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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 June 30, 2004
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 Act).
Yes X No
----------- ----------
Indicate the number of shares outstanding of each of the Registrant's classes
of common stock, as of the latest practicable date.
Common Stock 27,947,350 Shares
($.01 Par Value) (Outstanding at July 31, 2004)
(Class of Stock)
1
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2004
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets
- June 30, 2004 and December 31, 2003 3
Consolidated Statement of Income
- For the Three-month and Six-month periods ended
June 30, 2004 and 2003 4
Consolidated Statements of Stockholders' Equity
- For theSix-month period ended June 30, 2004 and
year ended December 31, 2003 5
Consolidated Statements of Cash Flows
- For the Six-month periods ended June 30, 2004 and 2003 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 18
Item 3. Quantitative and Qualitative Disclosures About Market Risk 30
Item 4. Controls and Procedures 32
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 33
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders None
Item 5. Other Information 33
Item 6. Exhibit and Reports on Form 8-K 33
SIGNATURES 35
2
CONSOLIDATED BALANCE SHEETS
SWIFT ENERGY COMPANY
June 30, 2004 December 31, 2003
------------------------- ---------------------------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents.................................. $ 86,879,237 $ 1,066,280
Accounts receivable - .....................................
Oil and gas sales........................................ 28,715,142 26,082,650
Joint interest owners.................................... 1,280,003 1,350,707
Other current assets....................................... 8,271,903 4,957,647
------------------------- ---------------------------
Total Current Assets................................... 125,146,285 33,457,284
------------------------- ---------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized........................ 1,371,533,116 1,305,763,355
Unproved properties not being amortized.................. 68,570,079 67,557,969
------------------------- ---------------------------
1,440,103,195 1,373,321,324
Furniture, fixtures, and other equipment................... 11,303,233 10,602,786
------------------------- ---------------------------
1,451,406,428 1,383,924,110
Less-Accumulated depreciation, depletion,
and amortization...................................... (605,343,453) (567,464,334)
------------------------- ---------------------------
846,062,975 816,459,776
------------------------- ---------------------------
Other Assets:
Deferred income taxes...................................... 2,805,904 1,905,909
Debt issuance costs........................................ 11,304,599 8,015,575
------------------------- ---------------------------
14,110,503 9,921,484
------------------------- ---------------------------
$ 985,319,763 $ 859,838,544
========================= ===========================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities................... $ 19,988,733 $ 26,247,477
Accrued capital costs...................................... 15,737,355 29,417,542
Accrued interest........................................... 7,448,478 8,748,656
Current portion of long-term debt.......................... 92,477,213 ---
Undistributed oil and gas revenues......................... 6,387,622 4,939,667
------------------------- ---------------------------
Total Current Liabilities.............................. 142,039,401 69,353,342
------------------------- ---------------------------
Long-Term Debt............................................... 350,000,000 340,254,783
Deferred Income Taxes........................................ 54,697,197 43,498,682
Asset Retirement Obligation.................................. 8,957,941 9,340,473
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,
28,392,853 and 28,011,109 shares issued, and 27,911,985
and 27,484,091 shares outstanding, respectively.......... 283,929 280,111
Additional paid-in capital................................. 338,816,308 334,865,204
Treasury stock held, at cost, 480,868 and
527,018 shares, respectively............................. (6,896,245) (7,558,093)
Retained earnings.......................................... 97,559,165 70,073,384
Other comprehensive loss, net of taxes..................... (137,933) (269,342)
------------------------- ---------------------------
429,625,224 397,391,264
------------------------- ---------------------------
$ 985,319,763 $ 859,838,544
========================= ===========================
See accompanying notes to consolidated financial statements.
3
CONSOLIDATED STATEMENTS OF INCOME
SWIFT ENERGY COMPANY
(Unaudited)
Three Months Ended Six Months Ended
------------------------------- ----------------------------------
06/30/04 06/30/03 06/30/04 06/30/03
--------------- -------------- ----------------- ---------------
Revenues:
Oil and gas sales.................................. $ 71,824,789 $ 50,909,250 $ 137,778,559 $ 105,759,549
Price-risk management and other, net............... (781,054) (191,721) (1,379,094) (1,542,027)
--------------- -------------- ----------------- ---------------
71,043,735 50,717,529 136,399,465 104,217,522
--------------- -------------- ----------------- ---------------
Costs and Expenses:
General and administrative, net.................... 4,175,559 3,337,995 8,205,233 6,894,543
Depreciation, depletion and amortization........... 19,509,056 15,676,549 37,804,740 30,588,312
Accretion of asset retirement obligation 160,259 201,903 330,735 417,286
............
Lease operating costs.............................. 10,435,813 9,171,687 20,061,793 16,484,791
Severance and other taxes.......................... 6,927,269 4,582,724 13,173,828 9,177,273
Interest expense, net.............................. 7,143,389 6,672,867 14,044,564 13,357,769
Debt retirement cost............................... 2,691,243 --- 2,691,243 ---
--------------- -------------- ----------------- ---------------
51,042,588 39,643,725 96,312,136 76,919,974
--------------- -------------- ----------------- ---------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle....... 20,001,147 11,073,804 40,087,329 27,297,548
Provision for Income Taxes........................... 7,103,220 3,852,378 12,601,548 9,591,185
-------------- -------------- ----------------- ---------------
Income Before Cumulative Effect of Change
in Accounting Principle............................ 12,897,927 7,221,426 27,485,781 17,706,363
Cumulative Effect of Change in Accounting
Principle (net of taxes)........................... --- --- --- 4,376,852
--------------- -------------- ----------------- ---------------
Net Income................................. $ 12,897,927 $ 7,221,426 $ 27,485,781 $ 13,329,511
=============== ============== ================= ===============
Per share amounts
Basic:
Income Before Cumulative Effect of
Change in Accounting Principle ....... $ 0.46 $ 0.26 $ 0.99 $ 0.65
Cumulative Effect of Change in
Accounting Principle.................. --- --- --- (0.16)
--------------- -------------- ----------------- ---------------
Net Income............................... $ 0.46 $ 0.26 $ 0.99 $ 0.49
=============== ============== ================= ===============
Diluted:
Income Before Cumulative Effect of
Change in Accounting Principle ....... $ 0.46 $ 0.26 $ 0.98 $ 0.65
Cumulative Effect of Change in
Accounting Principle.................. --- --- --- (0.16)
--------------- -------------- ----------------- ---------------
Net Income......................... $ 0.46 $ 0.26 $ 0.98 $ 0.49
=============== ============== ================= ===============
Weighted Average Shares Outstanding.................. 27,742,444 27,311,170 27,647,636 27,277,156
=============== ============== ================= ===============
See accompanying notes to consolidated financial statements
4
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
SWIFT ENERGY COMPANY
(Unaudited)
Accumulated
Additional Other
Common Paid-in Treasury Retained Comprehensive
Stock (1) Capital Stock Earnings Loss Total
----------- ------------- ------------- -------------- -------------- -------------
Balance, December 31, 2002 $ 278,116 $ 333,543,471 $ (8,749,922)$ 40,179,572 $ (178,053) $ 365,073,184
Stock issued for benefit plans
(83,201 shares).................... 1 (408,178) 1,191,829 - - 783,652
Stock options exercised
(142,807 shares)................... 1,428 1,315,964 - - - 1,317,392
Employee stock purchase plan
(56,574 shares).................... 566 413,947 - - - 414,513
Comprehensive income:
Net income............................ - - - 29,893,812 - 29,893,812
Change in fair value of cash flow
hedges, net of income tax ......... - - - - (91,289) (91,289)
-------------
Total comprehensive income........... 29,802,523
----------- ------------- ------------- -------------- -------------- -------------
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
(331,999 shares)................... 3,321 3,289,406 - - - 3,292,727
Employee stock purchase plan
(49,745 shares).................... 497 495,400 - - - 495,897
Comprehensive income:
Net income............................ - - - 27,485,781 - 27,485,781
Change in fair value of cash flow
hedges, net of income tax.......... - - - - 131,409 131,409
-------------
Total comprehensive income............ 27,617,190
----------- ------------- ------------- -------------- -------------- -------------
Balance, June 30, 2004.................. $ 283,929 $ 338,816,308 $ (6,896,245)$ 97,559,165 $ (137,933) $ 429,625,224
=========== ============= ============= ============== ============== =============
(1)$.01 par value
See accompanying notes to consolidated financial statements.
