 547 11.7 28.5 $35.70 $20.60 $3.91
======== ======= ======= =========
In the first six months of 2005, our $62.7 million increase in
oil, NGL, and natural gas sales resulted from:
o Price variances that had a $45.2 million favorable impact on
sales, of which $36.5 million was attributable to the 37% increase
in average oil prices received, $6.8 million was attributable to
the 14% increase in average gas prices received, and $1.9 million
was attributable to the 21% increase in average NGL prices
received; and
o Volume variances that had a $17.5 million favorable impact on
sales, with $17.1 million of increases coming from the 480,000 Bbl
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
increase in oil sales volumes, $2.7 million of increases due to
the 0.7 Bcf increase in gas sales volumes, partially offset by a
$2.4 million decrease attributable to the 115,000 Bbl decrease in
NGL sales volumes.
Costs and Expenses. Our expenses in the first six months of 2005
increased $22.1 million, or 23%, compared to expenses in the same
period of 2004. The increase was due to a $15.2 million increase in
DD&A, a $6.7 million increase in severance and other taxes, and a $2.6
million increase in lease operating costs, all of which are primarily
due to increased production volumes and high oil and gas prices in the
first six months of 2005. These cost increases in the first six months
of 2005 were partially offset by debt retirement costs that were
incurred in the first six months of 2004, which totaled $2.7 million.
Our first six months of 2005 general and administrative expenses,
net, increased $1.7 million, or 20%, from the level of such expenses in
the same 2004 period. This increase was primarily due to an increase in
workforce, resulting in increased salaries and benefits, and due to the
continued costs of compliance initiatives related to the Sarbanes-Oxley
Act. Our net general and administrative expenses per Mcfe produced
increased to $0.31 per Mcfe in the first half of 2005 from $0.29 per
Mcfe in the same 2004 period. For the first six months of 2005 and
2004, our capitalized general and administrative costs totaled $8.8
million and $6.2 million, respectively. The portion of supervision fees
recorded as a reduction to general and administrative expenses was $3.8
million for the first six months of 2005 and $2.5 million for the 2004
period.
DD&A increased $15.2 million, or 40%, in the first six months of
2005 from the level of those expenses in the same period of 2004.
Domestically, DD&A increased $10.8 million in the first half of 2005
due to increases in the depletable oil and gas property base including
future development costs and higher production in the 2005 period. In
New Zealand, DD&A increased by $4.4 million in the first half of 2005
due to increases in the depletable oil and gas property base, higher
production in the 2005 period and lower reserve volumes than in the
same 2004 period. Our DD&A rate per Mcfe of production was $1.69 and
$1.32 in the first six months of 2005 and 2004, respectively.
We recorded $0.4 million of accretions to our asset retirement
obligation in the first six months of 2005 and $0.3 million in the same
period of 2004.
Our lease operating costs per Mcfe produced were $0.72 in the
first six months of 2005 and $0.70 in the 2004 period. Our lease
operating costs in the first half of 2005 increased $2.6 million, or
13%, over the level of such expenses in the same 2004 period.
Approximately $1.9 million of the increase was related to our domestic
operations, which increased primarily due to higher production from our
Lake Washington area. Our lease operating costs in New Zealand
increased in the first half of 2005 by $0.7 million due to higher plant
operating expenses, an increase in the New Zealand dollar exchange rate
and higher production in the Rimu/Kauri area partially offset by the
decline in the TAWN area.
In the first six months of 2005, severance and other taxes
increased $6.7 million, or 51%, over levels in the first six months of
2004. The increase was due primarily to higher commodity prices and
increased Lake Washington and Rimu/Kauri production in the period.
Severance taxes on oil in Louisiana are 12.5% of oil sales, which is
higher than in the other states where we have production. As our
percentage of oil production in Louisiana increases, the overall
percentage of severance costs to sales also increases. Severance and
other taxes, as a percentage of oil and gas sales, were approximately
9.9% and 9.6% in the first half of 2005 and 2004, respectively.
