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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 September 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 27,193,069 Shares
($.01 Par Value) (Outstanding at October 31, 2002)
(Class of Stock)
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets
- September 30, 2002 and December 31, 2001 3
Consolidated Statements of Income
- For the Three-month and Nine-month periods ended
September 30, 2002 and 2001 5
Consolidated Statements of Stockholders' Equity
- September 30, 2002 and December 31, 2001 6
Consolidated Statements of Cash Flows
- For the Nine-month periods ended September 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 18
Item 3. Quantitative and Qualitative Disclosures About Market Risk 28
Item 4. Controls and Procedures 29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 30
Item 2. Changes in Securities and Use of Proceeds None
Item 3. Defaults Upon Senior Securities None
Item 4. Submission of Matters to a Vote of Security Holders None
Item 5. Other None
Item 6. Exhibits and Reports on Form 8-K 30
SIGNATURES 31
CERTIFICATIONS 31
2
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, 2002 December 31, 2001
------------------------ --------------------------
(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents $ 1,713,949 $ 2,149,086
Accounts receivable -
Oil and gas sales 15,686,669 14,215,189
Associated limited partnerships
and joint ventures 6,232,143 6,259,604
Joint interest owners 2,433,084 11,467,461
Other current assets 5,136,262 2,661,640
------------------------ --------------------------
Total Current Assets 31,202,107 36,752,980
------------------------ --------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 1,115,684,232 974,698,428
Unproved properties not being amortized 75,556,398 95,943,163
------------------------ --------------------------
1,191,240,630 1,070,641,591
Furniture, fixtures, and other equipment 9,316,998 8,706,414
------------------------ --------------------------
1,200,557,628 1,079,348,005
Less-Accumulated depreciation, depletion,
and amortization (489,997,433) (448,139,334)
------------------------- --------------------------
710,560,195 631,208,671
------------------------ --------------------------
Other Assets:
Deferred income taxes 2,886,507 ---
Deferred charges 9,288,312 3,723,182
------------------------ --------------------------
12,174,819 3,723,182
------------------------ --------------------------
$ 753,937,121 $ 671,684,833
======================== ==========================
See accompanying notes to consolidated financial statements.
3
SWIFT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, 2002 December 31, 2001
------------------------ ------------------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 29,712,887 $ 38,884,380
Payable to associated limited partnerships 18,396 26,573,490
Undistributed oil and gas revenues 4,039,388 7,787,465
------------------------ ------------------------
Total Current Liabilities 33,770,671 73,245,335
------------------------ ------------------------
Long-Term Debt 328,752,630 258,197,128
Deferred Income Taxes 29,909,411 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, 27,803,192 and 25,634,598
shares issued, and 27,193,069 and 24,795,564
shares outstanding, respectively 278,032 256,346
Additional paid-in capital 333,285,276 296,172,820
Treasury stock held, at cost, 610,123 and
839,034 shares, respectively (8,749,922) (12,032,791)
Retained earnings 36,807,253 28,256,345
Other comprehensive loss, net of taxes (116,230) ---
------------------------ ------------------------
361,504,409 312,652,720
------------------------ ------------------------
$ 753,937,121 $ 671,684,833
======================== ========================
See accompanying notes to consolidated financial statements.
4
SWIFT ENERGY COMPANY
Consolidated Statements of Income
(UNAUDITED)
Three months ended Nine months ended
------------------------------ ---------------------------------
09/30/02 09/30/01 09/30/02 09/30/01
-------------- ------------- ---------------- --------------
Revenues:
Oil and gas sales $ 36,592,329 $ 39,346,270 $ 101,536,512 $ 153,154,895
Fees from limited partnerships
and joint ventures 5,830 19,196 59,953 212,184
Interest income 158,664 15,935 190,957 39,788
Gain on asset disposition --- --- 7,332,668 ---
Price-risk management and other, net (186,014) 1,863,182 375,065 2,532,995
-------------- ------------- ---------------- --------------
36,570,809 41,244,583 109,495,155 155,939,862
-------------- ------------- ---------------- --------------
Costs and Expenses:
General and administrative, net 2,497,413 2,099,533 7,368,989 5,991,518
Depreciation, depletion and amortization 13,487,437 14,857,858 41,789,711 42,963,556
Oil and gas production 11,004,641 9,285,213 30,602,493 27,222,789
Interest expense, net 6,647,968 3,394,416 16,607,651 9,232,406
-------------- ------------- ---------------- --------------
33,637,459 29,637,020 96,368,844 85,410,269
-------------- ------------- ---------------- --------------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle 2,933,350 11,607,563 13,126,311 70,529,593
Provision for Income Taxes 986,344 4,187,473 4,575,403 25,416,904
-------------- ------------- ---------------- --------------
Income Before Cumulative Effect of Change
in Accounting Principle 1,947,006 7,420,090 8,550,908 45,112,689
Cumulative Effect of Change in Accounting
Principle (net of taxes) --- --- --- 392,868
-------------- ------------- ---------------- --------------
Net Income $ 1,947,006 $ 7,420,090 $ 8,550,908 $ 44,719,821
============== ============= ================ ==============
Per share amounts -
Basic: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.07 $ 0.30 $ 0.33 $ 1.83
Cumulative Effect of Change in
Accounting Principle --- --- --- (0.02)
-------------- ------------- ---------------- --------------
Net Income $ 0.07 $ 0.30 $ 0.33 $ 1.81
============== ============= ================ ===============
Diluted: Income Before Cumulative Effect of
Change in Accounting Principle $ 0.07 $ 0.29 $ 0.32 $ 1.77
Cumulative Effect of Change in
Accounting Principle --- --- --- (0.02)
-------------- ------------- ---------------- --------------
Net Income $ 0.07 $ 0.29 $ 0.32 $ 1.75
============== ============= ================ ==============
Weighted Average Shares Outstanding 26,889,186 24,760,352 26,112,382 24,716,411
============== ============= ================ ==============
See accompanying notes to consolidated financial statements.