5
CONSOLIDATED STATEMENTS OF CASH FLOWS
SWIFT ENERGY COMPANY
(Unaudited)
Period Ended June 30,
------------------------------------------------
2004 2003
--------------------- ---------------------
Cash Flows From Operating Activities:
Net income.................................................... $ 27,485,781 $ 13,329,511
Adjustments to reconcile net income to net cash provided
by operating activities -
Cumulative effect of change in accounting principle......... --- 4,376,852
Depreciation, depletion, and amortization................... 37,804,740 30,588,312
Accretion of asset retirement obligation.................... 330,735 417,286
Deferred income taxes....................................... 12,195,548 9,460,394
Debt retirement cost........................................ 899,226 ---
Other....................................................... 363,958 211,966
Change in assets and liabilities -
Increase in accounts receivable........................... (3,445,623) (5,375,296)
Increase in accounts payable and accrued liabilities...... 962,744 530,896
Decrease in accrued interest.............................. (1,300,178) (18,080)
--------------------- ---------------------
Net Cash Provided by Operating Activities........... 75,296,931 53,521,841
--------------------- ---------------------
Cash Flows From Investing Activities:
Additions to property and equipment........................... (85,926,359) (62,260,796)
Proceeds from the sale of property and equipment.............. 1,274,935 755,450
Net cash distributed as operator of
oil and gas properties...................................... (5,781,399) (1,956,188)
Net cash received (distributed) as operator of partnerships
and joint ventures.......................................... 224,482 (254,929)
Other......................................................... (17,607) (86,372)
--------------------- ---------------------
Net Cash Used in Investing Activities............... (90,225,948) (63,802,835)
--------------------- ---------------------
Cash Flows From Financing Activities:
Proceeds from long-term debt.................................. 150,000,000 ---
Payments of long-term debt.................................... (32,076,000) ---
Net proceeds from (payments of) bank borrowings............... (15,900,000) 7,500,000
Net proceeds from issuances of common stock................... 2,923,516 1,090,996
Payments of debt issuance costs............................... (4,205,542) ---
--------------------- ---------------------
Net Cash Provided by Financing Activities........... 100,741,974 8,590,996
--------------------- ---------------------
Net Increase (Decrease) in Cash and Cash Equivalents............ 85,812,957 (1,689,998)
Cash and Cash Equivalents at Beginning of Period................ 1,066,280 3,816,107
--------------------- ---------------------
Cash and Cash Equivalents at End of Period...................... $ 86,879,237 $ 2,126,109
===================== =====================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
Capitalized................................................... $ 14,774,142 $ 12,831,097
Cash paid during period for income taxes........................ $ 406,000 $ 130,791
See accompanying notes to consolidated financial statements.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SWIFT ENERGY COMPANY
(1) General Information
The consolidated financial statements included herein have been
prepared by Swift Energy Company and are unaudited, except for the
consolidated balance sheet at December 31, 2003 and consolidated statement
of stockholders' equity for the year ended December 31, 2003, which have
been prepared from the audited financial statements at that date. The
financial statements reflect necessary adjustments, all of which were of a
recurring nature, and are in the opinion of our management necessary for a
fair presentation. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with accounting
principles generally accepted in the United States have been omitted
pursuant to the rules and regulations of the Securities and Exchange
Commission. We believe that the disclosures presented are adequate to
allow the information presented not to be misleading. Certain
reclassifications have been made to prior period financial information to
conform to the current period presentation. The consolidated financial
statements should be read in conjunction with the audited financial
statements and the notes thereto included in the latest Form 10-K and
Annual Report.
(2) Summary Of Significant Accounting Policies
Oil and Gas Properties
We follow the "full-cost" method of accounting for oil and gas property
and equipment costs. Under this method of accounting, all productive and
nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized. Such costs may be
incurred both prior to and after the acquisition of a property and include
lease acquisitions, geological and geophysical services, drilling,
completion, and equipment. Internal costs incurred that are directly
identified with exploration, development, and acquisition activities
undertaken by us for our own account, and which are not related to
production, general corporate overhead, or similar activities, are also
capitalized. For the six months ended June 30, 2004 and 2003, such
internal costs capitalized totaled $6.2 million in each period. Interest
costs are also capitalized to unproved oil and gas properties. For the six
months ended June 30, 2004 and 2003, capitalized interest on our unproved
properties totaled $3.2 million and $3.5 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 capitalized asset retirement obligations, but
excluding costs of unproved properties--by an overall rate determined by
dividing the physical units of oil and gas produced during the period by
the total estimated units of proved oil and gas reserves at the beginning
of the period. This calculation is done on a country-by-country basis.
Furniture, fixtures, and other equipment are depreciated by the
straight-line method at rates based on the estimated useful lives of the
property. Repairs and maintenance are charged to expense as incurred.
Renewals and betterments are capitalized.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Geological and geophysical (G&G) costs incurred on developed properties
are recorded in Proved Property and therefore subject to amortization. In
exploration areas, G&G costs are capitalized in Unproved Property 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 and capitalized asset retirement obligations, net of related
salvage values and deferred income taxes, and excluding the asset
retirement obligation liability is limited to the sum of the estimated
future net revenues from proved properties, excluding cash outflows from
asset retirement obligations, using period-end prices, adjusted for the
effects of hedging, discounted at 10%, and the lower of cost or fair value
of unproved properties, adjusted for related income tax effects ("Ceiling
Test"). Our hedges at June 30, 2004 consisted of natural gas price floors,
crude oil price floors and crude oil collars with strike prices lower than
the period end price and thus did not affect prices used in this
calculation. This calculation is done on a country-by-country basis for
those countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production, timing,
and plan of development. The accuracy of any reserves estimate is a
function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify revision of
such estimate. Accordingly, reserves estimates are often different from
the quantities of oil and gas that are ultimately recovered.
Given the volatility of oil and gas prices, it is reasonably possible
that our estimate of discounted future net cash flows from proved oil and
gas reserves could change in the near term. If oil and gas prices decline
from our period-end prices used in the Ceiling Test, even if only for a
short period, it is possible that 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 onshore and inland waters oil
and natural gas reserves in Texas and Louisiana, as well as onshore oil
and natural gas reserves in New Zealand. Our investments in affiliated oil
and gas partnerships and other ventures are accounted for using the
proportionate consolidation method, whereby our proportionate share of
assets, liabilities, revenues, and expenses are included in the
appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing
the consolidated financial statements.
Accounts Receivable
Included in the "Accounts receivable" balance, which totaled $30.0
million and $27.4 million at June 30, 2004 and December 31, 2003,
respectively, on the accompanying consolidated balance sheets, is
approximately $2.3 million of receivables related to hydrocarbon volumes
produced during 2001 and 2002 that have been disputed since early 2003.