Interest expense on our 7-5/8% senior notes due 2011 issued in
June 2004, including amortization of debt issuance costs, totaled $5.9
million in the first six months of 2005 and $0.2 million in the same
2004 period, which was the period these notes were issued and the
10-1/4% senior subordinated notes were retired. Interest expense on our
9-3/8% senior subordinated notes due 2012 issued in April 2002,
including amortization of debt issuance costs, totaled $9.6 million in
both the first six months of 2005 and 2004. Interest expense on our
10-1/4% senior subordinated notes issued in August 1999 and retired in
2004, including amortization of debt issuance costs, totaled $6.6
million in the first six months of 2004. Interest expense on our bank
credit facility, including commitment fees and amortization of debt
issuance costs, totaled $0.6 million in the first six months of 2005
24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
and $0.9 million in the same period in 2004. Our total interest cost in
the first six months of 2005 was $16.1 million, of which $3.5 million
was capitalized. Our total interest cost in the first six months of
2004 was $17.3 million, of which $3.2 million was capitalized. We
capitalize a portion of interest related to unproved properties. The
decrease of interest expense in the first six months of 2005 was
primarily attributable to the replacement of our 10-1/4% senior
subordinated notes with our 7-5/8% senior notes.
In the first six months of 2004, we incurred $2.7 million of debt
retirement costs related to the repurchase of a portion of our 10-1/4%
senior subordinated notes pursuant to a tender offer. The costs were
comprised of approximately $1.8 million of premiums paid to repurchase
the notes, $0.6 million to write-off unamortized debt issuance costs,
$0.2 million to write-off unamortized debt discount and $0.1 million of
other costs.
Our overall effective tax rate was 34.3% in the first six months
of 2005 and 31.4% in the same 2004 period. The effective income tax
rate for both the first six months of 2005 and 2004 was lower than the
statutory tax rates primarily due to reductions from the New Zealand
statutory rate attributable to the currency effect on the New Zealand
deferred tax calculation. Both the first six months of 2005 and 2004
also included reductions in tax expense primarily attributable to an
adjustment of the tax basis of the TAWN properties, which were acquired
in 2002.
Net Income. For the first six months of 2005, our net income of
$53.6 million was 95% higher, and Basic EPS of $1.90 was 91% higher,
than our first half of 2004 net income of $27.5 million and Basic EPS
of $0.99. Our Diluted EPS in the first six months of 2005 of $1.86 was
90% higher than our first half 2004 Diluted EPS of $0.98. These higher
amounts are due to our increased oil and gas revenues, which in turn
were higher due to continued strong commodity prices and our increased
production during the first six months of 2005.
Contractual Commitments and Obligations
We had no material changes in our contractual commitments and
obligations from December 31, 2004 amounts referenced in our Annual
Report on Form 10-K for the period ending December 31, 2004.
Commodity Price Trends and Uncertainties
Oil and natural gas prices historically have been volatile and are
expected to continue to be volatile in the future. The price of oil has
increased over the last two years and is currently at record highs when
compared to longer-term historical prices. Factors such as geopolitical
activities, worldwide supply disruptions, worldwide economic
conditions, weather conditions, actions taken by OPEC, and fluctuating
currency exchange rates can cause wide fluctuations in the price of
oil. Domestic natural gas prices continue to remain high when compared
to longer-term historical prices. North American weather conditions,
the industrial and consumer demand for natural gas, storage levels of
natural gas, and the availability and accessibility of natural gas
deposits in North America can cause significant fluctuations in the
price of natural gas. Such factors are beyond our control.
Income Tax Regulations
The tax laws in the jurisdictions we operate in are continuously
changing and professional judgments regarding such tax laws can differ.
We do not believe the recently enacted American Jobs Creation Act of
2004 will have a material impact on our financial position or cash flow
from operations in the near-term.
