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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2002
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in its Charter)
TEXAS 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Drive, Suite 400
Houston, Texas 77060
(281) 874-2700
(Address and telephone number of principal executive offices)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
----------- ----------
Indicate the number of shares outstanding of each of the Registrant's classes
of common stock, as of the latest practicable date.
Common Stock 26,882,183 Shares
($.01 Par Value) (Outstanding at July 31, 2002)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2002
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets
- June 30, 2002 and December 31, 2001 3
Consolidated Statements of Income
- For the Three-month and Six-month periods ended
June 30, 2002 and 2001 5
Consolidated Statements of Stockholders' Equity
- June 30, 2002 and December 31, 2001 6
Consolidated Statements of Cash Flows
- For the Six-month periods ended June 30, 2002 and 2001 7
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk 27
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 28
Item 2. Changes in Securities and Use of Proceeds None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders 28
Item 5. Other 28
Item 6. Exhibits and Reports on Form 8-K 28
SIGNATURES 30
2
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
June 30, 2002 December 31, 2001
------------------------ -------------------------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 11,805,821 $ 2,149,086
Accounts receivable -
Oil and gas sales 17,758,716 14,215,189
Associated limited partnerships
and joint ventures 4,394,632 6,259,604
Joint interest owners 4,347,160 11,467,461
Other current assets 4,433,366 2,661,640
------------------------ -------------------------
Total Current Assets 42,739,695 36,752,980
------------------------ -------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 1,087,057,241 974,698,428
Unproved properties not being amortized 71,167,746 95,943,163
------------------------ -------------------------
1,158,224,987 1,070,641,591
Furniture, fixtures, and other equipment 9,124,776 8,706,414
------------------------ -------------------------
1,167,349,763 1,079,348,005
Less-Accumulated depreciation, depletion,
and amortization (476,636,788) (448,139,334)
------------------------ -------------------------
690,712,975 631,208,671
------------------------ -------------------------
Other Assets:
Deferred income taxes 3,650,815 ---
Deferred charges 9,453,453 3,723,182
------------------------ -------------------------
13,104,268 3,723,182
------------------------ -------------------------
$ 746,556,938 $ 671,684,833
======================== =========================
See accompanying notes to consolidated financial statements.
3
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
June 30, 2002 December 31, 2001
----------------------- -------------------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 21,626,890 $ 38,884,380
Payable to associated limited partnerships 7,288,847 26,573,490
Undistributed oil and gas revenues 7,957,456 7,787,465
----------------------- -------------------------
Total Current Liabilities 36,873,193 73,245,335
----------------------- -------------------------
Long-Term Debt 324,233,604 258,197,128
Deferred Income Taxes 29,792,838 27,589,650
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000
shares authorized, none outstanding --- ---
Common stock, $.01 par value, 85,000,000
shares authorized, 27,491,666 and 25,634,598
shares issued, and 26,881,543 and 24,795,564
shares outstanding, respectively 274,917 256,346
Additional paid-in capital 329,272,061 296,172,820
Treasury stock held, at cost, 610,123 and
839,034 shares, respectively (8,749,922) (12,032,791)
Retained earnings 34,860,247 28,256,345
----------------------- -------------------------
355,657,303 312,652,720
----------------------- -------------------------
$ 746,556,938 $ 671,684,833
======================= =========================
See accompanying notes to consolidated financial statements.
4
SWIFT ENERGY COMPANY
Consolidated Statements of Income
(UNAUDITED)
Three months ended Six months ended
------------------------------ --------------------------------
06/30/02 06/30/01 06/30/02 06/30/01
-------------- ------------- ---------------- -------------
Revenues:
Oil and gas sales $ 38,331,342 $ 51,113,100 $ 64,944,183 $ 113,808,625
Fees from limited partnerships
and joint ventures 49,498 130,432 54,123 192,988
Interest income 26,531 11,514 32,293 23,853
Gain on asset disposition --- --- 7,332,668 ---
Price-risk management and other, net 162,898 1,048,219 561,079 669,813
-------------- ------------- ---------------- -------------
38,570,269 52,303,265 72,924,346 114,695,279
-------------- ------------- ---------------- -------------
Costs and Expenses:
General and administrative, net 2,597,549 2,007,754 4,871,576 3,891,985
Depreciation, depletion and amortization 14,341,510 14,718,912 28,302,274 28,105,698
Oil and gas production 10,032,445 8,979,457 19,597,852 17,937,576
Interest expense, net 6,079,879 3,188,242 9,959,683 5,837,990
-------------- ------------- ---------------- -------------
33,051,383 28,894,365 62,731,385 55,773,249
-------------- ------------- ---------------- -------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle 5,518,886 23,408,900 10,192,961 58,922,030
Provision for Income Taxes 1,934,794 8,435,954 3,589,059 21,229,431
-------------- ------------- ---------------- -------------
Income Before Cumulative Effect of Change
in Accounting Principle 3,584,092 14,972,946 6,603,902 37,692,599
Cumulative Effect of Change in Accounting
Principle (net of taxes) --- --- --- 392,868
-------------- ------------- ---------------- -------------
Net Income $ 3,584,092 $ 14,972,946 $ 6,603,902 $ 37,299,731
============== ============= ================ =============
Per share amounts -
Basic: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.13 $ 0.61 $ 0.26 $ 1.53
Cumulative Effect of Change in
Accounting Principle --- --- --- (0.02)
-------------- ------------- ---------------- -------------
Net Income $ 0.13 $ 0.61 $ 0.26 $ 1.51
============== ============= ================ =============
Diluted: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.13 $ 0.59 $ 0.25 $ 1.48
Cumulative Effect of Change in
Accounting Principle --- --- --- (0.02)
-------------- ------------- ---------------- -------------
Net Income $ 0.13 $ 0.59 $ 0.25 $ 1.46
============== ============= ================= =============
Weighted Average Shares Outstanding 26,566,357 24,722,727 25,723,981 24,694,441
============== ============= ================ =============
See accompanying notes to consolidated financial statements.
5
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Additional
Common Paid-In Treasury Retained
Stock(1) Capital Stock Earnings Total
----------- --------------- ---------------- ---------------- ---------------
Balance, December 31, 2000 $ 254,521 $ 293,396,723 $ (12,101,199) $ 50,604,110 $ 332,154,155
Stock issued for benefit plans
(11,945 shares) 72 354,973 68,408 --- 423,453
Stock options exercised
(152,915 shares) 1,529 1,942,634 --- --- 1,944,163
Employee stock purchase plan
(22,360 shares) 224 478,490 --- --- 478,714
Net income --- --- --- (22,347,765) (22,347,765)
----------- --------------- ---------------- ---------------- ---------------
Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ 28,256,345 $ 312,652,720
=========== =============== ================ ================ ===============
Stock issued for benefit plans
(37,709 shares)(2) 288 609,446 127,795 --- 737,529
Stock options exercised
(93,469 shares)(2) 935 849,232 --- --- 850,167
Public stock offering
(1,725,000 shares)(2) 17,250 30,469,094 --- --- 30,486,344
Employee stock purchase plan
(9,801 shares)(2) 98 122,343 --- --- 122,441
Stock issued in acquisition
(220,000 shares)(2) --- 1,049,126 3,155,074 --- 4,204,200
Net income (2) --- --- --- 6,603,902 6,603,902
----------- ---------------- ---------------- ---------------- ---------------
Balance, June 30, 2002 (2) $ 274,917 $ 329,272,061 $ (8,749,922) $ 34,860,247 $ 355,657,303
=========== =============== ================ ================ ===============
(1) $.01 Par Value
(2) Unaudited
See accompanying notes to consolidated financial statements.