Accordingly, we did not record a receivable with regard to 2003 disputed
volumes.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
We continually assess the collectibility of trade and other
receivables, and based on our judgment, we establish a reserve when we
believe a receivable may not be collected. At both June 30, 2004 and
December 31, 2003, we had an allowance for doubtful accounts of $0.8
million. These allowances for doubtful accounts have been deducted from
the total "Accounts receivable" balances on the accompanying consolidated
balance sheets.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to
make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from estimates. Significant estimates include proved reserve
volumes, DD&A, and deferred income taxes.
Income Taxes
Income tax expense in the first six months of 2004 includes a reduction
from the U.S. statutory rate, primarily from the result of the currency
exchange rate effect on the New Zealand deferred tax, along with a
reduction in tax expense primarily attributable to an adjustment of the
tax basis of the TAWN properties acquired in 2002.
Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. Diluted earnings per share ("Diluted EPS") for all periods also
assume, as of the beginning of the period, exercise of stock options using
the treasury stock method. Certain of our stock options that would
potentially dilute Basic EPS in the future were antidilutive for the three
months and six months ended June 30, 2004 and 2003 were excluded. The
following is a reconciliation of the numerators and denominators used in
the calculation of Basic and Diluted EPS (before cumulative effect of
change in accounting principle) for the three-month and six-month periods
ended June 30, 2004 and 2003:
Three Months Ended June 30,
--------------------------------------------------------------------------------
2004 2003
-------------------------------------- ----------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------- ------------ ---------- -------------- ------------ ----------
Basic EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Share Amounts.... $12,897,927 27,742,444 $.46 $7,221,426 27,311,170 $.26
Stock Options.................... --- 555,300 --- 108,323
------------- ------------ -------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions.................... $12,897,927 28,297,744 $.46 $7,221,426 27,419,493 $.26
------------- ------------ -------------- ------------
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Six Months Ended June 30,
--------------------------------------------------------------------------------
2004 2003
-------------------------------------- ----------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
-------------- ----------- ---------- -------------- ------------ ----------
Basic EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Share Amounts $27,485,781 27,647,636 $.99 $17,706,363 27,277,156 $.65
Stock Options.................... --- 504,626 --- 85,976
------------- ------------ -------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions.................... $27,485,781 28,152,262 $.98 $17,706,363 27,363,132 $.65
------------- ------------ -------------- ------------
Options to purchase approximately 2.9 million shares of common stock,
at an average exercise price of $17.37 were outstanding at June 30, 2004,
and options to purchase approximately 2.9 million shares of common stock,
at an average price of $16.66 were outstanding at June 30, 2003.
Approximately 0.9 million and 1.6 million options to purchase shares were
not included in the computation of Diluted EPS for the three-month periods
ended June 30, 2004 and 2003, respectively, and approximately 1.0 million
and 1.7 million options to purchase shares were not included in the
computation of Diluted EPS for the six-month periods ended June 30, 2004
and 2003, respectively, because the options were antidilutive, given that
the option price was greater than the average closing market price of the
common shares during those periods.
Other Comprehensive Loss
In addition to net income, comprehensive income or loss includes all
changes to equity during a period, except those resulting from investments
and distributions to the owners of the Company. At June 30, 2004, we
recorded $137,933, net of taxes of $77,588, of derivative losses in "Other
comprehensive loss" on the accompanying balance sheet. The components of
accumulated other comprehensive loss and related tax effects for the
six-month period ended June 30, 2004 were as follows:
Gross Value Tax Effect Net of Tax Value
---------------- --------------- ----------------
Balance at December 31, 2003................ $ 420,847 $ 151,505 $ 269,342
Change in fair value of cash flow hedges ... 869,010 312,844 556,166
Effect of cash flow hedges settled
during the period........................ (1,074,336) (386,761) (687,575)
---------------- --------------- ----------------
Balance at June 30, 2004.................... $ 215,521 $ 77,588 $ 137,933
================ =============== ================
For the six-month periods ended June 30, 2004 and 2003, total
comprehensive income was $27.6 million and $13.1 million, respectively.
For the three-month periods ended June 30, 2004 and 2003, total
comprehensive income was $13.0 million and $7.1 million, respectively.
Stock Based Compensation
We account for three stock-based compensation plans under the
recognition and measurement principles of APB Opinion No. 25, "Accounting
for Stock Issued to Employees," and related interpretations. No
stock-based employee compensation cost is reflected in net income, as all
options granted under those plans had an exercise price equal to the
market value of the underlying common stock on the date of the grant; or
in the case of the employee stock purchase plan, 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,"
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
our net income and earnings per share would have been adjusted to the
following pro forma amounts:
Three Months Ended June 30,
-----------------------------------------------
2004 2003
---------------------- -------------------
Net Income: As Reported............................................ $12,897,927 $7,221,426
Stock-based employee compensation expense
determined under fair value method for
all awards, net of tax............................... (1,088,520) (1,041,376)
---------------------- -------------------
Pro Forma.............................................. $11,809,407 $6,180,050
Basic EPS: As Reported............................................ $.46 $.26
Pro Forma.............................................. $.43 $.23
Diluted EPS: As Reported............................................ $.46 $.26
Pro Forma.............................................. $.42 $.23
Six Months Ended June 30,
-----------------------------------------------
2004 2003
---------------------- -------------------
Net Income: As Reported............................................ $27,485,781 $13,329,511
Stock-based employee compensation expense
determined under fair value method for
all awards, net of tax............................... (2,110,826) (2,023,318)
---------------------- -------------------
Pro Forma.............................................. $25,374,955 $11,306,193
Basic EPS: As Reported............................................ $.99 $.49
Pro Forma.............................................. $.92 $.41
Diluted EPS: As Reported............................................ $.98 $.49
Pro Forma.............................................. $.90 $.41
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.
Price-Risk Management Activities
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) be recorded in the balance sheet as either an asset or
a liability measured at its fair value. Hedge accounting for qualifying
hedges 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. Hedges that do not meet the
criteria for hedge accounting are accounted for under mark to market
accounting.
We have a price-risk management policy to use derivative instruments to
protect against declines in oil and gas prices, mainly through the
purchase of price floors and collars. During the second quarters of 2004
and 2003, we recognized net losses of $0.5 million and $0.4 million,
respectively, relating to our derivative activities. During the first six
months of 2004 and 2003, we recognized net losses of $1.1 million and $1.8
million, respectively, relating to our derivative activities. This
activity is recorded in "Price-risk management and other, net" on the
accompanying statements of income. At June 30, 2004, we had recorded $0.1
million, net of taxes of $0.1 million, of derivative losses in "Other
comprehensive loss" on the accompanying balance sheet. This amount
represents the change in fair value for the effective portion of our
hedging transactions that
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
were qualified as cash flow hedges. The ineffectiveness reported in
"Price-risk management and other, net" for the first six months of 2004
and 2003 was not material. We expect to reclassify all amounts currently
held in "Other comprehensive loss" into the statement of income within the
next six months when the forecasted sale of hedged production occurs.
As of June 30, 2004, we had in place natural gas price floors in effect
for the July 2004 contract month through the December 2004 contract month,
which cover a portion of our domestic natural gas production for July 2004
to December 2004. The natural gas price floors cover notional volumes of
2,160,000 Mmbtu with a weighted average floor price of $5.60 per Mmbtu.