Liquidity and Capital Resources
During the first six months of 2005, we relied upon our net cash
provided by operating activities of $129.3 million to fund capital
expenditures of $101.8 million and to pay down our bank borrowings by
$7.5 million. During the first six months of 2004, we largely relied
upon our net cash provided by operating activities of $77.1 million and
proceeds from the offering of our 7-5/8% senior notes due 2011 of
$150.0 million to fund capital expenditures of $85.9 million,
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
repurchase $32.1 million of our 10-1/4% senior subordinated notes due
2009, and repay all outstanding indebtedness under our bank credit
facility.
Net Cash Provided by Operating Activities. For the first six
months of 2005, our net cash provided by operating activities was
$129.3 million, representing a 68% increase as compared to $77.1
million generated during the same 2004 period. The $52.2 million
increase in the first six months of 2005 was primarily due to an
increase of $62.7 million in oil and gas sales, attributable to higher
commodity prices and production, offset in part by higher lease
operating costs due to higher production and severance taxes.
Accounts Receivable. Included in the "Accounts receivable"
balance, which totaled $46.9 million and $39.0 million at June 30, 2005
and December 31, 2004, respectively, on the accompanying balance
sheets, is approximately $2.3 million of receivables related to
hydrocarbon volumes produced from 2001 and 2002 that have been disputed
since early 2003. As a result of the dispute, we did not record a
receivable with regard to any 2003 disputed volumes and our contract
governing these sales expired in 2003. Based on settlement discussions,
we settled our claim with this counter-party in July 2005 by receiving
a cash payment for less than our gross receivable. Accordingly, in the
second quarter of 2005, we increased our reserve for this claim by
approximately $0.6 million, which is recorded in "Price-risk management
and other, net" on the accompanying statements of income.
We assess the collectibility of accounts receivable, and based on
our judgment, we accrue a reserve when we believe a receivable may not
be collected. At June 30, 2005 and December 31, 2004, we had an
allowance for doubtful accounts of $1.0 million and $0.5 million,
respectively. The allowance for doubtful accounts has been deducted
from the total "Accounts receivable" balances on the accompanying
balance sheets.
Bank Credit Facility. We had no borrowings under our bank credit
facility at June 30, 2005, and $7.5 million in outstanding borrowings
at December 31, 2004. Our bank credit facility at June 30, 2005
consisted of a $400.0 million revolving line of credit with a $250.0
million borrowing base. The borrowing base is re-determined at least
every six months and was reaffirmed by our bank group at $250.0
million, effective May 1, 2005. We maintained the commitment amount at
$150.0 million, which amount was set at our request effective May 9,
2003. We can increase this commitment amount to the total amount of the
borrowing base at our discretion, subject to the terms of the credit
agreement. Our revolving credit facility includes, among other
restrictions that changed somewhat as the facility was renewed and
extended, requirements to maintain certain minimum financial ratios
(principally pertaining to adjusted working capital ratios and
EBITDAX), and limitations on incurring other debt. We are in compliance
with the provisions of this agreement.
Our access to funds from our credit facility is not restricted
under any "material adverse condition" clause, a clause that is common
for credit agreements to include. A "material adverse condition" clause
can remove the obligation of the banks to fund the credit line if any
condition or event would reasonably be expected to have an adverse or
material effect on our operations, financial condition, prospects or
properties, and would impair our ability to make timely debt
repayments. Our credit facility includes covenants that require us to
report events or conditions having a material adverse effect on our
financial condition. The obligation of the banks to fund the credit
facility is not conditioned on the absence of a material adverse
effect.
Debt Maturities. Our credit facility extends until October 1,
2008. Our $150.0 million of 7-5/8% senior notes mature July 15, 2011,
and our $200.0 million of 9-3/8% senior subordinated notes mature May
1, 2012.
Working Capital. Our working capital improved from a deficit of
$14.2 million at December 31, 2004, to a surplus of $13.7 million at
June 30, 2005. The improvement primarily resulted from an increase in
our cash balances due to increased cash flows from operating activities
and an increases in oil and gas sales receivables due to increased
production and commodity pricing from year-end 2004 levels.
