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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2005
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in its Charter)
TEXAS 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Drive, Suite 400
Houston, Texas 77060
(Address of principal executive offices) (Zip Code)
(281) 874-2700
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities and Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----------- ----------
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes X No
----------- ----------
Indicate the number of shares outstanding of each of the Issuer's classes of
common stock, as of the latest practicable date.
Common Stock 28,333,043 Shares
($.01 Par Value) (Outstanding at April 30, 2005)
(Class of Stock)
1
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005
INDEX
PART I - FINANCIAL INFORMATION PAGE
Item 1. Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets
- March 31, 2005 and December 31, 2004 3
Condensed Consolidated Statements of Income
- For the Three month period ended March 31, 2005 and 2004 4
Condensed Consolidated Statements of Stockholders' Equity
- For the Three month period ended March 31, 2005 and
year ended December 31, 2004 5
Condensed Consolidated Statements of Cash Flows
- For the Three month period ended March 31, 2005 and 2004 6
Notes to Condensed Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 19
Item 3. Quantitative and Qualitative Disclosures About Market Risk 28
Item 4. Controls and Procedures 29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 30
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 None
Item 5. Other Information 30
Item 6. Exhibits 30
SIGNATURES 31
2
CONDENSED CONSOLIDATED BALANCE SHEETS
SWIFT ENERGY COMPANY
March 31, 2005 December 31, 2004
---------------------- -------------------------
ASSETS
Current Assets:
Cash and cash equivalents ................................... $ 9,714,592 $ 4,920,118
Accounts receivable -
Oil and gas sales ......................................... 39,651,825 38,029,409
Joint interest owners ..................................... 780,972 1,013,938
Other current assets ........................................ 12,919,971 10,422,531
--------------------- -------------------------
Total Current Assets .................................... 63,067,360 54,385,996
--------------------- -------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized ......................... 1,526,524,713 1,479,681,903
Unproved properties not being amortized ................... 78,598,390 80,121,509
---------------------- -------------------------
1,605,123,103 1,559,803,412
Furniture, fixtures, and other equipment .................... 13,508,448 12,820,622
---------------------- -------------------------
1,618,631,551 1,572,624,034
Less-Accumulated depreciation, depletion,
and amortization .......................................
(673,288,705) (649,185,874)
---------------------- -------------------------
945,342,846 923,438,160
---------------------- -------------------------
Other Assets:
Deferred income taxes ....................................... --- 1,666,058
Debt issuance costs ......................................... 8,873,058 9,148,977
Restricted assets ........................................... 1,982,124 1,933,956
---------------------- -------------------------
10,855,182 12,748,991
---------------------- -------------------------
$ 1,019,265,388 $ 990,573,147
====================== =========================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities .................... $ 21,603,028 $ 29,406,877
Accrued capital costs ....................................... 27,238,961 22,489,467
Accrued interest ............................................ 10,346,388 9,209,192
Undistributed oil and gas revenues .......................... 7,503,261 7,512,755
---------------------- -------------------------
Total Current Liabilities ............................... 66,691,638 68,618,291
---------------------- -------------------------
Long-Term Debt ................................................ 350,000,000 357,500,000
Deferred Income Taxes ......................................... 84,774,868 73,106,580
Asset Retirement Obligation ................................... 16,328,853 17,176,136
Lease Incentive Obligation.. .................................. 135,828 ---
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000
shares authorized, none outstanding ....................... --- ---
Common stock, $.01 par value, 85,000,000 share authorized,
28,682,536 and 28,570,632 shares issued, and 28,233,092
and 28,089,764 shares outstanding, respectively ........... 286,825 285,706
Additional paid-in capital .................................. 345,479,463 343,536,298
Treasury stock held, at cost, 449,444 and
480,868 shares, respectively .............................. (6,445,586) (6,896,245)
Unearned Compensation........................................ (1,643,577) (1,728,585)
Retained earnings ........................................... 164,213,453 138,524,301
Accumulated Other comprehensive income (loss), net of taxes.. (556,377) 450,665
---------------------- -------------------------
501,334,201 474,172,140
---------------------- -------------------------
$ 1,019,265,388 $ 990,573,147
====================== =========================
See accompanying notes to condensed consolidated financial statements.