Our natural gas hedges in place at June 30, 2004 are expected to cover
approximately 50% to 55% of our domestic natural gas production from July
2004 to September 2004, and approximately 10% to 15% of our domestic
natural gas production from October 2004 to December 2004. As of June 30,
2004, we also had crude oil price floors and a crude oil "collar"
financial transaction in effect for the July 2004 contract month through
the September 2004 contract month, which cover a portion of our domestic
crude oil production for July 2004 through September 2004. The crude oil
price floors cover notional volumes of 225,000 barrels with a weighted
average floor price of $31.40 per barrel. The crude oil collar covers
notional volumes for the month of September 2004 of 75,000 barrels for the
price floor and 30,000 barrels for the price ceiling, with a floor price
of $31 per barrel and a ceiling price of $42.50 per barrel. Our crude oil
floors and collar in place at June 30, 2004 are expected to cover
approximately 25% to 30% of our domestic crude oil production from July
2004 to September 2004.
When we entered into these transactions, they were designated as a
hedge of the variability in cash flows associated with the forecasted sale
of natural gas and crude oil 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 "Other comprehensive income (loss)." When the hedged
transactions are recorded upon the actual sale of oil and natural gas,
these gains or losses are reclassified from "Other comprehensive income
(loss)" and recorded in "Price-risk management and other, net" on the
consolidated statement of income. The fair value of our derivatives are
computed using the Black-Scholes option pricing model and are periodically
verified against quotes from brokers. The fair value of these instruments
at June 30, 2004, was $0.2 million and is recognized on the balance sheet
in "Other current assets."
Asset Retirement Obligation
In June 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." The statement requires
entities to record the fair value of a liability for legal obligations
associated with the retirement obligations of tangible long-lived assets
in the period in which it is incurred. When the liability is initially
recorded, the carrying amount of the related long-lived asset is
increased. 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. SFAS No. 143 was adopted by us effective
January 1, 2003. Upon adoption of SFAS No. 143 effective January 1, 2003,
we recorded an asset retirement obligation of $8.9 million, an addition to
oil and gas properties of $2.0 million and a non-cash charge of $4.4
million (net of $2.5 million of deferred taxes), which is recorded as a
Cumulative Effect of Change in Accounting Principle. The cumulative charge
to earnings took into consideration the impact of adopting SFAS No. 143 on
previous full-cost ceiling tests. SFAS No. 143 is silent with respect to
whether prior period ceiling tests should be reflected in the
implementation entry calculation; however, management believes that any
impairment on the properties should be reflected in the historical
periods. Had we not considered the impact of adopting SFAS No. 143 on
previous full-cost ceiling tests, the charge recognized would have been
reduced. Excluding the Cumulative Effect of Change in Accounting
Principle, the adoption of SFAS No. 143 reduced our net income for the
three months and six months ended June 30, 2003 by approximately $0.2
million and $0.3 million, respectively, or less than $0.01 per diluted
share in each of the 2003 periods. The following is a roll-forward of our
asset retirement obligation:
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
2004 2003
----------------- ----------------
Asset Retirement Obligation recorded as of January 1................. $ 10,137,473 $ 8,934,320
Accretion expense for the six months ended June 30................. 330,735 417,286
Liabilities incurred for new wells and facilities construction..... 191,491 387,073
Reductions due to sold, or plugged and abandoned wells............. (216,484) (219,068)
Increase due to currency exchange rate fluctuations................ (14,274) ---
----------------- ----------------
Asset Retirement Obligation as of June 30............................ $ 10,428,941 $ 9,519,611
----------------- ----------------
At June 30, 2004 and December 31, 2003, approximately $1.5 million and
$0.7 million, respectively, of our asset retirement obligation is
classified as a current liability in "Accounts payable and accrued
liabilities" on the accompanying consolidated balance sheets.
New Accounting Principles
In March 2004, the FASB issued an exposure draft that would amend SFAS
No. 123 "Accounting for Stock Based Compensation" and SFAS No. 95
"Statement of Cash Flows." This exposure draft was issued to improve
existing accounting rules and provide more complete, higher quality
information for investors on employee stock compensation matters. The
comment period for the exposure draft ended June 30, 2004. The exposure
draft covers a wide range of equity-based arrangements including stock
options. Under the FASB's proposal, share-based payments to employees,
including stock options, would be treated the same as other forms of
compensation by recognizing the related cost in the income statement. The
expense of the award would generally be measured at fair value at the
grant date. Current accounting guidance allows that the expense relating
to employee stock options to only be disclosed in the footnotes of the
financial statements. We are evaluating the effects that will result from
future adoption of this proposed statement.
In January 2003, the FASB issued Interpretation No. 46 (Revised
December 2003), 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 June 2001, the FASB issued SFAS No. 141, "Business Combinations,"
and SFAS No. 142, "Goodwill and Intangible Assets." We adopted these
statements on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires that all business combinations initiated after June 30, 2001, be
accounted for using the purchase method and that intangible assets be
disaggregated and reported separately from goodwill. SFAS No. 142
establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and other indefinite lived
intangible assets are not amortized but reviewed annually for impairment.
An issue, EITF Issue 04-2, had arisen for companies engaged in oil and
gas exploration and production regarding the application of SFAS No. 141
and SFAS No. 142 as they relate to mineral rights held under lease or
other contractual arrangements, and as to whether costs associated with
these rights should be classified as intangible assets on the balance
sheet, apart from other capitalized oil and gas property costs, and to
provide
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
specific footnote disclosure. In March 2004, the Emerging Issues Task
Force of the FASB reached a consensus that mineral rights are tangible
assets. In April 2004, the FASB ratified the EITF's consensus by issuing
FASB Staff Position (FSP) 141-1 and 142-1, which amend SFAS No. 141 and
SFAS No. 142 to address the inconsistency between the EITF consensus on
EITF Issue No. 04-02 and SFAS No. 141 and SFAS No. 142. The FSP is
effective for reporting periods beginning after April 29, 2004 and defines
mineral rights as tangible assets. The comment period on the FSP extends
until August 17, 2004. These staff positions will have no impact on our
consolidated financial statements.
(3) Long-Term Debt
Our long-term debt, including the current portion, as of June 30, 2004
and December 31, 2003, was as follows:
June 30, December 31,
2004 2003
------------------ -------------------
Bank Borrowings........................... $ --- $ 15,900,000
Senior Subordinated Notes due 2009... 92,477,213 124,354,783
Senior Notes due 2011..................... 150,000,000 ---
Senior Subordinated Notes due 2012... 200,000,000 200,000,000
------------------ -------------------
Long-Term Debt................... $ 442,477,213 $ 340,254,783
------------------ -------------------
The unamortized discount on the Senior Subordinated Notes due 2009 was
$0.4 million at June 30, 2004 and $0.6 million at December 31, 2003,
respectively. The balance of our Senior Subordinated Notes due 2009 is
classified as a current liability in "Current portion of long-term debt"
on the accompanying consolidated balance sheets as these were redeemed on
August 1, 2004.
Bank Borrowings
At June 30, 2004, 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, 2003,
we had $15.9 million in outstanding borrowings under our credit facility.
The interest rate is either (a) the lead bank's prime rate (4.25% at June
30, 2004) 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 increased, renewed and
extended 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 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 working capital and EBITDAX
ratios), and limitations on incurring other debt or repurchasing our
Senior Subordinated Notes due 2011 or Senior 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 active New Zealand subsidiaries
as collateral for this credit facility. 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, 2004. We requested that the
commitment amount with our bank group be reduced to $150.0 million
effective May 9, 2003. Under the terms of the credit facility, we can
increase this commitment amount back to the total amount of the borrowing
base at our discretion, subject to the terms of the credit agreement. The
next borrowing base review is scheduled for November 2004.