26
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Capital Expenditures. In the first six months of 2005, we relied
upon our net cash provided by operating activities of $129.3 million to
fund total capital expenditures of $101.8 million in the first six
months of 2005, which included:
Domestic expenditures of $67.6 million as follows:
o $54.7 million for drilling and developmental activity
costs, predominantly in our Lake Washington and AWP areas;
o $11.6 million of domestic prospect costs, principally
prospect leasehold, activity, and geological costs of
unproved prospects;
o $1.2 million primarily for a field office building,
computer equipment, software, furniture, and fixtures;
o less than $0.1 million on gas processing plants in the
Brookeland and Masters Creek areas.
New Zealand expenditures of $34.2 million as follows:
o $ 30.0 million for drilling and developmental activity
costs;
o $3.7 million on prospect costs and geological costs of
unproved properties;
o $0.4 million on gas processing plants;
o and $0.1 million for computer equipment, software,
furniture, and fixtures.
We successfully completed 27 of 39 wells in the first six months
of 2005, for a success rate of 69%. Domestically, we completed 23 of 29
development wells for a success rate of 79% and completed three of four
exploration wells during the first six months of 2005. During the same
period, a total of 24 wells were drilled in the Lake Washington area,
of which 17 were completed; eight wells were drilled in the AWP Olmos
area and all were completed, and one non-operated well was drilled in
the Brookeland area and was completed. In New Zealand during the first
six months of 2005, we drilled five development wells, one was
successful, and one exploratory well which was unsuccessful.
For the last six months of 2005, we expect to make capital
expenditures of approximately $120 to $140 million. Our current
estimated total capital expenditures for 2005 continue to be
approximately $220 to $240 million, excluding acquisition costs and net
of approximately $5 million to $15 million in non-core property
dispositions. These estimated 2005 amounts include an increase of
approximately $20 million due to higher drilling and services costs
over prior year levels. Capital expenditures for 2004 were $198
million.
If producing property acquisitions become attractive during the
remaining six months of 2005, we will explore the use of debt and/or
equity offerings, along with using our cash flows in excess of capital
expenditures, to fund any such acquisition.
During the last six months of 2005, we anticipate drilling or
participating in the drilling of up to an additional 13 to 17 wells in
the Lake Washington area, an additional 4 to 7 wells in the AWP Olmos
area, and several additional wells, with varying working interest
percentages, mainly in South Texas. In addition, we plan on drilling 4
to 6 wells in New Zealand.
Our 2005 capital expenditures continue to be focused on developing
and producing long-lived reserves in our Lake Washington, AWP Olmos,
and Rimu/Kauri area. We expect our 2005 total production to increase
over 2004 levels, primarily from the Lake Washington, Bay de Chene,
Cote Blanche Island and Rimu/Kauri areas. We expect production in our
other core areas to decrease as limited new drilling is currently
budgeted to offset the natural production decline of these properties.
For 2005, based upon our progress to date and planned activities for
27
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
the remainder of the year, we estimate our total production to increase
10% to 14%, or approximately 64.0 Bcfe to 66.5 Bcfe, and estimate that
proved reserves will increase 5% to 10%, both over 2004 levels.
New Accounting Pronouncements
In September and November 2004, and March 2005, the EITF discussed
a proposed framework for addressing when a limited partnership should
be consolidated by its general partner, EITF Issue 04-5. The proposed
framework presumes that a sole general partner in a limited partnership
controls the limited partnership, and therefore should consolidate the
limited partnership. The presumption of control can be overcome if the
limited partners have (a) the substantive ability to remove the sole
general partner or otherwise dissolve the limited partnership or (b)
substantive participating rights. The EITF reached a tentative
conclusion on the circumstances in which either kick-out rights or
participating rights would be considered substantive and preclude
consolidation by the general partner and what limited partner's rights
would be considered participating rights that would preclude
consolidation by the general partner. The EITF tentatively concluded
that for kick-out rights to be considered substantive, the conditions
specified in paragraph B20 of FIN 46R should be met. With regard to the
definition of participating rights that would preclude consolidation by
the general partner, the EITF concluded that the definition of those
rights should be consistent with those in EITF Issue 96-16. The EITF
also reached a tentative conclusion on the transition for Issue 04-05.