3
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
SWIFT ENERGY COMPANY
Three Months Ended
----------------------------------
03/31/05 03/31/04
----------------- ---------------
Revenues:
Oil and gas sales ................................. $ 95,521,333 $ 65,953,770
Price-risk management and other, net .............. 99,351 (598,040)
----------------- ---------------
95,620,684 65,355,730
----------------- ---------------
Costs and Expenses:
General and administrative, net ................... 4,874,308 4,029,674
Depreciation, depletion and amortization ......... 24,205,378 18,295,684
Accretion of asset retirement obligation .......... 186,507 170,476
Lease operating costs ............................. 11,048,782 9,625,980
Severance and other taxes ......................... 9,203,081 6,246,559
Interest expense, net ............................. 6,344,009 6,901,175
----------------- ---------------
55,862,065 45,269,548
----------------- ---------------
Income Before Income Taxes .......................... 39,758,619 20,086,182
Provision for Income Taxes .......................... 14,069,467 5,498,328
----------------- ---------------
Net Income ................................ $ 25,689,152 $ 14,587,854
================= ===============
Per share amounts
Basic: Net Income ............................. $ 0.91 $ 0.53
================= ===============
Diluted: Net Income ............................ $ 0.89 $ 0.52
================= ===============
Weighted Average Shares Outstanding ................. 28,160,949 27,552,827
================= ===============
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 --- --- --- --- 502,601
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
(111,904 shares) 1,119 851,103 --- --- --- --- 852,222
Tax benefits from exercise
of stock options --- 552,778 --- --- --- --- 552,778
Issuance of restricted stock --- 104,150 --- --- --- --- 104,150
Amortization of restricted stock --- --- --- 85,008 --- --- 85,008
Net income --- --- --- --- 25,689,152 --- 25,689,152
Other Comprehensive Loss --- --- --- --- --- (1,007,042) (1,007,042)
-------------
Total Comprehensive Income 24,682,110
----------- ------------- ------------- ------------ ------------ --------------- -------------
Balance, March 31, 2005 $ 286,825 $ 345,479,463 $ (6,445,586)$ (1,643,577)$164,213,453 $ (556,377)$ 501,334,201
=========== ============= ============= ============ ============ =============== =============
(1) $.01 Par Value
See accompanying notes to condensed consolidated financial statements.
5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
SWIFT ENERGY COMPANY
Period Ended March 31,
-------------------------------------------------
2005 2004
--------------------- -----------------------
Cash Flows From Operating Activities:
Net income ............................................................ $ 25,689,152 $ 14,587,854
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization ........................... 24,205,378 18,295,684
Accretion of asset retirement obligation ............................ 186,507 170,476
Deferred income taxes ............................................... 14,069,467 5,434,312
Other ............................................................... 985,389 274,125
Change in assets and liabilities -
Increase in accounts receivable ................................... (18,122) (2,021,976)
Increase (decrease) in accounts payable and accrued liabilities ... (1,603,411) 1,531,695
Increase in accrued interest ...................................... 1,137,196 1,323,570
--------------------- -----------------------
Net Cash Provided by Operating Activities ................... 64,651,556 39,595,740
--------------------- -----------------------
Cash Flows From Investing Activities:
Additions to property and equipment ................................... (44,526,775) (45,149,834)
Proceeds from the sale of property and equipment ...................... 121,777 23,255
Net cash distributed as operator of
oil and gas properties .............................................. (7,913,657) (8,707,560)
Net cash received (distributed) as operator of partnerships
and joint ventures .................................................. (884,798) 105,566
Other ................................................................. 4,977 (934)
--------------------- -----------------------
Net Cash Used in Investing Activities ....................... (53,198,476) (53,729,507)
--------------------- -----------------------
Cash Flows From Financing Activities:
Net proceeds from (payments of) bank borrowings ....................... (7,500,000) 16,600,000
Net proceeds from issuances of common stock ........................... 841,394 866,068
--------------------- -----------------------
Net Cash Provided by (Used in) Financing Activities.......... (6,658,606) 17,466,068
--------------------- -----------------------
Net Increase in Cash and Cash Equivalents ............................... 4,794,474 3,332,301
Cash and Cash Equivalents at Beginning of Period ........................ 4,920,118 1,066,280
--------------------- -----------------------
Cash and Cash Equivalents at End of Period .............................. $ 9,714,592 $ 4,398,581
===================== =======================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized ........................................................... $ 4,923,109 $ 5,300,358
Cash paid during period for income taxes ................................ $ --- $ ---
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 three months ended March 31, 2005 and 2004, such
internal costs capitalized totaled $4.1 million and $2.9 million,
respectively. Interest costs are also capitalized to unproved oil and gas
properties. For the three months ended March 31, 2005 and 2004,
capitalized interest on unproved properties totaled $1.8 million, and $1.6
million, respectively. Interest not capitalized and general and
administrative costs related to production and general overhead are
expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil
and gas properties, except in transactions involving a significant amount
of reserves or where the proceeds from the sale of oil and gas properties
would significantly alter the relationship between capitalized costs and
proved reserves of oil and gas attributable to a cost center. Internal
costs associated with selling properties are expensed as incurred.
Future development costs are estimated property-by-property based on
current economic conditions and are amortized to expense as our
capitalized oil and gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization
of oil and gas properties by the unit-of-production method. Under this
method, we compute the provision by multiplying the total unamortized
costs of oil and gas properties--including future development costs, gas
processing facilities, and 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, held 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.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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 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 March 31, 2005 consisted mainly 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 depreciation,
depletion, and amortization ("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.
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 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.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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 March 31, 2005, we did not have any
material natural gas imbalances.
Accounts Receivable
Included in the "Accounts receivable" balance, which totaled $40.4
million and $39.0 million at March 31, 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.