6
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Period Ended June 30,
-----------------------------------------------
2002 2001
--------------------- -------------------
Cash Flows From Operating Activities:
Net income $ 6,603,902 $ 37,299,731
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization 28,302,274 28,105,698
Deferred income taxes 3,585,238 20,409,538
Gain on asset disposition (7,332,668) ---
Other 577,360 221,087
Change in assets and liabilities -
(Increase) decrease in accounts receivable (61,937) 9,645,030
Increase in accounts payable and accrued liabilities 3,311,435 559,932
(Increase) Decrease in income taxes receivable 600,000 (211,983)
--------------------- -------------------
Net Cash Provided by Operating Activities 35,585,604 96,029,033
--------------------- -------------------
Cash Flows From Investing Activities:
Additions to property and equipment (102,631,965) (161,623,837)
Proceeds from the sale of property and equipment 9,594,403 2,939,760
Net cash distributed as operator of
oil and gas properties (6,749,977) (16,670,709)
Net cash received (distributed) as operator of partnerships
and joint ventures (17,419,671) 2,087,129
Other 195,180 (72,322)
--------------------- -------------------
Net Cash Used in Investing Activities (117,012,030) (173,339,979)
--------------------- -------------------
Cash Flows From Financing Activities:
Proceeds from long-term debt 200,000,000 ---
Net proceeds from (payments of) bank borrowings (134,000,000) 76,100,000
Net proceeds from issuances of common stock 31,248,720 1,320,787
Payments of debt issuance costs (6,165,559) ---
--------------------- -------------------
Net Cash Provided by Financing Activities 91,083,161 77,420,787
--------------------- -------------------
Net Increase in Cash and Cash Equivalents 9,656,735 109,841
Cash and Cash Equivalents at Beginning of Period 2,149,086 1,986,932
--------------------- -------------------
Cash and Cash Equivalents at End of Period $ 11,805,821 $ 2,096,773
===================== ===================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized $ 5,560,282 $ 5,607,962
Cash paid during period for income taxes $ 2,500 $ 221,668
Non-cash investing activity:
Issuance of common stock in acquisition $ 4,204,200 $ ---
See accompanying notes to consolidated financial statements.
7
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
(1) GENERAL INFORMATION
The consolidated financial statements included herein have been
prepared by Swift Energy Company and are unaudited, except for the balance
sheet at December 31, 2001, which has been prepared from the audited
financial statements at that date. The financial statements reflect
necessary adjustments, all of which were of a recurring nature, and are in
the opinion of our management necessary for a fair presentation. Certain
information and footnote disclosures normally included in financial
statements prepared in accordance with accounting principles generally
accepted in the United States have been omitted pursuant to the rules and
regulations of the Securities and Exchange Commission. We believe that the
disclosures presented are adequate to allow the information presented not
to be misleading. The consolidated financial statements should be read in
conjunction with the audited financial statements and the notes thereto
included in the latest Form 10-K and Annual Report.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Oil and Gas Properties
We follow the "full cost" method of accounting for oil and gas property
and equipment costs. Under this method of accounting, all productive and
nonproductive costs incurred in the exploration, development and
acquisition of oil and gas reserves are capitalized. Under the full-cost
method of accounting, such costs may be incurred both prior to or after
the acquisition of a property and include lease acquisitions, geological
and geophysical services, drilling, completion, equipment, and certain
general and administrative costs directly associated with acquisition,
exploration, and development activities. Interest costs related to
unproved properties are also capitalized to unproved oil and gas
properties. Interest not capitalized and general and administrative costs
related to production and general overhead are expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil
and gas properties, except in transactions involving a significant amount
of reserves. The proceeds from the sale of oil and gas properties are
generally treated as a reduction of oil and gas property costs, unless
such adjustments would significantly alter the relationship between
capitalized costs and proved reserves of oil and gas attributable to a
cost center.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, 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. The vast majority of
our properties are onshore, and the salvage value of the tangible
equipment should offset our site restoration and dismantlement and
abandonment costs.
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, site
restoration, and dismantlement and abandonment costs, net of salvage
value, but excluding costs of unproved properties--by an overall rate
determined by dividing the physical units of oil and gas produced during
the period by the total estimated units of proved oil and gas reserves.
This calculation is done on a country-by-country basis. All other
equipment is 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.
8
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
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, among other factors, 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 income.
Full Cost Ceiling Test. At the end of each quarterly reporting period,
the unamortized cost of oil and gas properties, net of related deferred
income taxes, is limited to the sum of the estimated future net revenues
from proved properties using period-end prices, discounted at 10%, and the
lower of cost or fair value of unproved properties, adjusted for related
income tax effects ("Ceiling Test"). This calculation is done on a
country-by-country basis for those countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production, timing,
and plan of development. The accuracy of any reserves estimate is a
function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify revision of
such estimate. Accordingly, reserves estimates are often different from
the quantities of oil and gas that are ultimately recovered.
In the fourth quarter of 2001, as a result of low oil and gas prices at
December 31, 2001, we reported a non-cash write-down on a before-tax basis
of $98.9 million ($63.5 million after tax) on our domestic properties. We
had no write-down on our New Zealand properties.
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 the Company's period-end prices used in the Ceiling Test, even if
only for a short period, it is possible that additional write-downs of oil
and gas properties could occur in the future.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to
make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from estimates.
9
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
Earnings Per Share
Basic earnings per share ("Basic EPS") has been computed using the
weighted average number of common shares outstanding during the respective
periods. Diluted EPS for all periods also assumes, as of the beginning of
the period, exercise of stock options using the treasury stock method. The
following is a reconciliation of the numerators and denominators used in
the calculation of Basic and Diluted EPS (before cumulative effect of
change in accounting principle) for the three-month and six-month periods
ended June 30, 2002 and 2001:
Three Months Ended June 30,
----------------------------------------------------------------------------------
2002 2001
---------------------------------------- ---------------------------------------
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 3,584,092 26,566,357 $ .13 $ 14,972,946 24,722,727 $ .61
Stock Options --- 390,804 --- 813,891
-------------- ------------ ------------ ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions 3,584,092 26,957,161 $ .13 $ 14,972,946 25,536,618 $ .59
-------------- ------------ ------------ ------------
Six Months Ended June 30,
----------------------------------------------------------------------------------
2002 2001
---------------------------------------- ----------------------------------------
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 $ 6,603,902 25,723,981 $ .26 $ 37,692,599 24,694,441 1.53
Stock Options --- 422,158 --- 832,014
-------------- ------------ ------------ ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 6,603,902 26,146,139 $ .25 $ 37,692,599 25,526,455 1.48
-------------- ------------ ------------ ------------
Options to purchase 2.7 million shares of common stock, at an average
exercise price of $17.64 were outstanding at June 30, 2002. Approximately
1.2 million and 1.0 million options to purchase shares were not included
in the computation of diluted EPS, for the three months and six months
ended June 30, 2002, respectively, because the option price was greater
than the average closing market price of the common shares during those
periods.