The FASB ratified the EITF consensus at the June 2005 EITF meeting. We
do not believe this EITF will have a material impact on our
consolidated financial statements because we believe our limited
partners have substantive kick-out rights under paragraph B20 of FIN
46R.
In December 2004, the FASB issued SFAS No. 123R, Share-Based
Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting for
Stock-Based Compensation, and supercedes APB Opinion No. 25, Accounting
for Stock Issued to Employees, and amends SFAS No. 95, Statement of
Cash Flows. SFAS No. 123R requires all employee share-based payments,
including grants of employee stock options, to be recognized in the
financial statements based on their fair values. SFAS No. 123
discontinues the ability to account for these equity instruments under
the intrinsic value method as described in APB Opinion No. 25. SFAS No.
123R requires the use of an option pricing model for estimating fair
value, which is amortized to expense over the service periods. The
requirements of SFAS No. 123R are effective for fiscal periods
beginning after June 15, 2005. SFAS No. 123R permits public companies
to adopt its requirements using one of two methods:
o A "modified prospective" method in which compensation cost is
recognized beginning with the effective date based on the
requirements of SFAS No. 123R for all share-based payments granted
after the effective date and based on the requirements of SFAS No.
123 for all awards granted to employees prior to the adoption date
of SFAS No. 123R that remain unvested on the adoption date.
o A "modified retrospective" method which includes the requirements
of the modified prospective method described above, but also
permits entities to restate either all prior periods presented or
prior interim periods of the year of adoption based on the amounts
previously recognized under SFAS No. 123 for purposes of pro forma
disclosures.
In April 2005, the SEC issued a release announcing that it would
provide for a phased-in implementation process for SFAS No. 123R. As a
result, our required date to adopt SFAS No. 123R is now January 1,
2006. Also in April 2005, the SEC issued Staff Accounting Bulleting No.
107, Share-Based Payment, which provides guidance on the implementation
of SFAS No. 123R. SAB No. 107 provides guidance on valuing options,
estimating volatility and expected terms of the option awards, and
discusses the SEC's views on share-based payment transactions with
non-employees, the capitalization of compensation cost and accounting
for income tax effects of share-based payment arrangements upon
adoption of SFAS No. 123R.
We have elected to adopt the provisions of SFAS No. 123R on
January 1, 2006 using the modified prospective method. As permitted by
Statement 123, the Company currently accounts for share-based payments
to employees using APB Opinion No. 25's intrinsic value method and, as
28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
such, generally recognizes no compensation cost for employee stock
options. Accordingly, the adoption of Statement No. 123R's fair value
method is expected to have a significant impact on our results of
operations. However, it will have no impact on our overall financial
position. We currently use the Black-Scholes formula to estimate the
value of stock options granted to employees and expect to continue to
use this acceptable option valuation model upon the required adoption
of SFAS No. 123R. The significance of the impact of adoption will
depend on levels of outstanding unvested share-based payments on the
date of adoption and share-based payments granted in the future.
However, had we adopted Statement No. 123R in prior periods, the impact
of that standard would have approximated the impact of Statement No.
123 as described in the disclosure of pro forma net income and earnings
per share under "Stock Based Compensation" above.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and
Error Corrections: a replacement of APB Opinion No. 20 and FASB
Statement No. 3. SFAS No. 154 requires voluntary changes in accounting
principles to be applied retrospectively, unless it is impracticable.
SFAS No. 154's retrospective application requirement replaces APB 20's
requirement to recognize most voluntary changes in accounting principle
by including in net income of the period of the change the cumulative
effect of changing to the new accounting principle. If retrospective
application for all prior periods is impracticable, the method used to
report the change and the reason the retrospective application is
impracticable are to be disclosed.