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
Senior Subordinated Notes Due 2009
These notes consisted of $125.0 million of 10 1/4% Senior Subordinated
Notes due August 2009, which were issued at 99.236% of the principal
amount on August 4, 1999, and were to mature on August 1, 2009. These
notes were unsecured senior subordinated obligations. Interest on these
notes had been payable semi-annually on February 1 and August 1. In June
2004, we repurchased $32.1 million of these notes pursuant to a tender
offer. In the second quarter of 2004, we recorded a charge of $2.7 million
related to the repurchase of these notes, which is recorded in "Debt
retirement costs" on the consolidated statement of income. The costs were
comprised of approximately $1.8 million of premiums paid to repurchase the
notes, $0.6 million to write-off unamortized debt issuance costs, $0.2
million to write-off unamortized debt discount and approximately $0.1
million of other costs. In July 2004, we repurchased approximately $0.5
million of these notes, and as of August 1, 2004, we redeemed the
remaining $92.5 million in outstanding notes. In the third quarter of
2004, we will record approximately $6.9 million of debt retirement costs
related to the redemption of these remaining notes. The balance of the
remaining notes at June 30, 2004, has been classified as "Current portion
of long-term debt" on the accompanying consolidated balance sheets.
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 the Senior Notes is payable semi-annually on January 15 and
July 15, and commences on January 15, 2005. On or after July 15, 2008, we
may redeem some or all of the Senior 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 Senior Notes with the net
proceeds of qualified offerings of our equity at a redemption price of
107.625% of the principal amount of the Senior 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 consolidated balance sheets and will be amortized to
interest expense over the life of the notes using the effective interest
method. Upon certain changes in control of Swift Energy, each holder of
Senior Notes will have the right to require us to repurchase all or any
part of the Senior Notes at a purchase price in cash equal to 101% of the
principal amount, plus accrued and unpaid interest to the date of
purchase. The terms of these Senior 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 due 2011.
Senior Subordinated Notes Due 2012
These notes consist of $200.0 million of 9 3/8% Senior Subordinated
Notes due 2012, which were issued on April 16, 2002 at 100% of the
principal amount, 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 borrowings under our
bank credit facility. Interest on these notes is payable semi-annually on
May 1 and November 1. 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 the notes, plus accrued and unpaid interest. Upon
certain changes in control of Swift Energy, each holder of these notes
will have the right to require us to repurchase the Senior Subordinated
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 Subordinated
Notes due 2012.
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
SWIFT ENERGY COMPANY
The aggregate maturities on our long-term debt are $92.9 million in
2004, $0 in 2005, 2006, 2007, 2008 and $350.0 million thereafter,
respectively.
(4) Foreign Activities
As of June 30, 2004, our gross capitalized oil and gas property costs
in New Zealand totaled approximately $222.6 million. Approximately $187.9
million has been included in the proved properties portion of our oil and
gas properties, while $34.7 million is included as unproved properties.
Our functional currency in New Zealand is the U.S. dollar.
(5) 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. The Company
evaluates performance based on profit or loss from oil and gas operations
before price-risk management and other, general and administrative
expenses, interest expense, net and debt retirement costs. The Company's
reportable segments are managed separately based on their geographic
locations. Financial information by operating segment is presented below:
Three Months Ended June 30,
----------------------------------------------------------------------------------
2004 2003
--------------------------------------- -----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ ------------ ------------- ------------- ------------- -------------
Oil and gas sales............................... $ 59,755,056 $ 12,069,733 $ 71,824,789 $ 39,977,699 $ 10,931,551 $ 50,909,250
Costs and Expenses:
Depreciation, depletion and amortization ... 14,903,238 4,605,818 19,509,056 11,065,738 4,610,811 15,676,549
Accretion of asset retirement obligation ... 119,699 40,560 160,259 148,082 53,821 201,903
Lease operating costs....................... 7,935,048 2,500,764 10,435,812 6,430,837 2,740,850 9,171,687
Severance and other taxes................... 6,062,585 864,685 6,927,270 3,668,249 914,475 4,582,724
------------ ------------ ------------ ------------- ------------- -------------
Income from oil and gas operations.............. $ 30,734,486 $ 4,057,906 $ 34,792,392 $ 18,664,793 $ 2,611,594 $ 21,276,387
Price-risk management and other, net ....... (781,054) (191,721)
General and administrative, net............. 4,175,559 3,337,995
Interest expense, net....................... 7,143,389 6,672,867
Debt retirement cost........................ 2,691,243 ---
------------- -------------
Income before income taxes and cumulative
effect of change in accounting principle ... $ 20,001,147 $ 11,073,804
============= =============
16
Six Months Ended June 30,
----------------------------------------------------------------------------------
2004 2003
--------------------------------------- -----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ ------------ ------------- ------------- ------------- -------------
Oil and gas sales............................... $114,421,220 $ 23,357,339 $ 137,778,559 $ 83,718,875 $ 22,040,674 $ 105,759,549
Costs and Expenses:
Depreciation, depletion and amortization ... 29,421,187 8,383,553 37,804,740 20,862,718 9,725,594 30,588,312
Accretion of asset retirement obligation ... 250,247 80,488 330,735 297,523 119,763 417,286
Lease operating costs....................... 14,854,330 5,207,463 20,061,793 11,947,290 4,537,501 16,484,791
Severance and other taxes................... 11,481,465 1,692,363 13,173,828 7,324,615 1,852,658 9,177,273
------------ ------------ ------------- ------------- ------------- -------------
Income from oil and gas operations.............. $ 58,413,991 $ 7,993,472 $ 66,407,463 $ 43,286,729 $ 5,805,158 $ 49,091,887
Price-risk management and other, net ....... (1,379,094) (1,542,027)
General and administrative, net............. 8,205,233 6,894,543
Interest expense, net....................... 14,044,564 13,357,769
Debt retirement cost........................ 2,691,243 ---
------------- -------------
Income before income taxes and cumulative
effect of change in accounting principle ... $ 40,087,329 $ 27,297,548
============= =============
Property, plant and equipment, net.............. $662,588,304 $183,474,671 $ 846,062,975 $ 591,373,155 $ 167,176,684 $ 758,549,839
============ ============ ============= ============= ============= =============
(6) Subsequent Event
In July 2004, we repurchased approximately $0.5 million of Senior
Subordinated Notes due 2009 pursuant to a tender offer we initiated in
June 2004. Effective August 1, 2004, we repurchased the remaining $92.5
million of these notes. In the third quarter of 2004, we will record
approximately $6.9 million of debt retirement costs related to the
repurchase of these remaining notes.
17
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 consolidated financial statements
and notes thereto included in this report. The following information
contains forward-looking statements. For a discussion of limitations
inherent in forward-looking statements, see "Forward-Looking Statements"
on page 29 of this report.
Overview
For the first six months of 2004, we had revenues of $136.4 million and
production of 28.5 Bcfe. Our revenues were bolstered by oil and gas prices
remaining strong during this period and our domestic production for the
first six months of 2004 increasing by 27% to 20.6 Bcfe compared to the
same period in 2003. We continued to focus our efforts and capital
throughout the second quarter on infrastructure improvements, increased
production and the development of longer life reserves in the Lake
Washington and AWP Olmos areas. In the first six months of 2004, we
produced approximately 11,800 net barrels of oil equivalent per day in
Lake Washington, compared to approximately 5,400 net barrels of oil
equivalent per day in the same period of 2003. During 2004, we also
allocated capital to development in our three other domestic core areas.
New Zealand accounted for 7.9 Bcfe of production in the first six months
of 2004, a 21% decrease from production in the same period in 2003.