Price Risk Management Activities
Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting
for Derivative Instruments and Hedging Activities" establishes accounting
and reporting standards requiring that every derivative instrument
(including certain derivative instruments
10
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
embedded in other contracts) be reported in the balance sheet as either an
asset or liability measured at its fair value. SFAS No. 133 requires that
changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges would allow the gains and losses on derivatives to
offset related results on the hedged item in the income statements and
would require that a company formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting.
We have a risk management policy to use derivative instruments to
protect against declines in oil and gas prices. Mainly, the purchase of
protection price floors and collars. We did not elect to designate our
derivatives for special hedge accounting treatment and instead are using
mark-to-market accounting treatment. We adopted SFAS No. 133 effective
January 1, 2001. Accordingly, we marked our open contracts at December 31,
2000 to fair value at that date resulting in a one-time net of taxes
charge of $392,868, which was recorded as a Cumulative Effect of Change in
Accounting Principle. During the first six months of 2002 and 2001, we
recognized net losses of $19,879 and net gains of $293,774 respectively,
relating to our derivative activities. Approximately $105,597 of the
losses recognized in 2002 were unrealized as the contracts were still
open, while $195,419 of the gains recognized in the comparative 2001
period were unrealized. This activity is recorded in "Price Risk
Management and Other, net" on the accompanying statements of income.
At June 30, 2002, we had in place certain "costless collar" financial
transactions in effect through the December 2002 contract month. Such
derivatives qualify for cash flow hedge accounting under SFAS No.133, as
amended. We did not elect to designate our derivatives for special hedge
accounting treatment. The crude oil collars cover notional volumes of
45,000 barrels of oil per month, with floor prices ranging from $20.00 to
$21.00 per barrel and ceiling prices ranging from $27.52 to $27.65 per
barrel, plus 60% participation by the Company in prices realized above
these ceilings. The natural gas collars cover notional volumes of 280,000
MMBtu per month, with floor prices ranging from $2.50 to $2.75 per MMBtu
and ceiling prices ranging from $4.21 to $4.55 per MMBtu, also with 60%
participation by the Company in prices realized above these ceilings. The
fair value of our "costless collar" transactions was a liability of
$79,440 for the crude oil collars and a liability of $26,157 for the
natural gas collars at June 30, 2002.
New Accounting Principle
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 entity increases the carrying amount of the related
long-lived asset. Over time, accretion of the liability is recognized each
period, and the capitalized cost is depreciated over the useful life of
the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss
upon settlement. This standard will require us to record a liability for
the fair value of our dismantlement and abandonment costs, excluding
salvage values. The standard is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. The Company is
currently evaluating the effect of adopting Statement No. 143 on its
financial statements and will adopt the statement on January 1, 2003.
11
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
(3) LONG-TERM DEBT
Our long-term debt as of June 30, 2002 and December 31, 2001, is as
follows (in thousands):
June 30, December 31,
2002 2001
----------------- -------------------
Bank Borrowings $ --- $ 134,000
Senior Notes due 2009 124,234 124,197
Senior Notes due 2012 200,000 ---
----------------- -------------------
Long-Term debt $ 324,234 $ 258,197
------------------ -------------------
The unamortized discount on the Senior Notes due 2009 was approximately
$766 and $803 thousand at June 30, 2002 and December 31, 2001
respectively.
Bank Borrowings
Under our $300.0 million credit facility with a syndicate of nine
banks, at June 30, 2002 we had no outstanding borrowings and at year-end
2001 outstanding borrowings of $134.0 million. At June 30, 2002, the
credit facility consisted of a $300.0 million secured revolving line of
credit with a $195.0 million borrowing base. The interest rate is either
(a) the lead bank's prime rate (4.75 % at June 30, 2002) 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. Our credit facility extends until October 1, 2005.
The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $5.0 million in
any fiscal year), a remaining aggregate limitation on purchases of Company
stock of $15.0 million, requirements as to maintenance of certain minimum
financial ratios (principally pertaining to working capital, debt, and
equity ratios), and limitations on incurring other debt. Since inception,
no cash dividends have been declared on our common stock. We are currently
in compliance with the provisions of this agreement. The credit facility
is secured by our domestic oil and gas properties. We have also pledged
65% of the stock in our two active New Zealand subsidiaries as collateral
for this credit facility. The borrowing base is re-determined at least
every six months and was reconfirmed on April 5, 2002 with the same $275.0
million borrowing base. The next scheduled borrowing base review is
November 2002. Upon closing of our $200.0 million senior subordinated
notes offering, on April 12, 2002, our borrowing base was reduced by $80.0
million, or 40% of the notes offering, to $195.0 million.
Senior Notes Due 2009
Our Senior Notes due 2009 at June 30, 2002, consist of $125,000,000 of
10.25% Senior Subordinated Notes due 2009. The Senior Notes were issued at
99.236% of the principal amount on August 4, 1999, and will mature on
August 1, 2009. The notes are unsecured senior subordinated obligations
and are subordinated in right of payment to all our existing and future
senior debt, including our bank debt. Interest on the Senior Notes is
payable semiannually on February 1 and August 1. On or after August 1,
2004, the Senior Notes are redeemable for cash at the option of Swift,
with certain restrictions, at 105.125% of
12
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
principal, declining to 100% in 2007. Upon certain changes in control of
Swift, each holder of Senior Notes will have the right to require us to
repurchase the Senior Notes at a purchase price in cash equal to 101% of
the principal amount, plus accrued and unpaid interest to thedate of
purchase. We are currently in compliance with the provisions of the
indenture governing the Senior Notes.
Senior Notes Due 2012
Our Senior Notes due 2012 at June 30, 2002, consist of $200,000,000 of
9.375 % Senior Subordinated Notes due 2012. The Senior Notes were issued
on April 11, 2002 and will mature on May 1, 2012. The notes are unsecured
senior subordinated obligations and are subordinated in right of payment
to all our existing and future senior debt, including our bank debt.
Interest on the Senior Notes is payable semiannually on May 1 and November
1, with the first interest payment on November 1, 2002. On or after May 1,
2007, the Senior Notes are redeemable for cash at the option of Swift,
with certain restrictions, at 104.688% of principal, declining to 100% in
2010. In addition, prior to May 1, 2005, we may redeem up to 33.33% of the
Senior Notes with the proceeds of qualified offerings of our equity at
109.375% of the principal amount of the Senior Notes, together with
accrued and unpaid interest. Upon certain changes in control of Swift,
each holder of Senior Notes will have the right to require us to
repurchase the Senior Notes at a purchase price in cash equal to 101% of
the principal amount, plus accrued and unpaid interest to the date of
purchase. We are currently in compliance with the provisions of the
indenture governing the Senior Notes.
(4) STOCKHOLDERS' EQUITY
In March 2002, we issued 220,000 shares of our common stock, along with
cash consideration as a closing date adjustment, to acquire all of the New
Zealand assets of Antrim Oil and Gas Limited ("Antrim"). These 220,000
shares, with a fair market value of $4.2 million, were issued from our
treasury shares, and resulted in an increase to paid-in capital of $1.0
million and a decrease in the value of our treasury stock of $3.2 million.
In April 2002, we issued 1,725,000 shares of common stock in a public
offering, at a price of $18.25 per share. Gross proceeds from this
offering were $31,481,250, with issuance costs of $994,906.
(5) NEW ZEALAND ACTIVITIES
Our activity in New Zealand began in 1995. As of June 30, 2001, our
permit 38719, which we operate, included approximately 49,800 acres in the
Taranaki Basin of New Zealand's North Island. This acreage includes our
Rimu and Kauri areas as well as our Tawa and Matai prospects.