Under SFAS No. 154, retrospective application will be the
transition method in the unusual instance that a newly issued
accounting pronouncement does not provide specific transition guidance.
It is expected that many pronouncements will specify transition methods
other than retrospective. SFAS No. 154 is effective for accounting
changes made in fiscal years beginning after December 15, 2005, and the
adoption of this statement is expected to have no impact on our
financial position or results of operations.
In July 2005, the FASB issued an exposure draft "Accounting for
Uncertain Tax Positions, a proposed interpretation of FASB Statement
No. 109." The proposed interpretation would apply to all open tax
positions under FASB No. 109. The conclusions in this interpretation
include: initial recognition of tax benefits, recognition and
de-recognition of tax positions, measurement of tax benefits and
classifications of tax liabilities. The comment period on this exposure
draft ends in September 2005, and we are currently assessing the
impact, if any, that this interpretation would have on our financial
position and results of operations. The proposal enactment date would
require application effective December 31, 2005.
New Developments
Petroleum Mining Permit 38155. In April 2005, Swift Energy New
Zealand ("SENZ") was awarded petroleum mining permit ("PMP") 38155 by
the New Zealand Government, for the development of our Kauri Sand and
Manutahi Sand discoveries. The PMP 38155 mining permit covers 8,708
acres and allows us to fully develop our Kauri area for a primary term
of 30 years.
Petroleum Exploration Permit 38495. In April 2005, Swift Energy
New Zealand ("SENZ") was awarded petroleum exploration permit ("PEP")
38495 by the New Zealand Government. Following the award of PEP 38495,
SENZ initiated a farm-in agreement with Mighty River Power ("MRP"),
whereby SENZ agreed to transfer a 50% interest in the permit to MRP in
return for MRP funding various seismic operations during 2005 and 2006.
PEP 38495 is located offshore in the southern portion of the basin to
the south and west of our PEP 38719 and encompasses approximately 600
square miles.
29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
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 the uncertainty of finding, replacing, developing or
acquiring reserves; the uncertainty of drilling results and reserve
estimates; damage to operations or decreased production due to
hurricanes or tropical storms; operating hazards; availability of
equipment, services or supplies; changes in geologic or engineering
information; geopolitical events; volatility in oil and gas prices;
fluctuations of demand for our oil and natural gas; changes in market
conditions; increased competition; and government regulations; as well
as the risks and uncertainties 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, expected increases in development
costs and other factors, interim results are not necessarily indicative
of those for a full year.
30
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Risk
Our major market risk exposure is the volatile commodity pricing
applicable to our oil and natural gas production. Realized commodity
prices received for such production are primarily driven by the
prevailing worldwide price for crude oil and spot prices applicable to
natural gas. The effects of such pricing volatility are expected to
continue.
Our price-risk management policy permits the utilization of
derivative instruments (such as futures, forward contracts, swaps, and
option contracts such as floors and collars) to mitigate price risk
associated with fluctuations in oil and natural gas prices. Below is a
description of the derivative instruments we have utilized to hedge our
exposure to price risk.
oPrice Floors - At June 30, 2005, we had in place price floors in
effect through the December 2005 contract month for natural gas,
which cover 30% to 35% of our estimated domestic natural gas
production for July 2005 to December 2005. The natural gas price
floors cover notional volumes of 2,300,000 MMBtu, and expire at
various dates from July 2005 to December 2005, with a weighted
average floor price of $5.71 per MMBtu.
oNew Zealand Gas Contracts - Almost all of our current gas production
in New Zealand is sold under long-term, fixed-price contracts
denominated in New Zealand dollars. These contracts protect against
price volatility, and our revenue from these contracts will vary
only due to production fluctuations and foreign exchange rates.
Customer Credit Risk
We are exposed to the risk of financial non-performance by
customers. Our ability to collect on sales to our customers is
dependent on the liquidity of our customer base. To manage customer
credit risk, we monitor credit ratings of customers and seek to
minimize exposure to any one customer where other customers are readily
available. Due to availability of other purchasers, we do not believe
that the loss of any single oil or gas customer would have a material
adverse effect on our financial position or results of operations.