Natural gas production in New Zealand declined primarily due to minimum
takes from the gas purchaser at TAWN. Increased use of hydroelectricity in
New Zealand has contributed to a short-term reduction in market demand for
natural gas, which is expected to continue throughout 2004. While our
fields at TAWN have been able to meet minimum contracted volumes to date,
it is anticipated that these fields will not be able to meet the
contracted volumes beginning in the second half of this year without
additional development, and we have plans to drill a development well in
the Tariki field in the second half of this year. There is no penalty if
the fields are unable to produce these minimum contracted volumes. New
Zealand natural gas and NGL contracts are denominated in the New Zealand
dollar, which have significantly strengthened during the last several
years against the U.S. Dollar.
Our production costs were up in the first six months of 2004
predominately due to increased production and facility repairs in Lake
Washington, increased severance taxes, currency exchange rates and
maintenance activities in New Zealand. Our general and administrative
expenses increased in the first six months of 2004 primarily due an
increase in franchise tax expense, increased costs related to our
corporate governance activities and compliance with the Sarbanes-Oxley
Act, as well as higher costs in our New Zealand operations due to currency
exchange rates. We are working to reduce our controllable production and
general and administrative costs on a per unit produced basis for the
remainder of 2004.
Our debt to PV-10 ratio increased to 26% at June 30, 2004 compared to
22% at December 31, 2003, due to the issuance in the second quarter of
2004 of our 7 5/8% Senior Notes due 2011 and partial repurchase of our
Senior Subordinated Notes due 2009. Our debt to capitalization ratio
increased to 51% at June 30, 2004 compared to 46% at year-end 2003, also
due to the issuance of Senior Notes in the second quarter of 2004 and
partial repurchase of our Senior Subordinated Notes due 2009. In June
2004, we repurchased $32.1 million of our 10 1/4% Senior Subordinated
Notes due 2009 through a tender offer. We recorded a charge of $2.7
million related to the tender offer, which is recorded in "Debt retirement
costs" on the consolidated statement of income. In July 2004, we
repurchased $0.5 million in Senior Subordinated Notes due 2009 at the
close of the tender offer. On August 1, 2004, we redeemed the remaining
$92.5 million of these notes in accordance with our redemption rights
under the indenture governing these notes. In the third quarter of 2004,
we will record approximately $6.9 million of debt retirement costs related
to the repurchase of these remaining notes. The redemption of our Senior
Subordinated Notes due 2009 will lower our effective interest rate going
forward.
We will continue to look for opportunities in 2004 to improve our
balance sheet and liquidity, but expect our capital expenditures to
continue to equal or modestly exceed our cash flow for the near term.
Our 2004 capital expenditure budget was increased by approximately 20%
in July 2004, and is now $160 to $175 million. The budget still assumes
increased drilling activity, when compared to 2003 levels, in all domestic
core areas except Lake Washington. In Lake Washington, the increased 2004
budget still assumes
18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
reduced drilling activity from 2003 levels and is estimated at 27 to 32
wells, accompanied by the on-going extensive three-dimensional seismic
survey, together with the analysis of the resulting data, to enhance our
drilling program in the area for years to come. We plan to drill 15 to 18
wells in AWP Olmos, with the objective of maintaining production levels in
that area. Additionally, we expect to have ongoing exploratory efforts in
our South Texas Garcia Ranch properties. In New Zealand, we plan to drill
10 to 14 wells. For the long-term, we continue to see a tightening natural
gas market and strengthening gas prices in New Zealand. Based on results
for the first half of 2004 and on current operating conditions, we
estimate that 2004 production levels will increase over 2003 levels in the
range of 11% to 15%, which is lower than the previously estimated range of
11% to 17%. We continue to believe that commodity prices will remain
strong for the remainder of 2004 and that we are positioned for reserve
growth of 5% to 8% for 2004 from 2003.
Results of Operations - Three Months Ended June 30, 2004 and 2003
Revenues. Our revenues in the second quarter of 2004 increased by 40%
compared to revenues in the same period in 2003, 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 second quarter of 2004 and 2003.
In the second quarter of 2004, oil production made up 48% of total
production, natural gas made up 41% and NGL contributed 11%. In the second
quarter of 2003, natural gas production made up 53% of total production,
oil production made up 37% and NGL contributed 10%.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our four
domestic core areas and two New Zealand core areas:
Three Months Ended June 30,
---------------------------
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
- ---- --------------------------------------- -----------------------------------------
2004 2003 2004 2003
---- ---- ---- ----
AWP Olmos.................... $ 12.5 $ 11.7 2.1 2.1
Brookeland................... 4.7 4.1 0.9 1.1
Lake Washington.............. 32.8 12.7 5.5 2.7
Masters Creek................ 5.4 6.3 1.0 1.5
Other........................ 4.4 5.2 0.7 1.1
------------------ ------------------- ----------------- -----------------------
Total Domestic....... $ 59.8 $ 40.0 10.2 8.5
------------------ ------------------- ----------------- -----------------------
Rimu/Kauri................... 5.2 1.7 1.2 0.5
TAWN......................... 6.8 9.2 2.9 4.3
------------------ ------------------- ----------------- -----------------------
Total New Zealand.... $ 12.0 $ 10.9 4.1 4.8
------------------ ------------------- ----------------- -----------------------
Total........ $ 71.8 $ 50.9 14.3 13.3
================== =================== ================= =======================
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
The following table provides additional information regarding our oil,
NGL and gas sales:
Net Sales Volume Average Sales Price
---------------- -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
------------ ----------- ----------- ------------- ------------ ----------- -----------
2004
- ----
Three Months Ended June 30:
Domestic................. 1,021 179 3.0 10.2 $37.22 $19.42 $6.09
New Zealand.............. 122 90 2.8 4.1 $37.37 $17.69 $2.13
------------ ----------- ----------- -------------
Total.............. 1,142 269 5.8 14.3 $37.24 $18.84 $4.19
============ =========== =========== =============
2003
- ----
Three Months Ended June 30:
Domestic................. 676 140 3.6 8.5 $28.25 $17.07 $5.15
New Zealand.............. 146 71 3.5 4.8 $26.68 $13.36 $1.75
------------ ----------- ----------- -------------
Total.............. 822 211 7.1 13.3 $27.97 $15.81 $3.47
============ =========== =========== =============
Oil and gas sales in the second quarter of 2004 increased by 41%, or
$20.9 million, from the level of those revenues for the same period in
2003. The increase in production volumes during the second quarter of 2004
was primarily from our Lake Washington area domestically, and the
Rimu/Kauri area in New Zealand.
In the second quarter of 2004, our $20.9 million increase in oil, NGL,
and gas sales resulted from:
oPrice variances that had a $15.5 million favorable impact on sales, of
which $10.6 million was attributable to the 33% increase in average
oil prices received, $4.1 million was attributable to the 21% increase
in average gas prices received, and $0.8 million was attributable to
the 19% increase in average NGL prices received; and
oVolume variances that had a $5.4 million favorable impact on sales,
with $9.0 million of increases coming from the 321,000 Bbl increase in
oil sales volumes, $0.9 million of increases due to the 57,000 Bbl
increase in NGL sales volumes, partially offset by a $4.5 million
decrease attributable to the 1.3 Bcf decrease in gas sales volumes.
Costs and Expenses. Our total expenses in the second quarter of 2004
increased $11.4 million, or 29%, compared to expenses in the same period
in 2003. The majority of the increase was due to the $3.8 million increase
in depreciation, depletion and amortization, a $2.3 million increase in
severance taxes, and $1.3 million in lease operating costs, all of which
increased as our production volumes increased in the 2004 period, pricing
increases also contributed to an increase in severance taxes. We also
incurred $2.7 million of debt retirement costs in the second quarter of
2004 related to the repurchase of a portion of our Senior Subordinated
Notes due 2009 pursuant to a tender offer.