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 both March 31, 2005 and December 31, 2004, we had an
allowance for doubtful accounts of $0.5 million. 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
March 31, 2005 December 31,2004
(000's) (000's)
---------------- ----------------
Materials, Supplies and Tubulars... $ 10,196 $ 6,417
Crude Oil ......................... 559 770
---------------- ----------------
Total ...................... $ 10,755 $ 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.
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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.
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 quarter 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. In the first quarter of 2005, these amounts were partially
offset by higher deferred state income taxes. The first quarter 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 is currently evaluating 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 cash flow from operations.
Accounts Payable and Accrued Liabilities
Included in "Accounts payable and accrued liabilities," on the
accompanying balance sheets, at March 31, 2005 and December 31, 2004 are
liabilities of approximately $4.9 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 March 31, 2005, we
recorded $0.6 million, net of taxes of $0.3 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
March 31, 2005 were as follows:
Gross Value Tax Effect Net of Tax
Value
----------------- --------------- --------------
Other comprehensive income at December 31, 2004... $ 710,828 $ (260,163) $ 450,665
Change in fair value of cash flow hedges........ (1,508,366) 551,264 (957,102)
Effect of cash flow hedges settled
during the period ............................. (78,646) 28,706 (49,940)
----------------- --------------- --------------
Other comprehensive loss at March 31, 2005........ $ (876,184) $ 319,807 $ (556,377)
================= =============== ==============
Total comprehensive income was $24.7 million and $14.6 million for the
first quarter of 2005 and 2004, respectively.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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
for the period ended March 31, 2005 we recorded expense related to these
shares of $0.1 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 No. 123, "Accounting for Stock-Based Compensation," our net
income and earnings per share would have been adjusted to the following
pro forma amounts:
Three Months Ended March 31,
--------------------------------------------
2005 2004
----------------------- -------------------
Net Income: As Reported ............................................ $25,689,152 $14,587,854
Stock-based employee compensation expense
determined under fair value method for
all awards, net of tax ................................ (859,151) (1,022,306)
----------------------- -------------------
Pro Forma .............................................. $24,830,001 $13,565,548
Basic EPS: As Reported ............................................ $.91 $.53
Pro Forma .............................................. $.88 $.49
Diluted EPS: As Reported ............................................ $.89 $.52
Pro Forma .............................................. $.86 $.48
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 first quarter of 2005 and
2004, we recognized net losses of $0.1 million and $0.6 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 March 31, 2005, the Company had recorded $0.6
million, net of taxes of $0.3 million, of
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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 quarters
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 nine months when
the forecasted sale of hedged production occurs.
At March 31, 2005, we had in place price floors in effect through the
December 2005 contract month for natural gas, that cover a portion of our
domestic natural gas production for April 2005 to December 2005. The
natural gas price floors cover notional volumes of 4,050,000 MMBtu, with a
weighted average floor price of $5.69 per MMBtu. Our natural gas price
floors in place at March 31, 2005 are expected to cover approximately 35%
to 45% of our estimated domestic natural gas production from April 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 March
31, 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 $1.7 million in the first quarter of 2005 and $1.3 million in
the first quarter of 2004.
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 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 three months ended March 31 .................. 186,507 170,476
Liabilities incurred for new wells and facilities construction.......... 29,622 81,953
Reductions due to sold, or plugged and abandoned wells ................. (166,452) (26,000)
Increase (decrease) due to currency exchange rate fluctuations.......... (11,960) 4,077
----------------- ----------------
Asset Retirement Obligation as of March 31 ............................... $ 17,676,853 $ 10,367,979
----------------- ----------------
At March 31, 2005 and December 31, 2004, approximately $1.3 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 January 2003, the FASB issued Interpretation No. 46 (Revised
December 2003) ("FIN 46R"), Consolidation of Variable Interest Entities,
an Interpretation of Accounting Research Bulletin No. 51 consolidated
financial statements (the "Interpretation"). The Interpretation
significantly changes whether entities included in its scope are
consolidated by their sponsors, transferors, or investors. The
Interpretation introduces a new consolidation model - the variable
interest model; which determines control (and consolidation) based on
potential variability in gains and losses of the entity being evaluated
for consolidation. The Interpretation provides guidance for determining
whether an entity lacks sufficient equity or its equity holders lack
adequate decision-making ability. These variable interest entities
("VIEs") are covered by the Interpretation and are to be evaluated for
consolidation based on their variable interests. These provisions applied
immediately to variable interests in VIEs created after January 31, 2003,
and to variable interests in special purpose entities for periods ending
after December 15, 2003. The provisions apply for all other types of
variable interests in VIEs for periods ending after March 15, 2004. We
have no variable interests in VIEs, nor do we have variable interests in
special purpose entities. The adoption of this interpretation had no
impact on our financial position or results of operations.
In 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 protective 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. 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. A final consensus on this EITF is expected to be
reached at the June 2005 EITF meeting.