We expanded our operation in New Zealand in January 2002 with our
purchase of Southern Petroleum (NZ) Exploration, Limited, from Shell New
Zealand, through which we acquired interests in four fields and
significant infrastructure assets.
In March 2002, we completed the acquisition of all of the New Zealand
assets of Antrim. These assets include a 5% working interest in the
Swift-operated permit 38719, increasing the Company's interest in this
permit to 95%. An additional 7.5% interest was also acquired in permit
38716, increasing the Company's interest to 15%.
As of June 30, 2002, our gross investment in New Zealand totaled
approximately $150.3 million. Approximately $124.1 million of our
investment costs have been included in the proved properties portion of
our oil and gas properties while $26.2 million is included as unproved
properties.
13
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
In August 2002 we were awarded two additional onshore permits, permits
38756 and 38759. These permits include approximately 8,100 and 20,400
gross acres, respectively, in proximity to our permit 38719.
Rimu Area. Early in 2002, we were awarded petroleum mining permit 38151
by the New Zealand Ministry for Economic Development for the development
of the Rimu discovery over an approximately 5,500 acre area for a primary
term of 30 years. We plan to add up to three drilling pads in the permit
area, for a total of five pads, with each able to handle multiple wells.
Nine additional wells are currently planned within the mining permit,
one gas injection well and eight development wells targeting the Upper
Tariki and Lower Tariki sandstones and the Upper Rimu limestone. During
the first quarter of 2002, the Rimu-A2 sidetrack was successfully
completed and recently underwent fracture stimulation. The Rimu-B3
development well was also sidetracked in early 2002 but was unsuccessful.
Kauri Area. The Kauri-A3 development well was drilled and is currently
awaiting long-term production testing. The Kauri-A4 exploratory well began
drilling in June 2002 and is targeting the Kauri, Tariki and Kapuni sands.
TAWN Area. The TAWN acquisition in January 2002 consisted of a 96.76%
working interest in four petroleum mining licenses, or PML, covering
producing oil and gas fields, and extensive associated
hydrocarbon-processing facilities and pipelines, which give us a
competitive advantage through infrastructure that complements our existing
fields, providing us with increased access to export terminals and markets
and additional excess processing capacity for both oil and natural gas.
The TAWN assets are located approximately 17 miles north of the Rimu area.
The properties are collectively identified as the TAWN properties, an
acronym derived from the first letters of the field names - the Tariki
Field (PML 38138), the Ahuroa Field (PML 38139), the Waihapa Field (PML
38140), and the Ngaere Field (PML 38141). The four fields include 17 wells
where the purchaser of gas, Contact Energy, has contracted to take minimum
quantities and can call for higher production levels (which occurred
during the first quarter of 2002) to meet electrical demand in New
Zealand.
Solution gas gathered from an oil facility, the Waihapa Production
Station ("WPS"), flows to the Tariki Ahuroa gas plant. The current
processing capacity of the WPS facility is over 15,000 barrels of oil and
40 MMcf of natural gas per day. A 32 mile, eight inch diameter oil export
line runs from the WPS to the Omata Tank Farm at New Plymouth, where oil
export facilities allow for sales into international markets. An
additional 32 mile, eight inch diameter natural gas pipeline runs from the
WPS to the Taranaki Combined Cycle Electric Generation Facility near
Stratford and on to the New Plymouth Power Station.
We have a service agreement with the owner of the Omata Tank Farm to
utilize the blending, storage, and export capabilities of the facility.
The operator of the facility provides services for a fixed fee per barrel
received and other variable costs as required by the agreement. Under the
terms of the agreement, crude oil produced from the Rimu/Kauri area has
access to the Omata Tank Farm.
Our contract with Shell Petroleum Mining (SPM), which purchases all of
our New Zealand crude oil production, runs through the end of 2002 and may
be renewed for an additional year at our request. The delivery point for
our crude oil sales is the ship's flange. SPM and the Omata Tank Farm
coordinate logistical issues for shipments, and thus SPM's decisions
regarding sales from the Omata Tank Farm can affect the timing of sales of
that portion of our production.
14
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
Rimu Production Station. We completed construction on the Rimu
Production Station ("RPS") during the first quarter and production was
processed through this facilitybeginning in the second quarter of 2002.
Our oil production processed through the RPS is transported to our WPS
facility and then sent by pipeline to the Omata Tank Farm. Our natural gas
production processed through the RPS is sold to Genesis Power Ltd. under a
long-term contract. Natural gas prices are substantially lower in New
Zealand, as compared to domestic prices, due to the abundance of
hydro-electric power plants in New Zealand.
(6) SEGMENT INFORMATION
Below is a summary of financial information by country.
Three Months Ended June 30,
-------------------------------------------------------------------------------------
2002 2001
----------------------------------------- ----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ ------------ ------------- ------------ ----------- -------------
Oil and gas sales $ 31,273,908 $ 7,057,434 $ 38,331,342 $ 50,291,707 $ 821,393 $ 51,113,100
Costs and Expenses:
Depreciation, depletion and amortization 11,852,659 2,488,851 14,341,510 14,655,361 63,551 14,718,912
Oil and gas production 7,937,289 2,095,156 10,032,445 8,911,406 68,051 8,979,457
Income from oil and gas operations $ 11,483,960 $ 2,473,427 $ 13,957,387 $ 26,724,940 $ 689,791 $ 27,414,731
Six Months Ended June 30,
-------------------------------------------------------------------------------------
2002 2001
----------------------------------------- ----------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ ------------ ------------- ------------ ----------- -------------
Oil and gas sales $ 53,747,288 $ 11,196,895 $ 64,944,183 $112,987,232 $ 821,393 $ 113,808,625
Costs and Expenses:
Depreciation, depletion and amortization 24,013,954 4,288,320 28,302,274 28,040,838 64,860 28,105,698
Oil and gas production 16,697,156 2,900,696 19,597,852 17,869,525 68,051 17,937,576
Income from oil and gas operations $ 13,036,178 $ 4,007,879 $ 17,044,057 $ 67,076,869 $ 688,482 $ 67,765,351
Property, Plant and Equipment, net $544,996,156 $145,716,819 $ 690,712,975 $611,228,300 $53,169,369 $ 664,397,669
(7) ACQUISITIONS
Through our subsidiary, Swift Energy New Zealand Limited ("SENZ"), we
acquired Southern Petroleum (NZ) Exploration Limited ("Southern NZ") in
January 2002 for approximately $51.6 million in cash. Southern NZ was an
affiliate of Shell New Zealand and owns interests in four onshore
producing oil and gas fields, hydrocarbon processing facilities, and
pipelines connecting the fields and facilities to export terminals and
markets. This acquisition was accounted for by the purchase method of
accounting. In conjunction with the TAWN acquisition, we granted Shell New
Zealand a short-term option to acquire an undivided
15
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
JUNE 30, 2002 (UNAUDITED) AND DECEMBER 31, 2001
25% interest in our permit 38719, which includes our Rimu and Kauri areas
and the Rimu Production Station. This option was not exercised and expired
on May 15, 2002.
In March 2002, we purchased through our subsidiary, SENZ, all of the
New Zealand assets owned by Antrim for 220,000 shares of Swift Energy
common stock and an effective date adjustment of approximately $0.5
million. Antrim owned a 5% interest in permit 38719 and a 7.5% interest in
permit 38716.