Foreign Currency Risk
We are exposed to the risk of fluctuations in foreign currencies,
most notably the New Zealand dollar. Fluctuations in rates between the
New Zealand dollar and U.S. dollar may impact our financial results
from our New Zealand subsidiaries since we have receivables,
liabilities, natural gas and NGL sales contracts, and New Zealand
income tax calculations, all denominated in New Zealand dollars.
Interest Rate Risk
Our 7-5/8% senior notes due 2011 and 9-3/8% senior subordinated
notes due 2012 have fixed interest rates, consequently we are not
exposed to cash flow risk from market interest rate changes on these
notes. However, there is a risk that market rates will decline and the
required interest payments on these notes may exceed those payments
based on the current market rate. At June 30, 2005, we had no
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 60
basis points and would not have a material adverse effect on our 2005
cash flows based on this same level or a modest level of borrowing.
31
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure
that information required to be disclosed in our filings under the
Securities and Exchange Act of 1934 is recorded, processed, summarized
and reported within the time periods specified in the Securities and
Exchange Commission rules and forms. Our chief executive officer and
chief financial officer have evaluated our disclosure controls and
procedures as of the end of the period covered by this report and have
concluded that such disclosure controls and procedures are effective in
ensuring that material information required to be disclosed in this
report is accumulated and communicated to them and our management to
allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
There was no change in our internal control over financial
reporting during the second quarter of 2005 that has materially
affected, or is reasonably likely to materially affect, our internal
control over financial reporting.
32
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. Unregistered Sales of Equity Securities and Use of Proceeds - None
Item 3. Defaults Upon Senior Securities - None
Item 4. Submission of Matters to a Vote of Security Holders -
Our annual meeting of shareholders was held on May 10, 2005. At the record date,
28,222,966 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 2008 annual meeting of shareholders:
FOR WITHHELD
NOMINEES FOR DIRECTORS
Deanna L. Cannon 23,693,494 2,562,363
Douglas J. Lanier 23,691,491 2,564,366
Bruce H. Vincent 20,663,780 5,592,077
The terms of directors Raymond E. Galvin, Clyde W. Smith, Jr., Terry E. Swift
expire at the 2006 annual meeting and the terms of directors A. Earl Swift, Greg
Matiuk and Henry C. Montgomery expire at the 2007 annual meeting.
Item 5. Other Information - None
Item 6. Exhibits
31.1 Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
32 Certification of Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
33
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 5, 2005 By: (original signed by)
------------------ ---------------------------------
Alton D. Heckaman, Jr.
Executive Vice President
Chief Financial Officer
Date: August 5, 2005 By: (original signed by)
------------------ ---------------------------------
David W. Wesson
Controller and Principal
Accounting Officer
34
Exhibit 31.1
CERTIFICATION
I, Terry E. Swift, certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended June
30, 2005, of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the
registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such
internal control over financial reporting, to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: August 5, 2005 /s/ Terry E. Swift
----------------------------------------------------
Terry E. Swift
Chief Executive Officer
35
Exhibit 31.2
CERTIFICATION
I, Alton D. Heckaman, Jr., certify that:
1. I have reviewed this Quarterly Report on Form 10-Q for the period ended June
30, 2005, of Swift Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the
registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such
internal control over financial reporting, to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and
procedures and presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over
financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control over
financial reporting.
Date: August 5, 2005 /s/ Alton D. Heckaman, Jr.
------------------------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President - Chief Financial Officer
36
Exhibit 32
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Quarterly Report on Form 10-Q for the period
ended June 30, 2005 (the "Report") of Swift Energy Company ("Swift") as filed
with the Securities and Exchange Commission on August 5, 2005, 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 5, 2005
/s/ Alton D. Heckaman, Jr.
-------------------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President - Chief Financial Officer
Dated: August 5, 2005
/s/ Terry E. Swift
-------------------------------------------------
Terry E. Swift
Chief Executive Officer
37