In September 2004, the Securities and Exchange Commission ("SEC")
issued Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the
SEC staff's views regarding SFAS No. 143 and its impact on both the
full-cost ceiling test and the calculation of depletion expense. In
accordance with SAB 106, beginning in the fourth quarter of 2004,
undiscounted abandonment cost for future wells, not recorded at the
present time but needed to develop the proved undeveloped reserves in
existence at the present time, was included in the unamortized cost of oil
and gas properties, net of related salvage value, for purposes of
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
computing DD&A. The effect of including undiscounted abandonment costs of
future wells to the undiscounted cost of oil and gas properties has
increased depletion expense in the current period and will increase
depletion expense in future periods, however, we currently do not believe
such increases have been or will be material.
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 press 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 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.
(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 antidilutive for periods ended March 31, 2005 and 2004,
and are discussed below.
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
The following is a reconciliation of the numerators and denominators
used in the calculation of Basic and Diluted EPS for the periods ended
March 31, 2005 and 2004:
Three Months Ended March 31,
------------------------------------------------------------------------------
2005 2004
---------------------------------------- ------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
-------------- ------------ ------------ ----------- ----------- ------------
Basic EPS:
Net Income and Share Amounts...... $ 25,689,152 28,160,949 $ 0.91 $14,587,854 27,552,827 $ 0.53
Dilutive Securities:
Restricted Stock ................. --- 11,242 --- ---
Stock Options .................... --- 641,115 --- 546,460
-------------- ------------ ----------- -----------
Diluted EPS:
Net Income and Assumed Share
Conversions .................... $ 25,689,152 28,813,306 $ 0.89 $14,587,854 28,099,287 $ 0.52
-------------- ------------ ----------- -----------
Options to purchase approximately 2.9 million shares at an average
exercise price of $18.97 were outstanding at March 31, 2005, while options
to purchase 3.2 million shares at an average exercise price of $16.58 were
outstanding at March 31, 2004. Approximately 0.7 million and 0.9 million
options to purchase shares were not included in the computation of Diluted
EPS for the periods ended March 31, 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 30,000 shares, which
were issued in the second half of 2004, were not included in the
computation of Diluted EPS for the period ended March 31, 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 March 31, 2005
and December 31, 2004, was as follows (in thousands):
March 31, 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
------------------ -------------------
Bank Borrowings
At March 31, 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 (5.75% at March
31, 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.
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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 $0.3 million and $0.4 million
for the first quarters of 2005 and 2004, respectively. The amount of
commitment fees included in interest expense, net was $0.1 million for
both the first quarters of 2005 and 2004.
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
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 for the first
quarter of 2005.
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 may redeem up to 33.33% of
these notes with the net proceeds of qualified offerings of our equity at
109.375% of the principal amount of these notes,
16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
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 in both
the first quarters of 2005 and 2004.
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 $1.8 million and $1.6 million, for the first quarters of 2005 and 2004,
respectively.
(5) Foreign Activities
As of March 31, 2005, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $251.1 million. Approximately $217.8
million has been included in the "Proved properties" portion of our oil
and gas properties, while $33.3 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 $218.9 million at March 31,
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. 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 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:
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Three Months Ended March 31,
------------------------------------------------------------------------------------
2005 2004
----------------------------------------- ----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ ------------ ------------- ------------ ------------ ------------
Oil and gas sales ............................ $ 76,775,769 $ 18,745,564 $ 95,521,333 $ 54,666,162 $ 11,287,608 $ 65,953,770
Costs and Expenses:
Depreciation, depletion and amortization . 17,673,698 6,531,680 24,205,378 14,517,949 3,777,735 18,295,684
Accretion of asset retirement obligation . 153,857 32,650 186,507 130,548 39,928 170,476
Lease operating costs .................... 8,244,217 2,804,565 11,048,782 6,919,281 2,706,699 9,625,980
Severance and other taxes................. 8,030,686 1,172,395 9,203,081 5,418,881 827,678 6,246,559
------------ ------------ ------------- ------------ ------------ ------------
Income from oil and gas operations........ $ 42,673,311 $ 8,204,274 $ 50,877,585 $ 27,679,503 $ 3,935,568 $ 31,615,071
Price-risk management and other, net ..... 99,351 (598,040)
General and administrative, net........... 4,874,308 4,029,674
Interest expense, net .................... 6,344,009 6,901,175
-------------- ------------
Income Before Income Taxes ................... $ 39,758,619 $ 20,086,182
============== ============
Total Assets $800,313,774 $218,951,614 $1,019,265,388 $691,175,130 $195,194,148 $886,369,278
============ ============ ============== ============ ============ ============
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 27 of
this report.
Overview
For the first three months of 2005, we had revenues of $95.6 million
and production of 15.5 Bcfe, which is a 46% increase in revenues and a 9%
increase in production over the same period in 2004. Our revenues for the
first quarter of 2005 were bolstered by oil and gas prices remaining
strong and production increasing by 9% compared to the first quarter of
2004. First quarter 2005 revenues and production were down from fourth
quarter 2004 by 3% and 2%, respectively, due to the temporary shut down of
a third party gas pipeline in the Lake Washington area. We continued to
focus our efforts and capital throughout the period on infrastructure
improvements, increased production, and the development of long-lived
reserves primarily in southern Louisiana, and additionally in our AWP
Olmos area in South Texas.