16
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Over the last several years, we have emphasized adding reserves through
drilling activity. We also add reserves through strategic purchases of
producing properties when oil and gas prices are lower and other market
conditions are appropriate. We have used this flexible strategy of
employing both drilling and acquisitions to add more reserves than we have
depleted through production.
CRITICAL ACCOUNTING POLICIES
For a discussion of our critical accounting policies, see Note 2 in the
"Notes to Consolidated Financial Statements" section of this report. The
policies identified are those relating to oil and gas properties, the full
cost ceiling test, the use of estimates and price-risk management
activities.
RELATED-PARTY TRANSACTIONS
We are the operator of a number of properties owned by our affiliated
limited partnerships and joint ventures and, accordingly, charge these
entities and third-party joint interest owners operating fees. The
operating fees charged to the partnerships in the first six months of 2002
and 2001 were $0.2 million and $0.5 million, respectively. We are also
reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled $0.8
million and $1.7 million in the first six months of 2002 and 2001,
respectively.
CONTRACTUAL COMMITMENTS AND OBLIGATIONS
Our contractual commitments for the next three and one half years and
thereafter as of June 30, 2002 are as follows:
2002 2003 2004 2005 Thereafter Total
---- ---- ---- ---- ---------- -----
Non-cancelable operating lease
commitments $ 696,547 $ 1,480,092 $1,492,268 $ 284,711 $ -- $ 3,953,618
Senior Subordinated Notes due 2009 (2) -- -- -- -- 125,000,000 125,000,000
Senior Subordinated Notes due 2012 (2) -- -- -- -- 200,000,000 200,000,000
Credit Facility which expires in
October 2005 (1) -- -- -- -- -- --
--------- ----------- ----------- ----------- --------------- ---------------
$ 696,547 $ 1,480,092 $ 1,492,268 $ 284,711 $ 325,000,000 $ 328,953,618
========= =========== =========== =========== =============== ===============
(1) There were no borrowings on the credit facility at June 30, 2002
or July 31, 2002. There was however a $0.8 million standby letter
of credit outstanding under this facility.
(2) These amounts do not include the interest obligation, which is
paid semiannually.
17
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 2002, we principally relied upon our
internally generated cash flows of $35.6 million, net proceeds from the
issuance of long-term debt of $195.0 million and net proceeds from our
public stock offering of $30.5 million, less the re-payment of bank
borrowings of $134.0 million, to fund capital expenditures of $102.6
million.
During 2001, we primarily relied upon internally generated cash flows
of $96.0 million and bank borrowings of $76.1 million to fund capital
expenditures of $161.6 million.
Net Cash Provided by Operating Activities. For the first six months of
2002, net cash provided by our operating activities was $35.6 million,
representing a 63% decrease as compared to $96.0 million during the first
six months of 2001. The $60.4 million decrease was primarily due to a
decrease of $48.9 million in oil and gas sales in the 2002 period, due to
lower commodity prices, plus a $4.1 million increase in interest expense
due to higher debt balances in the 2002 period.
Existing Credit Facility. We had $134.0 million in outstanding
borrowings under our credit facility at December 31, 2001, and no
outstanding borrowings at June 30, 2002. At June 30, 2002, our credit
facility consisted of a $300.0 million revolving line of credit with a
$195.0 million borrowing base. The borrowing base is re-determined at
least every six months with the next review in November 2002. Our
revolving credit facility includes, among other restrictions, requirements
as to maintenance of certain minimum financial ratios (principally
pertaining to working capital, debt, and equity ratios), and limitations
on incurring other debt. We are currently in compliance with the
provisions of this agreement. The borrowing base was last reconfirmed on
April 5, 2002 with a $275.0 million borrowing base. Pursuant to the terms
of our credit facility, upon closing of our $200.0 million Senior
Subordinated Notes offering, on April 11, 2002, our bank borrowing base
was reduced by $80.0 million, or 40% of the notes offering, to $195.0
million. Proceeds from this Notes offering, along with proceeds from our
common stock offering as described in Notes 3 and 4 ("Long-Term Debt" and
"Stockholder's Equity") were used to repay all outstanding indebtedness
under our credit facility.
Debt Maturities. Our credit facility extends until October 1, 2005. Our
$125.0 million senior notes mature August 1, 2009 and our $200.0 million
senior notes mature May 1, 2012. Although carrying a higher interest rate
than our credit facility, our $200.0 million senior notes effectively
match long-term debt with the recently acquired long-life assets of the
Lake Washington Field, the Rimu Production Station and the TAWN
properties. These properties were previously financed through our
short-term credit facility.
Working Capital. Our working capital increased from a working capital
deficit of $36.5 million at December 31, 2001, to a surplus of $5.9
million at June 30, 2002. This was primarily caused by a reduction in our
payable to associated limited partnerships and reductions in accrued
liabilities due to a decrease in our capital drilling activities.
Substantial partnership property sales closed prior to December 31, 2001,
resulting in a large associated payable to partners. The payments to
partners occurred during the first quarter of 2002, thus significantly
reducing the payable to associated limited partnerships for periods
subsequent to December 31, 2001.
18
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Capital Expenditures. During the first six months of 2002, we used
$102.6 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
Domestic Activities of $26.5 million as follows:
o $20.5 million for drilling costs, both development and
exploratory;
o $5.1 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $0.6 million on property, plant and equipment;
o $0.2 million of producing property acquisitions; and
o $0.1 million spent primarily for computer equipment, software,
furniture and fixtures.
New Zealand Activities of $76.1 million as follows:
o $53.3 million for property acquisitions comprised of approximately
$52.1 million for the TAWN acquisition and approximately $1.3
million for the Antrim acquisition (excluding the value of common
stock issued in the Antrim acquisition);
o $11.3 million for drilling costs, both development and
exploratory;
o $9.0 million for the construction of production facilities;
o $2.2 million on prospect costs, principally seismic and geological
costs; and
o $0.3 million for fixed assets.
For the second half of 2002, we expect to make capital expenditures of
approximately $40 to $56 million (depending on the level and costs of
actual drilling activities and on commodity prices), including investments
in all areas in which investments were made during the first six months of
the year, excluding acquisitions, as described above. We currently
estimate total capital expenditures for 2002 to be between $143 to $159
million, a decrease from 2001 capital expenditures of $275.1 million. We
anticipate that 2002's internally generated cash flows together with our
available bank borrowings, will be sufficient to finance our currently
budgeted remaining 2002 capital expenditures. We may increase our drilling
budget if market prices, which we cannot predict, improve in the second
half of the year.
We drilled or participated in drilling 13 domestic wells in the first
six months of 2002, made up of 11 in the Lake Washington area, one in the
Grand Lake area and one non-operated well in San Jacinto County, Texas.
Nine were development wells, seven of which were successful. Four
exploratory wells were drilled, one was successful. In New Zealand the
Rimu-A2 sidetrack was successfully completed and recently underwent
fracture stimulation, while the Rimu-B3 sidetrack completed drilling but
was unsuccessful. The Kauri-A3 was drilled and is currently awaiting
long-term production testing of the Manutahi
19
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
sandstone. The Kauri-A4, which has multiple objectives in the Kauri,
Tariki and Kapuni sands, began drilling in June and will take
approximately 100 days to drill and assess. The Huinga-1B, a non-operated
exploratory well in which Swift owns a 15% working interest, was completed
and will undergo production testing. For the remaining six months of 2002,
we anticipate drilling or participating in the drilling of an additional
15 domestic development wells, primarily in the Lake Washington area. In
New Zealand, we plan to drill one additional development well during the
remainder of 2002.