Our second quarter of 2004 general and administrative expenses, net,
increased $0.8 million, or 25%, from the level of such expenses in the
same 2003 period. This increase was due primarily to an increase in
franchise tax expense, increased costs related to our corporate governance
activities and compliance with the Sarbanes-Oxley Act, as well as higher
costs in our New Zealand operations due to the increased currency exchange
rate of the New Zealand dollar as compared to the U.S. dollar. Our general
and administrative expenses per Mcfe produced were $0.29 per Mcfe in the
second quarter of 2004 and $0.25 in the 2003 period. The portion of
supervision fees recorded as a reduction of general and administrative
expenses was $1.2 million for the second quarter of 2004 and $0.7 million
for the same period in 2003.
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Depreciation, depletion, and amortization of our oil and gas
properties, or DD&A, increased $3.8 million, or 24%, in the second quarter
of 2004 from 2003 levels. Domestically, DD&A increased $3.8 million in the
2004 period, mainly due to higher production in the period and the DD&A
rate per Mcfe of production increased to $1.46 from $1.30 in the
comparable 2003 period mainly due to increases in future development costs
and oil and gas property additions, which increased our full cost pool
balance. In New Zealand, DD&A remained flat at $4.6 million in both the
2004 and 2003 period, the DD&A rate per Mcfe of production increased to
$1.14 from $0.96 in the 2003 period mainly due to increases in future
development costs and oil and gas property additions, which increased our
full cost pool balance. Our overall DD&A rate per Mcfe of production was
$1.37 in the second quarter of 2004 and $1.18 in the comparable 2003
period.
We recorded $0.2 million of accretion on our asset retirement
obligation in both the second quarter of 2004 and 2003.
Our lease operating costs per Mcfe produced were $0.73 in the second
quarter of 2004 and $0.69 in the same period of 2003. There were no
supervision fees recorded as a reduction to production costs for the
second quarter of 2004 and $0.5 million for the same 2003 period. Our
lease operating costs in the second quarter of 2004 increased $1.3
million, or 14%, over the level of such expenses in the comparable 2003
period. Approximately $1.5 million of the increase in lease operating
costs during the second quarter of 2004 was related to our domestic
operations, which increased due to higher production and facility repairs
in our Lake Washington area in that period. In New Zealand, production
costs decreased by $0.2 million in the second quarter of 2004 mainly due
to the decrease in production from our New Zealand properties in the 2004
period, offset by plant maintenance costs.
Severance and other taxes in the second quarter of 2004 increased $2.3
million, or 51%, over the level of such expenses in the comparable 2003
period. The increase is mainly due to higher commodity prices and
increased Lake Washington production in the second quarter of 2004.
Severance taxes on oil in Louisiana are 12% of oil sales, so as the
percentage of our oil production, which comes from Lake Washington
increases, the overall percentage of severance costs to sales will
increase. Severance and other taxes, as a percentage of oil and gas sales,
were approximately 10% and 9% in the second quarters of 2004 and 2003,
respectively.
Interest expense on our Senior Subordinated Notes due 2012, including
amortization of debt issuance costs, totaled $4.8 million in the second
quarter of both 2004 and 2003. Interest expense on our Senior Subordinated
Notes due 2009, including amortization of debt issuance costs, totaled
$3.3 million in the second quarter of both 2004 and 2003. Interest expense
on our bank credit facility, including commitment fees and amortization of
debt issuance costs, totaled $0.5 million in the second quarter of 2004
and $0.3 million in the same 2003 period. Interest expense on our Senior
Notes due 2011, issued in June 2004, was $0.2 million in the second
quarter of 2004. The total interest cost in the second quarter of 2004 was
$8.8 million, of which $1.6 million was capitalized. The total interest
cost in the second quarter of 2003 was $8.4 million, of which $1.7 million
was capitalized.
In the second quarter of 2004, we incurred $2.7 of debt retirement
costs related to the repurchase of a portion of our Senior Subordinated
Notes due 2009 pursuant to a tender offer. The costs were comprised of
approximately $1.8 million of premiums paid to repurchase the notes, $0.6
million to write-off unamortized debt issuance costs, $0.2 million to
write-off unamortized debt discount and approximately $0.1 million of
other costs.
Income tax expense in the second quarter of 2004 includes a reduction
from the U.S. statutory rate, primarily from the result of the currency
exchange rate effect on the New Zealand deferred tax.
Net Income. Our net income in the second quarter of 2004 of $12.9
million was 79% higher, and Basic EPS of $0.46 was 76% higher, than our
second quarter of 2003 net income of $7.2 million and Basic EPS of $0.26.
Our Diluted EPS in the second quarter of 2004 of $0.46 was 73% higher than
our 2003 Diluted EPS of $0.26. These amounts increased in the 2004 period
as oil and gas revenues increased due to higher commodity prices and
increased domestic production.
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Results of Operations - Six Months Ended June 30, 2004 and 2003
Revenues. Our revenues in the first six months of 2004 increased by 31%
compared to revenues in the same period in 2003, due primarily to
increases in oil prices and production from our Lake Washington and AWP
areas domestically and our Rimu/Kauri area in New Zealand. Substantially
all of our net revenues for the first six months of 2004 and 2003 were
from oil and gas sales. In the first six months of 2004, oil production
made up 48% of total production, natural gas made up 41% and NGL
contributed 11%. In the first half of 2003, natural gas production made up
56% of total production, oil production made up 35% and NGL contributed
9%.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our four
domestic core areas and two New Zealand core areas:
Six Months Ended June 30,
Area Oil and Gas Sales (In Millions) Net Oil and Gas Sales Volumes (Bcfe)
- ---- --------------------------------------- -----------------------------------------
2004 2003 2004 2003
---- ---- ---- ----
AWP Olmos..................... $ 24.3 $ 24.2 4.8 4.2
Brookeland.................... 9.3 9.4 1.9 2.0
Lake Washington............... 61.6 23.9 10.6 4.8
Masters Creek................. 10.6 14.7 2.0 3.1
Other......................... 8.6 11.6 1.3 2.1
------------------ ------------------- ----------------- -----------------------
Total Domestic........ $ 114.4 $ 83.8 20.6 16.2
------------------ ------------------- ----------------- -----------------------
Rimu/Kauri.................... 9.5 3.2 2.2 1.0
TAWN.......................... 13.8 18.8 5.7 8.9
------------------ ------------------- ----------------- -----------------------
Total New Zealand.... $ 23.4 $ 22.0 7.9 9.9
------------------ ------------------- ----------------- -----------------------
Total.......... $ 137.8 $ 105.8 28.5 26.1
================== =================== ================= =======================
The following table provides additional information regarding our oil,
NGL and gas sales:
Net Sales Volume Average Sales Price
---------------- -------------------
Oil NGL Gas Combined Oil NGL Gas
(MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf)
------------ ----------- ----------- ------------- ------------ ----------- -----------
2004
- ----
Six Months Ended June 30:
Domestic................. 2,039 390 6.1 20.6 $35.59 $22.06 $5.49
New Zealand.............. 228 157 5.6 7.9 $36.74 $16.97 $2.20
------------ ----------- ----------- -------------
Total.............. 2,267 547 11.7 28.5 $35.70 $20.60 $3.91
============ =========== =========== =============
2003
- ----
Six Months Ended June 30:
Domestic................. 1,253 240 7.3 16.2 $30.35 $21.83 $5.59
New Zealand.............. 258 145 7.5 9.9 $29.15 $13.12 $1.68
------------ ----------- ----------- -------------
Total.............. 1,511 385 14.8 26.1 $30.14 $18.55 $3.60
============ =========== =========== =============
Oil and gas sales in the first six months of 2004 increased by 30%, or
$32.0 million, from the level of those revenues for the same period in
2003. The increase in production volumes during the first six months of
2004 was primarily from our Lake Washington and AWP Olmos areas
domestically, and the Rimu/Kauri area in
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
New Zealand.