Our net production in Lake Washington for the first quarter of 2005
increased 35% as compared to production in the same period in 2004,
averaging approximately 12,600 net barrels of oil equivalent per day in
the first quarter of 2005, compared to approximately 9,300 net barrels of
oil equivalent per day for the same period in 2004. New Zealand accounted
for 4.5 Bcfe of our production in the first quarter of 2005, an 18%
increase from production in the same period in 2004. Natural gas
production in New Zealand increased due to higher production levels in our
Rimu/Kauri area.
Our production costs increased in the first quarter of 2005 as compared
to the first quarter of 2004 predominantly because of increased production
in Lake Washington, higher severance taxes due to increased revenues, and
currency exchange rates in New Zealand. Our general and administrative
expenses increased in the first quarter of 2005 over the same 2004 period
primarily due to an increase in workforce along with increased salaries
and benefits, and an increase in costs related to our on going compliance
initiatives with the Sarbanes-Oxley Act.
Our debt to PV-10 ratio decreased to 13% at March 31, 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 41% at
March 31, 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.
Results of Operations - Three Months Ended March 31, 2005 and 2004
Revenues. Our revenues in the first quarter of 2005 increased by 46%
compared to revenues in the same period in 2004, due primarily to an
increase in commodity prices and production from our Lake Washington and
Rimu/Kauri areas. Revenues from our oil and gas sales comprised
substantially all of net revenues for the first quarter of 2005 and 2004.
In the first quarter of 2005, oil production made up 51% of total
production, natural gas made up 40%, and NGL represented 9%. In the first
quarter of 2004, oil production made up 47% of total production, natural
gas made up 41%, and NGL represented 12%. The percentage of our total
production from oil increased as Lake Washington production, which is
almost entirely oil, increased over first quarter of 2004 levels. Although
production in Lake Washington was reduced by 0.25 Bcfe due to a
third-party pipeline interruption during the first quarter of 2005,
continued development in this area has increased production significantly.
19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
Our first quarter 2005 weighted average prices increased 33% to $6.16
per Mcfe from $4.62 in the first quarter of 2004, with oil prices
appreciating 40% to $47.66 from $34.14 during the first quarter of 2004,
natural gas prices increasing 17% to $4.25 from $3.64, and NGL prices rose
20% to $26.79 from $22.30.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes for the
periods ended March 31, 2005 and 2004.
Three Months Ended March 31,
----------------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
---- ----------------------------------- ---------------------------------------
2005 2004 2005 2004
---- ---- ---- ----
AWP Olmos ..................... $ 11.3 $ 11.7 1.9 2.6
Brookeland .................... 4.0 4.6 0.7 1.0
Lake Washington ............... 51.4 28.9 6.8 5.1
Masters Creek ................. 4.7 5.1 0.7 1.0
Other ......................... 5.4 4.4 0.9 0.7
---------------- ----------------- ---------------- ----------------------
Total Domestic ........ $ 76.8 $ 54.7 11.0 10.4
---------------- ----------------- ---------------- ----------------------
Rimu/Kauri .................... 12.5 4.3 2.4 1.1
TAWN .......................... 6.2 7.0 2.1 2.8
---------------- ----------------- ---------------- ----------------------
Total New Zealand ..... $ 18.7 $ 11.3 4.5 3.9
---------------- ----------------- ---------------- ----------------------
Total ......................... $ 95.5 $ 66.0 15.5 14.3
================ ================= ================ ======================
The following table provides additional information regarding our
quarterly oil and gas sales:
Sales Volume Average Sales Price
------------ -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
---------- --------- --------- ----------- ----------- ---------- ----------
2005
----
Three Months Ended March 31:
Domestic .................. 1,184 143 3.0 11.0 $47.20 $31.79 $5.41
New Zealand ............... 137 80 3.3 4.5 $51.68 $17.80 $3.17
---------- --------- --------- -----------
Total ............... 1,321 223 6.3 15.5 $47.66 $26.79 $4.25
========== ========= ========= ===========
2004
----
Three Months Ended March 31:
Domestic .................. 1,018 211 3.1 10.4 $33.95 $24.31 $4.90
New Zealand ............... 106 67 2.8 3.9 $36.03 $16.00 $2.27
---------- --------- --------- -----------
Total ............... 1,124 278 5.9 14.3 $34.14 $22.30 $3.64
========== ========= ========= ===========
In the first quarter of 2005, our $29.6 million increase in oil, NGL,
and natural gas sales resulted from:
oPrice variances that had a $22.7 million favorable impact on sales,
of which $17.9 million was attributable to the 40% increase in
average oil prices received, $3.8 million was attributable to the
17% increase in average gas prices received, and $1.0 million was
attributable to the 20% increase in average NGL prices received;
and
oVolume variances that had a $6.9 million favorable impact on sales,
with $6.7 million of increases coming from the 196,000 Bbl
increase in oil sales volumes, $1.4 million of increases due to
the 0.4 Bcf
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
increase in gas sales volumes, partially offset by a $1.2 million
decrease attributable to the 55,000 Bbl decrease in NGL sales
volumes.