Currently, our 2002 capital expenditures are focused on developing and
producing long-lived oil reserves in Lake Washington and in the Rimu/Kauri
area in New Zealand. With this focus, we expect our 2002 total production
to increase by 10% to 16% over 2001 levels primarily from these areas as
well as our TAWN acquisition, while we expect production in our other core
areas to decrease as no new drilling is currently budgeted to offset the
natural production decline of these properties. This drilling focus will
help add long-lived oil reserves, and along with the TAWN acquisition,
will help develop an overall flatter production decline curve which should
extend our average reserve life and emphasize the balancing of our
reserves between oil and gas, while strengthening the production from our
two newest core areas.
RESULTS OF OPERATIONS - Three Months Ended June 30, 2002 and 2001
Revenues. Our revenues decreased 26% to $38.6 million during the second
quarter of 2002, as compared to revenues of $52.3 million for the same
period in 2001. This decrease was primarily from reductions in our oil and
gas sales that resulted from the 44% decrease in domestic gas prices
received and the 19% decrease in oil prices received. Partially offsetting
the decrease in commodity prices received was the effect of an increase in
production from our New Zealand and Lake Washington activities
Oil and Gas Sales. Our oil and gas sales decreased 25% to $38.3 million
in the second quarter of 2002, compared to $51.1 million for the
comparable period in 2001. Our natural gas production decreased 6%, while
our oil production increased 45%, resulting in a 13% or 1.4 Bcfe increase
in equivalent volumes produced compared to production in the same period
in 2001. Our average price on a Mcfe basis, however, decreased 33%
comparing the two periods. The increase in production during the 2002
period is primarily from our New Zealand and Lake Washington activities.
This $12.8 million decrease in oil and gas sales during the second
quarter of 2002 resulted from price and volume variances. The components
of our sales decrease were:
o Price variances, which led to an unfavorable variance of $18.8
million, with $13.7 million of the decrease coming from the 44%
decrease in average gas prices received, and $5.1 million of the
decrease due to the 19% lower average oil prices received; and
o Volume variances, which had a $6.0 million favorable impact on
sales, with an $8.1 million increase coming from the 312 MBbl
increase in oil sales volumes, offset by a decrease of $2.1
million from the 0.5 Bcfe decrease in gas sales volumes.
20
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our core
areas and on a total basis for the second quarter periods of 2002 and
2001. Natural gas accounted for 53% of total production volumes during the
second quarter 2002 as compared to 63% in the 2001 period.
Three Months Ended June 30,
---------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- ---------------------- ------------------------
2002 2001 2002 2001
--------- -------- -------- ----------
AWP Olmos $ 9.0 $15.9 2.5 3.2
Brookeland 3.5 8.4 1.2 1.9
Lake Washington 4.6 1.7 1.1 0.4
Masters Creek 9.3 16.9 2.6 3.7
Other 4.8 7.4 1.5 1.9
--------- -------- -------- ----------
Total Domestic $31.2 $50.3 8.9 11.1
Rimu/Kauri 1.1 0.8 0.3 0.2
TAWN 6.0 --- 3.5 ---
--------- -------- -------- ----------
Total New Zealand $ 7.1 $ 0.8 3.8 0.2
--------- -------- -------- ----------
Total $38.3 $51.1 12.7 11.3
Our second quarter of 2002 drilling efforts have focused on Lake
Washington and New Zealand. With our acquisition of the TAWN assets on
January 25, 2002, New Zealand production has increased significantly and
was approximately 30% of total production for the quarter.
The following table provides additional information regarding our oil
and gas sales:
Net Sales Volume Average Sales Price
---------------- --------------------
Oil and Oil and
Condensate Gas Combined Condensate Gas
(MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
---------- ------- -------- ---------- --------
2001
----
Three Months Ended June 30:
Domestic 655 7.1 11.1 $26.22 $4.66
New Zealand 36 --- 0.2 $23.05 ---
---------- ------- -------- ---------- --------
Total 691 7.1 11.3 $26.05 $4.66
2002
----
Three Months Ended June 30:
Domestic 848 3.8 8.9 $21.07 $3.53
New Zealand 154 2.9 3.8 $20.48 $1.36
---------- ------- -------- ---------- --------
Total 1,002 6.7 12.7 $20.97 $2.60
21
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
In the table above, for the second quarter of 2002, natural gas liquids
have been combined with oil and condensate for reporting purposes. The
natural gas liquids production for the three month 2002 period was 330
MBbls, at an average price of $12.52 per barrel.
Price-Risk Management. During the second quarter of 2002 we recognized
net losses of $105,597 relating to our derivative activities, as compared
to net gains of $887,436 in the 2001 period. All of the net losses
recognized in the second quarter of 2002 were unrealized, while $195,419
of the gains recognized in the comparative 2001 period were unrealized.
This activity is recorded in "Price Risk Management and Other, net" on the
accompanying statements of income.
Costs and Expenses. Our expenses for the second quarter of 2002
increased $4.2 million, or 14% when compared to the same period in 2001.
The majority of this increase resulted from the January 25, 2002 TAWN
acquisition and increases in overall operating activity in New Zealand.
Our general and administrative expenses for the second quarter of 2002
increased $0.6 million, or 29%, when compared to the same period in 2001.
Our general and administrative expenses per Mcfe produced also increased
$0.02 per Mcfe, or 11% during the second quarter of 2002. Such increases
reflect additional costs as our activities increased in New Zealand.
Depreciation, depletion and amortization (DD&A) of our assets,
decreased approximately $0.4 million, or 3%, for the second quarter of
2002. Domestically, DD&A decreased $2.8 million due to decreased
production in the 2002 period and to the domestic write-down of oil and
gas properties in the fourth quarter of 2001, which decreased our
depletable oil and gas property base. In New Zealand, production and the
depletable oil and gas property base both increased in the 2002 period
primarily due to the TAWN acquisition. Our overall DD&A rate per Mcfe of
production decreased to $1.13 per Mcfe in the second quarter of 2002 from
$1.31 per Mcfe in the same 2001 period.
Our production costs increased by $1.1 million, or 12%, due to $2.1
million of production costs in our New Zealand operations that were not
present in the 2001 period, partially offset by domestic production cost
decreases of $1.0 million due to decreased production in the 2002 period.
Our combined production cost per Mcfe decreased by $0.01 per Mcfe, to
$0.79 in the second quarter of 2002, from $0.80 per Mcfe in the same 2001
period.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $0.9 million in the second
quarter of 2002, compared to $1.5 million in the same 2001 period. This
decrease is due to a decrease in bank borrowings as proceeds from the
senior notes and common stock offerings in the second quarter of 2002 were
applied against the credit facility. Interest expense and discount on our
senior notes due 2009, including amortization of debt issuance costs, was
the same in the second quarter of 2002 and 2001, totaling $3.3 million in
each period. Interest expense on our senior notes due 2012, including
amortization of debt issuance costs was $4.0 million in the second quarter
of 2002. The senior notes due 2012 were issued in the second quarter of
2002 and no comparable expense was present in the 2001 period. Thus, total
interest charges for the second quarter of 2002 were $8.2 million, of
which $2.1 million was capitalized, compared to the 2001 total of $4.8
million, of which $1.6 million was capitalized. The capitalized portion of
interest is related to our unproved properties.