In the first six months of 2004, our $32.0 million increase in oil,
NGL, and gas sales resulted from:
oPrice variances that had a $17.4 million favorable impact on sales, of
which $12.6 million was attributable to the 18% increase in average
oil prices received, $3.7 million was attributable to the 9% increase
in average gas prices received and $1.1 million was attributable to
the 11% increase in average NGL prices received; and
oVolume variances that had a $14.6 million favorable impact on sales,
with $22.8 million of increases coming from the 755,000 Bbl increase
in oil sales volumes, $3.0 million of increases due to the 162,000 Bbl
increase in NGL sales volumes, partially offset by $11.2 million in
decreases attributable to the 3.1 Bcf decrease in gas sales volumes.
Costs and Expenses. Our total expenses in the first six months of 2004
increased $19.4 million, or 25%, compared to expenses in the same period
in 2003. The majority of the increase was due to a $7.2 million increase
in depreciation, depletion and amortization, a $4.0 million increase in
severance taxes, and a $3.6 million increase in lease operating costs, all
of which increased as our production volumes increased in the 2004 period.
Pricing increases also contributed to an increase in severance taxes. We
also incurred $2.7 million of debt retirement costs in the first half of
2004 related to the repurchase of a portion of our Senior Subordinated
Notes due 2009 pursuant to a tender offer.
As discussed in Note 1 to the Consolidated Financial Statements, we
adopted SFAS No. 143 on January 1, 2003. Our adoption of SFAS No. 143
resulted in a one-time net of taxes charge of $4.4 million, which is
recorded as a "Cumulative Effect of Change in Accounting Principle" in the
2003 consolidated statement of income.
Our first six months of 2004 general and administrative expenses, net,
increased $1.3 million, or 19%, from the level of such expenses in the
same 2003 period. This increase is due primarily to an increase in
franchise tax expense, increased costs related to our corporate governance
activities and compliance with the Sarbanes-Oxley Act, as well as higher
costs in our New Zealand operations due to the increased currency exchange
rate of the New Zealand dollar as compared to the U.S. dollar. Our general
and administrative expenses per Mcfe produced were $0.29 per Mcfe in the
first six months of 2004 and $0.26 in the same 2003 period. The portion of
supervision fees recorded as a reduction of general and administrative
expenses was $2.4 million for the first six months of 2004 and $1.4
million for the same 2003 period.
Depreciation, depletion, and amortization of our oil and gas
properties, or DD&A, increased $7.2 million, or 24%, in the first six
months of 2004 from 2003 levels for the same period. Domestically, DD&A
increased $8.6 million in the first six months of 2004, mainly due to
higher production in the period and the DD&A rate per Mcfe of production
increased to $1.43 from $1.29 in the comparable 2003 period mainly due to
increases in future development costs and oil and gas property additions,
which increased our full cost pool balance. In New Zealand, DD&A decreased
by $1.3 million in the 2004 period due to decreased production in the
period and the DD&A per Mcfe of production increased to $1.06 from $0.98
mainly due to increases in future development costs and oil and gas
property additions, which increased our full cost pool balance. Our
overall DD&A rate per Mcfe of production was $1.32 in the first six months
of 2004 and $1.17 in the comparable 2003 period.
We recorded $0.3 million of accretion on our asset retirement
obligation in the first six months of 2004 and $0.4 million in the
comparable 2003 period.
Our lease operating costs per Mcfe produced were $0.70 in the first six
months of 2004 and $0.63 in the same period of 2003. There were no
supervision fees recorded as a reduction to production costs for the first
six months of 2004 and $1.0 million for the same 2003 period. Our lease
operating costs in the first six months of 2004 increased $3.6 million, or
22%, over the level of such expenses in the comparable 2003 period.
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Approximately $2.9 million of the increase in lease operating costs during
the first six months of 2004 was related to our domestic operations, which
increased due to higher production from our Lake Washington and AWP Olmos
areas in that period, along with increased facility repair costs in Lake
Washington. In New Zealand, production costs increased by $0.7 million in
the first six months of 2004 mainly due to the increase in currency
exchange rates, and scheduled plant maintenance activities in the six
months of 2004.
Severance and other taxes in the first six months of 2004 increased
$4.0 million, or 44%, over the level of such expenses in the comparable
2003 period. The increase was due primarily to higher commodity prices and
increased Lake Washington, AWP and Rimu/Kauri production. Severance taxes
on oil in Louisiana are 12% of oil sales, so as the percentage of our oil
production, which comes from Lake Washington increases, the overall
percentage of severance costs to sales will increase. Severance and other
taxes, as a percentage of oil and gas sales, were approximately 10% and 9%
in the first half of 2004 and 2003, respectively.
Interest expense on our Senior Subordinated Notes due 2012, including
amortization of debt issuance costs, totaled $9.6 million in the first six
months of both 2004 and 2003. Interest expense on our Senior Subordinated
Notes due 2009, including amortization of debt issuance costs, totaled
$6.6 million in the first six months of both 2004 and 2003. Interest
expense on our bank credit facility, including commitment fees and
amortization of debt issuance costs, totaled $0.9 million in the first six
months of 2004 and $0.7 million in the same 2003 period. Interest expense
on our Senior Notes due 2011, issued in June 2004, was $0.2 million in the
first half of 2004. The total interest cost in the first six months of
2004 was $17.3 million, of which $3.2 million was capitalized. The total
interest cost in the first six months of 2003 was $16.9 million, of which
$3.5 million was capitalized.
In the first six months of 2004, we incurred $2.7 million of debt
retirement costs related to the repurchase of a portion of our Senior
Subordinated Notes due 2009 pursuant to a tender offer. The costs were
comprised of approximately $1.8 million of premiums paid to repurchase the
notes, $0.6 million to write-off unamortized debt issuance costs, $0.2
million to write-off unamortized debt discount and approximately $0.1
million of other costs.
Income tax expense in the first six months of 2004 includes a reduction
from the U.S. statutory rate, primarily from the result of the currency
exchange rate effect on the New Zealand deferred tax, along with a
reduction in tax expense primarily attributable to an adjustment of the
tax basis of the TAWN properties acquired in 2002.
Net Income. Our net income in the first six months of 2004 of $27.5
million was 106% higher, and Basic EPS of $0.99 was 103% higher, than our
first six months of 2003 net income of $13.3 million and Basic EPS of
$0.49. Our Diluted EPS in the first six months of 2004 of $0.98 was 100%
higher than our 2003 Diluted EPS of $0.49. These amounts increased in the
2004 period as oil and gas revenues increased due to higher commodity
prices, increased domestic production, and the effect of the cumulative
effect of change in accounting principle recognized in the first half of
2003.
24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-(Continued)
SWIFT ENERGY COMPANY
Contractual Commitments and Obligations
Our contractual commitments for the remainder of 2004 and the next five
years and thereafter as of June 30, 2004 are as follows:
Last half
of 2004 2005 2006 2007 2008 2009 Thereafter Total