Costs and Expenses. Our expenses in the first quarter of 2005 increased
$10.6 million, or 23%, compared to expenses in the same period of 2004.
The increase was due to a $5.9 million increase in DD&A, a $3.0 million
increase in severance and other taxes, and a $1.4 million increase in
lease operating costs, all of which are primarily due to increased
production volumes and high oil and gas prices in the 2005 first quarter
period.
Our first quarter 2005 general and administrative expenses, net,
increased $0.8 million, or 21%, from the level of such expenses in the
same 2004 period. This increase was primarily due to an increase in
workforce along with increased salaries and benefits and continued costs
of compliance initiatives related to the Sarbanes-Oxley Act. For the first
quarters of 2005 and 2004, our capitalized general and administrative
costs totaled $4.1 million and $2.9 million, respectively. Our net general
and administrative expenses per Mcfe produced increased to $0.31 per Mcfe
in the first quarter of 2005 from $0.28 per Mcfe in the same 2004 period.
The portion of supervision fees recorded as a reduction to general and
administrative expenses was $1.7 million for the first quarter of 2005 and
$1.3 million for the 2004 period.
DD&A increased $5.9 million, or 32%, in the first quarter of 2005 from
the level of those expenses in the same period of 2004. Domestically, DD&A
increased $3.2 million in the first quarter of 2005 due to increases in
the depletable oil and gas property base and higher production in the 2005
period. In New Zealand, DD&A increased by $2.7 million in the first
quarter 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 $1.56
and $1.28 in the first quarters of 2005 and 2004, respectively.
We recorded $0.2 million of accretions to our asset retirement
obligation in both the first quarters of 2005 and 2004.
Our lease operating costs per Mcfe produced were $0.71 in the first
quarter of 2005 and $0.67 in the first quarter of 2004. Our lease
operating costs in the first quarter of 2005 increased $1.4 million, or
15%, over the level of such expenses in the same 2004 period. Almost all
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 quarter of
2005 by $0.1 million due to higher production.
In the first quarter of 2005, severance and other taxes increased $3.0
million, or 47%, over levels in the first quarter 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 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 9.6% and 9.5% in the first quarters 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 $3.0 million
in the first quarter of 2005. 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 first 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 first quarter of 2004.
Interest expense on our bank credit facility, including commitment fees
and amortization of debt issuance costs, totaled $0.3 million in the first
quarter of 2005 and $0.4 million in the same period in 2004. Our total
interest cost in the first quarter of 2005 was $8.1 million, of which $1.8
million was capitalized. Our total interest cost in the first quarter of
2004 was $8.5 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 first quarter of 2005 was primarily
attributable to the replacement of our 10-1/4% senior subordinated notes
with our 7-5/8% senior notes.
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
Our overall effective tax rate was 35.4% in the first quarter of 2005
and 27.4% in the same 2004 period. The effective income tax rate for both
the first 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. In the first quarter of 2005, this reduction was offset
somewhat by an increase in the domestic deferred state tax rate due to an
increase in the Louisiana apportionment factor. The first quarter of 2004
also included a reduction in tax expense primarily attributable to an
adjustment of the tax basis of the TAWN properties acquired in 2002.
Net Income. For the first quarter of 2005, our net income of $25.7
million was 76% higher, and Basic EPS of $0.91 was 72% higher, than our
first quarter of 2004 net income of $14.6 million and Basic EPS of $0.53.
Our Diluted EPS in the first quarter of 2005 of $0.89 was 72% higher than
our first quarter 2004 Diluted EPS of $0.52. These higher amounts are due
to our increased oil and gas revenues, which in turn were higher due to
continued strong commodity prices and increased production during the
first quarter 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 10-K.
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 significantly higher
when compared to longer-term historical prices. Factors such as 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 quarter of 2005, we relied upon our net cash provided
by operating activities of $64.7 million to fund capital expenditures of
$44.5 million and to pay down our bank borrowings by $7.5 million. During
the first quarter of 2004, we relied upon our net cash provided by
operating activities of $39.6 million and proceeds from bank borrowings of
$16.6 million to fund capital expenditures of $45.1 million.
Net Cash Provided by Operating Activities. For the first quarter of
2005, our net cash provided by operating activities was $64.7 million,
representing a 63% increase as compared to $39.6 million generated during
the same 2004 period. The $25.1 million increase in the first quarter of
2005 was primarily due to an increase of $29.6 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 $40.4 million and $39.0 million at March 31, 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
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
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.
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 both March 31, 2005 and December 31, 2004, we had an
allowance for doubtful accounts of $0.5 million. The allowance for
doubtful accounts has been deducted from the total "Accounts receivable"
balances on the accompanying consolidated balance sheets.