22
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Net Income. Our net income for the second quarter of 2002 of $3.6
million was 76% lower than net income of $15.0 million in the second
quarter of 2001. This decrease primarily reflected the effect of the
reduction in oil and gas sales received in the 2002 period, and increased
costs, as discussed above. Basic EPS of $0.13 for the second quarter of
2002 was 78% lower than Basic EPS of $0.61 in the 2001 period.
RESULTS OF OPERATIONS - Six Months Ended June 30, 2002 and 2001
Revenues. Our revenues decreased 36% to $72.9 million during the first
six months of 2002, as compared to revenues of $114.7 million for the same
period in 2001. This decrease was primarily from reductions in our oil and
gas sales that resulted from the 62% decrease in domestic gas prices
received and the 31% decrease in oil prices received. Partially offsetting
the decrease in commodity prices received was the effect of an increase in
production from our New Zealand and Lake Washington activities
Oil and Gas Sales. Our oil and gas sales decreased 43% to $64.9 million
in the first six months of 2002, compared to $113.8 million for the
comparable period in 2001. Our natural gas production decreased 4%, while
our oil production increased 50%, resulting in an 16% or 3.4 Bcfe increase
in equivalent volumes produced compared to production in the same period
in 2001. Our average price on a Mcfe basis, however, decreased 51%
comparing the two periods. The increase in production during the 2002
period is primarily from our New Zealand and Lake Washington activities.
This $48.9 million decrease in oil and gas sales during the first six
months of 2002 resulted from price and volume variances. The components of
our sales decrease were:
o Price variances, which led to an decrease in sales of $63.3
million, with $47.4 million of the decrease coming from the 62%
decrease in average gas prices received, and by a $15.9 million
decrease due to 31% lower average oil prices received; and
o Volume variances, which had a $14.4 million favorable impact on
sales, with $17.5 million of the increase coming from the 652 MBbl
increase in oil sales volumes, offset by a decrease of $3.1
million from the 0.5 Bcfe decrease in gas sales volumes.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our core
areas and on a total basis for the six month periods of 2002 and 2001.
Natural gas accounted for 53% of total production volumes during the first
six months of 2002 as compared to 64% in 2001.
23
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Six Months Ended June 30,
-------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- -------------------------- -------------------------
2002 2001 2002 2001
---- ---- ---- ----
AWP Olmos $ 16.2 $ 38.6 5.6 6.5
Brookeland 5.6 15.3 2.4 3.0
Lake Washington 6.9 2.4 1.9 0.6
Masters Creek 17.4 37.1 5.9 7.3
Other 7.6 19.6 2.7 4.0
----------- ------------- ------------- -----------
Total Domestic $ 53.7 $ 113.0 18.5 21.4
Rimu/Kauri 1.1 0.8 0.4 0.2
TAWN 10.1 --- 6.1 ---
------------ ------------- ------------- -----------
Total New Zealand $ 11.2 $ 0.8 6.5 0.2
------------ ------------- ------------- -----------
Total $ 64.9 $ 113.8 25.0 21.6
Our first half of 2002 drilling efforts have focused on Lake Washington
and New Zealand. With our acquisition of the TAWN assets on January 25,
2002, New Zealand production has increased significantly and was
approximately 26% of total production for the period.
The following table provides additional information regarding our oil
and gas sales:
Net Sales Volume Average Sales Price
--------------- -------------------
Oil and Oil and
Condensate Gas Combined Condensate Gas
(MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
---------- --------- ---------- ------------ ---------
2001
----
Six Months Ended June 30:
Domestic 1,258 13.8 21.4 $26.90 $5.73
New Zealand 36 --- 0.2 $23.05 ---
---------- --------- ---------- ------------- ---------
Total 1,294 13.8 21.6 $26.79 $5.73
2002
----
Six Months Ended June 30:
Domestic 1,681 8.5 18.5 $18.59 $2.65
New Zealand 265 4.8 6.5 $18.72 $1.30
---------- --------- ---------- ------------ ----------
Total 1,946 13.3 25.0 $18.61 $2.16
24
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
In the table above, for the first half of 2002, natural gas liquids
have been combined with oil and condensate for reporting purposes. The
natural gas liquids production for the first half 2002 period was 679
MBbls, at an average price of $11.60 per barrel.
Price-Risk Management. During the first half of 2002 we recognized net
losses of $19,879 relating to our derivative activities, as compared to
net gains of $293,744 in the 2001 period. There were $105,597 of losses
recognized in the first half of 2002 were unrealized, while $195,419 of
the gains recognized in the comparative 2001 period were unrealized. This
activity is recorded in "Price Risk Management and Other, net" on the
accompanying statements of income.
Costs and Expenses. Our expenses for the first half of 2002 increased
$7.0 million, or 12% when compared to the same period in 2001. The
majority of this increase resulted from the January 25, 2002 TAWN
acquisition and increases in overall operating activity in New Zealand.
Our general and administrative expenses for the first half of 2002
increased $1.0 million, or 25%, when compared to the same period in 2001.
Our general and administrative expenses per Mcfe produced also increased
$0.02 per Mcfe, or 11% during the first half of 2002. Such increases
reflect additional costs as our activities increased in New Zealand.
Depreciation, depletion and amortization (DD&A) of our assets,
increased approximately $0.2 million, or 1%, for the first half of 2002.
Domestically, DD&A decreased $4.0 million due to decreased production in
the 2002 period and to the domestic write-down of oil and gas properties
in the fourth quarter of 2001, which decreased our depletable oil and gas
property base. In New Zealand, production and the depletable oil and gas
property base both increased in the 2002 period due primarily to the TAWN
acquisition. Our overall DD&A rate per Mcfe of production decreased to
$1.13 per Mcfe in the first half of 2002 from $1.30 per Mcfe in the same
2001 period.
Our production costs increased by $1.7 million, or 9%, due to $2.8
million of production costs in our New Zealand operations that were not
present in the 2001 period, partially offset by domestic production cost
decreases of $1.1 million due to decreased production in the 2002 period.
Our combined production cost per Mcfe decreased by $0.04 per Mcfe, to
$0.79 in the first half of 2002, from $0.83 per Mcfe in the same 2001
period.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $2.9 million in the first
half of 2002, compared to $2.3 million in the same 2001 period. The
increase is due to an increase in bank borrowings in 2001 and the first
quarter of 2002 to partly fund capital expenditures. Proceeds from the
senior notes and common stock offering in the second quarter of 2002 were
applied against the credit facility and the bank borrowings balance at
June 30, 2002 was zero. Interest expense and discount on our senior notes
due 2009, including amortization of debt issuance costs, was $6.6 million
in the first half of 2002 and $6.5 million in the same 2001 period.
Interest expense on our senior notes due 2012, including amortization of
debt issuance costs was $4.0 million in the first half of 2002. The senior
notes due 2012 were issued in the second quarter of 2002 and no comparable
expense was present in the 2001 period. Thus, total interest charges for
the first half of 2002 were $13.5 million, of which $3.5 million was
capitalized, compared to the 2001 total of $8.8 million, of which $3.0
million was capitalized. The capitalized portion of interest is related to
our unproved properties.
25
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Net Income. Our net income for the first half of 2002 of $6.6 million
was 82% lower than net income of $37.3 million in the first half of 2001.