Sarbanes-Oxley Act Compliance Costs. For 2004 and the first quarter of
2005, we have incurred substantial costs to comply with the Sarbanes-Oxley
Act of 2002. These expenditures have reduced our net cash provided by
operating activities in each of these periods. We expect the costs of
Sarbanes-Oxley initiatives to decrease from 2004 levels during 2005 and in
future years.
Bank Credit Facility. We had no borrowings under our bank credit
facility at March 31, 2005, and $7.5 million in outstanding borrowings at
December 31, 2004. Our bank credit facility at March 31, 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 deficit of $3.6 million at March 31,
2005. The improvement primarily resulted from an increase in our cash
balances due to increased cash flows from operating activities, a decrease
in our accounts payable and accrued liabilities due to timing of payments
in the first quarter of 2005, partially offset by an increase in accrued
capital costs due to an increase in our drilling and facility construction
activities from year-end 2004 levels.
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. 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.
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
Capital Expenditures. In the first quarter of 2005, we relied upon our
net cash provided by operating activities of $64.7 million to fund capital
expenditures of $44.5 million. Our total capital expenditures of
approximately $44.5 million in the first quarter of 2005 included:
Domestic expenditures of $33.8 million as follows:
o $27.7 million for drilling and developmental activity costs,
predominantly in our Lake Washington and AWP areas;
o $5.3 million of domestic prospect costs, principally prospect
leasehold, activity, and geological costs of unproved prospects;
o $0.7 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 $10.7 million as follows:
o $ 8.7 million for drilling and developmental activity costs;
o $1.7 million on prospect costs and geological costs of unproved
properties;
o $0.2 million on gas processing plants;
o less than $0.1 million for computer equipment, software,
furniture, and fixtures.
We successfully completed 13 of 19 wells in the first quarter of 2005,
for a success rate of 68%. Domestically, we completed 11 of 14 development
wells for a success rate of 79% and completed two of three exploration
wells. A total of 15 wells were drilled in the Lake Washington area, of
which 11 were completed, and two wells were drilled in the AWP Olmos area,
both were completed. In New Zealand, we drilled a development well, the
Kauri E-8, and one exploratory well, the Karaka A-1; both were
unsuccessful.
Our current 2005 capital expenditure budget is $220 million to $240
million, net of $5 million to $15 million of dispositions and excluding
any acquisitions. Approximately 80% of the budget is targeted for domestic
activities, primarily in southern Louisiana, with the remaining 20%
planned for activities in New Zealand. Approximately $15 million to $20
million of the 2005 budget will be focused on activity in the newly
acquired properties in Bay de Chene and Cote Blanche Island fields. The $5
million to $15 million of dispositions planned for later in 2005 relate to
non-core properties. We expect that our 2005 capital expenditures will
begin at the low end of the range, and depending on commodity prices and
operational performance, they may increase to the high end of the range
during the course of the year. We anticipate 2005 capital expenditures to
be less than our cash flows provided from operating activities during
2005. For 2005, we are targeting total production and proved reserves to
increase 7% to 12% over the 2004 levels.
For the last nine months of 2005, we expect to make capital
expenditures of approximately $175 to $195 million. Our current estimated
total capital expenditures for 2005 are 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 nine 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 such activity.
24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
During the last nine months of 2005, we anticipate drilling or
participating in the drilling of up to an additional 17 to 21 wells in the
Lake Washington area, an additional 10 to 13 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 9 to 11 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.
New Accounting Pronouncements
In January 2003, the FASB issued Interpretation No. 46 (Revised
December 2003) ("FIN 46R"), Consolidation of Variable Interest Entities,
an Interpretation of Accounting Research Bulletin No. 51 consolidated
financial statements (the "Interpretation"). The Interpretation
significantly changes whether entities included in its scope are
consolidated by their sponsors, transferors, or investors. The
Interpretation introduces a new consolidation model - the variable
interest model; which determines control (and consolidation) based on
potential variability in gains and losses of the entity being evaluated
for consolidation. The Interpretation provides guidance for determining
whether an entity lacks sufficient equity or its equity holders lack
adequate decision-making ability. These variable interest entities
("VIEs") are covered by the Interpretation and are to be evaluated for
consolidation based on their variable interests. These provisions applied
immediately to variable interests in VIEs created after January 31, 2003,
and to variable interests in special purpose entities for periods ending
after December 15, 2003. The provisions apply for all other types of
variable interests in VIEs for periods ending after March 15, 2004. We
have no variable interests in VIEs, nor do we have variable interests in
special purpose entities. The adoption of this interpretation had no
impact on our financial position or results of operations.
In 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 protective 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. 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. A final consensus on this EITF is expected to be
reached at the June 2005 EITF meeting.