This decrease primarily reflected the effect of the reduction in oil and
gas sales received in the 2002 period, and increased costs, as discussed
above. Basic EPS of $0.26 for the first half of 2002 was 83% lower than
Basic EPS of $1.51 in the 2001 period.
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.
26
SWIFT ENERGY COMPANY
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Risk
Our major market risk exposure is the commodity pricing applicable to
our oil and natural gas production. Realized commodity prices received for
such production are primarily driven by the prevailing worldwide price for
crude oil and to spot prices applicable to natural gas. The effects of
such pricing volatility are discussed above, and such volatility is
expected to continue.
Our price risk program permits the utilization of agreements and
financial instruments (such as futures, forward and options contracts, and
swaps) to mitigate price risk associated with fluctuations in oil and
natural gas prices. Below is a description of the financial instruments we
have utilized to hedge our exposure to price risk.
o Price Floors - During the first six months of 2002 we recognized
net gains of $85,718 relating to price floors all of which was
realized. This activity is recorded in Price Risk Management and
Other, net on the accompanying statements of income.
o Costless Collars - At June 30, 2002 we had in place certain
"costless collar" financial transactions in effect through the
December 2002 contract month. The crude oil collars cover notional
volumes of 45,000 barrels of oil per month, with floor prices
ranging from $20.00 to $21.00 per barrel and ceiling prices
ranging from $27.52 to $27.65 per barrel, plus 60% participation
by the Company in prices realized above the ceiling. The natural
gas collars cover notional volumes of 280,000 MMBtu per month,
with floor prices ranging from $2.50 to $2.75 per MMBtu and
ceiling prices ranging from $4.21 to $4.55 per MMBtu, also with
60% participation by the Company in prices realized above these
ceilings. The fair value of our "costless collar" transactions was
a liability of $79,440 for the crude oil collars and liability of
$26,157 for the natural gas collars at June 30, 2002.
o New Zealand Gas Contracts - All of our gas production in New
Zealand is sold under long-term, fixed-price contracts. These
contracts protect against price volatility, and our revenue from
these contracts will vary only due to production fluctuations and
foreign exchange ratios.
Customer Credit Risk
The Company is 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 the Company monitors credit ratings of
customers, seeks letters of credit and parent guarantee protection, and
seeks to minimize exposure to any one customer where other customers are
readily available. Due to availability of other purchasers, we do not
believe the loss of any single oil or gas customer would materially affect
our revenues.
27
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings
No material legal proceedings are pending other than ordinary,
routine litigation incidental to the Company's business.
Item 2. Changes in Securities and Use of Proceeds - N/A
Item 3. Defaults Upon Senior Securities - N/A
Item 4. Submission of Matters to a Vote of Security Holders -
Our annual meeting of shareholders was held on May 14, 2002. At the record date,
25,934,476 shares of common stock were outstanding and entitled to one vote per
share upon all matters submitted at the meeting. At the annual meeting, two
nominees were elected to serve as Directors of Swift for three year terms to
expire at the 2005 annual meeting of shareholders:
FOR AGAINST ABSTENTIONS
--- ------- -----------
NOMINEES FOR DIRECTORS
Virgil N. Swift 22,957,728 324,917 ---
G. Robert Evans 22,910,054 372,591 ---
The terms of Directors Clyde W. Smith, Jr. and Terry E. Swift expire at the 2003
annual meeting and the terms of A. Earl Swift, Henry C. Montgomery and Harold H.
Withrow expire at the 2004 annual meeting.
Item 5. Other Information -
The Swift Energy Company Board of Directors appointed Raymond E. Galvin to serve
on the Company's Board of Directors effective August 5, 2002. Mr. Galvin served
until February 1997 as President of Chevron U.S.A. Production Co., and as a
director and vice president of Chevron Corporation, and began his career with
Gulf Oil Corp. in 1953.
Item 6. Exhibits & Reports on Form 8-K -
(a) Documents filed as part of the report
(3) Exhibits
12 Swift Energy Company Ratio of Earnings to Fixed Charges.
99.1 Certification of Chief Executive Officer and Chief Financial
Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
(b) Reports on Form 8-K filed during the quarter ended June 30, 2002, which
are incorporated herein by reference:
1. On April 9, 2002, the Company filed a Current Report on Form
8-K that reported under Item 5, "Other Events," that the
Company entered into an Underwriting Agreement with Credit
Suisse First
28
Boston ("CSFB") covering the proposed issuance and sale to
CSFB of 1.5 million shares of its common stock at $17.75 per
share and at the option of CSFB, an aggregate of not more
than 225,000 additional shares at $17.75 per share.
2. On April 11, 2002, the Company filed a Current Report on
Form 8-K that reported under Item 5, "Other Events," that
the Company entered into an underwriting agreement with
Credit Suisse First Boston Corporation, covering the
proposed issuance of $200 million aggregate principal amount
of 9 3/8% Senior Subordinated Notes due 2012.
3. On June 12, 2002, the Company filed a Current Report on Form
8-K that reported under Item 4, "Changes in Registrant's
Certifying Accountant," that the Board of Directors of the
Company approved the appointment of Ernst & Young LLP as the
Company's independent auditors for the fiscal year ending
December 31, 2002, to replace Arthur Andersen LLP as the
Company's independent auditors effective as of June 12,
2002.
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SWIFT ENERGY COMPANY
(Registrant)
Date: August 13, 2002 By: (original signed by)
----------------- ---------------------------------
Alton D. Heckaman, Jr.
Senior Vice President,
Chief Financial Officer
Date: August 13, 2002 By: (original signed by)
----------------- ---------------------------------
David W. Wesson
Controller and Principal Accounting
Officer
30
Exhibit 12
31
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
Six Months Ended June 30,
2002 2001
GROSS G&A 13,170,433 12,837,884
NET G&A 4,871,576 3,891,985
INTEREST EXPENSE 9,959,683 5,837,990
RENT EXPENSE 872,116 596,366
NET INCOME BEFORE TAXES 10,192,961 58,922,030
CAPITALIZED INTEREST 3,464,402 3,058,304
DEPLETED CAPITALIZED INTEREST 62,846 76,819
CALCULATED DATA
UNALLOCATED G&A (%) 36.99% 30.32%
NON-CAPITAL RENT EXPENSE 322,585 180,797
1/3 NON-CAPITAL RENT EXPENSE 107,528 60,266
FIXED CHARGES 13,531,613 8,956,560
EARNINGS 20,323,019 64,897,105
1.50 7.25
32
Exhibit 99.1
33
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the accompanying Quarterly Report on Form 10-Q for the
quarter ended June 30, 2002 (the "Report") of Swift Energy Company ("Swift") as
filed with the Securities and Exchange Commission on August 14, 2002, the
undersigned, in his capacity as an officer of Swift, hereby certifies pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that to his knowledge:
1. The Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934, as amended; and
2. The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of
Swift.
Dated: August 13, 2002 By: (Original signed by)
----------------------------------------
Alton D. Heckaman, Jr.
Senior Vice President-Finance and
Chief Financial Officer
Dated: August 13, 2002 By: (Original signed by)
----------------------------------------
Terry E. Swift
President and Chief Executive Officer
This certification made in accordance with Section 906 of the Sarbanes-Oxley Act
of 2002 accompanies the Quarterly Report on Form 10-Q of Swift for the period
ended June 30, 2002. This certification shall not be deemed filed by Swift for
purposes of Section 18 of the Securities and Exchange Act of 1934, as amended.
34