In September 2004, the Securities and Exchange Commission ("SEC")
issued Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the
SEC staff's views regarding SFAS No. 143 and its impact on both the
full-cost ceiling test and the calculation of depletion expense. In
accordance with SAB 106, beginning in the fourth quarter of 2004,
undiscounted abandonment cost for future wells, not recorded at the
present time but needed to develop the proved undeveloped reserves in
existence at the present time, was included in the unamortized cost of oil
and gas properties, net of related salvage value, for purposes of
computing DD&A. The effect of including undiscounted abandonment costs of
future wells to the
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued
SWIFT ENERGY COMPANY
undiscounted cost of oil and gas properties has increased depletion
expense in the current period and will increase depletion expense in
future periods, however, we currently do not believe such increases have
been or will be material.
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 press 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 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."
26
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
volatility in oil and gas prices; fluctuations of the prices received or
demand for our oil and natural gas; the uncertainty of drilling results
and reserve estimates; operating hazards; requirements for capital;
general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and government
regulations; as well as the risks and uncertainties discussed herein, and
set forth from time to time in our other public reports, filings and
public statements. Also, because of the volatility in oil and gas prices
and other factors, interim results are not necessarily indicative of those
for a full year.
27
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Risk
Our major market risk exposure is the 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 March 31, 2005, we had in place price floors in
effect through the December 2005 contract month for natural
gas, which cover 35% to 45% of our domestic natural gas
production for April 2005 to December 2005. The natural gas
price floors cover notional volumes of 4,050,000 MMBtu, and
expire at various dates from April 2005 to December 2005, with
a weighted average floor price of $5.69 per MMBtu.
oNew Zealand Gas Contracts - All of our current gas production in
New Zealand is sold under long-term, fixed-price contracts
denominated in New Zealand dollars. These contracts protect
against price volatility, and our revenue from these contracts
will vary only due to production fluctuations and foreign
exchange rates.
Customer Credit Risk
We are exposed to the risk of financial non-performance by customers.
Our ability to collect on sales to our customers is dependent on the
liquidity of our customer base. To manage customer credit risk, we monitor
credit ratings of customers and seek to minimize exposure to any one
customer where other customers are readily available. Due to availability
of other purchasers, we do not believe that the loss of any single oil or
gas customer would have a material adverse effect on our 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 Senior Notes due 2011 and Senior Subordinated Notes due 2012 have
fixed interest rates, consequently we are not exposed to cash flow risk
from market interest rate changes on these notes. However, there is a risk
that market rates will decline and the required interest payments on our
Senior Notes and Senior Subordinated Notes may exceed those payments based
on the current market rate. At March 31, 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 58 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.
28
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our chief executive officer and chief financial officer have evaluated
our disclosure controls and procedures, as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934, as of the end of the
period covered by the report. Based on that evaluation, they have
concluded that such disclosure controls and procedures are effective in
alerting them on a timely basis to material information relating to Swift
Energy as required under the Exchange Act to be disclosed in this report.
Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting
during the first quarter of 2005 that has materially affected, or is
reasonably likely to materially affect, our internal control over
financial reporting.
29
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation incidental to the Company's business.
Item 2. 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 - None
Item 5. Other Information
Our Insider Trading Policy allows directors and officers covered under the
policy to establish stock trading plans under specified circumstances pursuant
to Rule 10b5-1 established by the SEC under the Securities Exchange Act of 1934
to provide a safe harbor under certain provisions of that act. Our Chairman of
the Board of Directors, A. Earl Swift, established a new Rule 10b5-1 sales plan
on March 29, 2005 that specifies for future trading periods, the number of
shares of common stock of Swift Energy to be sold, and prices and conditions
under which such shares may be sold. Mr. Swift discontinued a previous Rule
10b5-1, which was in effect from January 11, 2005 through March 29, 2005, under
which 12,000 shares were sold. Under the new trading plan, Mr. Swift may sell up
to an aggregate of 96,000 shares, which shares are principally acquirable under
options that expire in 2005, during the period beginning on April 15, 2005 and
ending on March 15, 2006. Under the trading plan, an independent broker will
execute the trades pursuant to specific selling instructions provided by Mr.
Swift at the time the plan was established. Other directors or officers may
establish Rule 10b5-1 trading plans in the future.
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.
30
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SWIFT ENERGY COMPANY
(Registrant)
Date: May 9, 2005 By: (original signed by)
-------------------- ----------------------------------
Alton D. Heckaman, Jr.
Executive Vice President
Chief Financial Officer
Date: May 9, 2005 By: (original signed by)
-------------------- ----------------------------------
David W. Wesson
Controller and Principal Accounting Officer
31
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 March
31, 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: May 9, 2005
/s/ Terry E. Swift
-------------------------------------------
Terry E. Swift
Chief Executive Officer
32
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 March
31, 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: May 9, 2005
/s/ Alton D. Heckaman, Jr.
-------------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President
Chief Financial Officer
33
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 March 31, 2005 (the "Report") of Swift Energy Company ("Swift") as filed
with the Securities and Exchange Commission on May 9, 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: May 9, 2005
/s/ Alton D. Heckaman, Jr.
-------------------------------------------
Alton D. Heckaman, Jr.
Executive Vice President
Chief Financial Officer
Dated: May 9, 2005
/s/ Terry E. Swift
-------------------------------------------
Terry E. Swift
Chief Executive Officer