5
SWIFT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Additional Other
Common Paid-In Treasury Retained Comprehensive
Stock(1) Capital Stock Earnings Loss 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
(104,995 shares)(2) 1,050 956,732 --- --- --- 957,782
Public stock offering
(1,725,000 shares)(2) 17,250 30,465,809 --- --- --- 30,483,059
Employee stock purchase
plan(9,801 shares)(2) 98 122,343 --- --- --- 122,441
Stock issued in
acquisitions (520,000
shares)(2) 3,000 4,958,126 3,155,074 --- --- 8,116,200
Net income (2) --- --- --- 8,550,908 --- 8,550,908
Changes in fair value of
outstanding hedge
positions, net of taxes
of $65,380 (2) --- --- --- --- (116,230) (116,230)
---------- -------------- -------------- --------------- ------------- --------------
Balance, September 30, 2002(2) $ 278,032 $ 333,285,276 $ (8,749,922) $ 36,807,253 $ (116,230) $ 361,504,409
========== ============== ============== =============== ============= ==============
(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 September 30,
-----------------------------------------------
2002 2001
--------------------- -------------------
Cash Flows From Operating Activities:
Net income $ 8,550,908 $ 44,719,821
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization 41,789,711 42,963,556
Deferred income taxes 4,554,165 24,466,717
Gain on asset disposition (7,332,668) ---
Other 728,917 (440,079)
Change in assets and liabilities -
Decrease in accounts receivable 1,263,553 13,248,588
Increase (decrease) in accounts payable and accrued liabilities 5,539,810 (2,934,545)
(Increase) decrease in income taxes receivable 600,000 (211,983)
--------------------- -------------------
Net Cash Provided by Operating Activities 55,694,396 121,812,075
--------------------- -------------------
Cash Flows From Investing Activities:
Additions to property and equipment (132,521,779) (217,959,614)
Proceeds from the sale of property and equipment 11,525,547 2,939,521
Net cash distributed as operator of
oil and gas properties (4,247,012) (24,115,980)
Net cash received (distributed) as operator of partnerships
and joint ventures (26,527,633) 341,164
Other 68,388 (80,074)
--------------------- -------------------
Net Cash Used in Investing Activities (151,702,489) (238,874,983)
--------------------- -------------------
Cash Flows From Financing Activities:
Proceeds from long-term debt 200,000,000 ---
Net proceeds from (payments of) bank borrowings (129,500,000) 115,700,000
Net proceeds from issuances of common stock 31,330,384 1,462,744
Payments of debt issuance costs (6,257,428) ---
--------------------- -------------------
Net Cash Provided by Financing Activities 95,572,956 117,162,744
--------------------- -------------------
Net Increase (decrease) in Cash and Cash Equivalents (435,137) 99,836
Cash and Cash Equivalents at Beginning of Period 2,149,086 1,986,932
--------------------- -------------------
Cash and Cash Equivalents at End of Period $ 1,713,949 $ 2,086,768
===================== ===================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized $ 10,511,529 $ 12,157,044
Cash paid during period for income taxes $ 2,500 $ 235,564
Non-cash investing activity:
Issuance of common stock in acquisitions $ 8,116,200 $ ---
See accompanying notes to consolidated financial statements.
7
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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.
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.
8
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
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
SEPTEMBER 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 nine-month periods ended
September 30, 2002 and 2001:
Three Months Ended September 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 $ 1,947,006 26,889,186 $ .07 $ 7,420,090 24,760,352 $ .30
Stock Options --- 242,283 --- 699,759
-------------- ------------ ------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 1,947,006 27,131,469 $ .07 $ 7,420,090 25,460,111 $ .29
-------------- ------------ ------------- ------------
Nine Months Ended September 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 $ 8,550,908 26,112,382 $ .33 $ 45,112,689 24,716,411 $ 1.83
Stock Options --- 368,786 --- 771,557
-------------- ------------ ------------- ------------
Diluted EPS:
Net Income Before Cumulative
Effect of Change in Accounting
Principle and Assumed Share
Conversions $ 8,550,908 26,481,168 $ .32 $ 45,112,689 25,487,968 $ 1.77
-------------- ------------ ------------- ------------
Options to purchase 2.8 million shares of common stock, at an
average exercise price of $17.62 were outstanding at September 30,
2002. Approximately 1.4 million and 1.2 million options to purchase
shares were not included in the computation of diluted EPS, for the
three months and nine months ended September 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
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 hedge
10
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
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 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 nine months of 2002 and 2001, we recognized net losses of
$201,474 and net gains of $1,924,931 respectively, relating to our
derivative activities. Approximately $162,727 of the losses
recognized in 2002 were unrealized as the contracts were still open,
while $775,056 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 September 30, 2002 the Company had recorded $116,230, net of
taxes of $65,380, 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 derivative
transactions that were qualified as cash flow hedges. The Company
expects to reclassify all amounts held in "Other comprehensive loss"
into the income statement within the next six months.
As of September 30, 2002, the Company had entered into the
commodity derivative instruments set forth in the table below as
cash flow hedges of its Domestic Oil and Natural Gas production for
the remainder of 2002 and part of 2003. When the Company entered
into the following transactions they were designated as a hedge of
the variability in cash flows associated with the forecasted sale of
its oil and natural gas production. Changes in the fair value of a
hedge that is highly effective, and is designated and qualifies as a
cash flow hedge, to the extent that the hedge is effective, are
initially recorded in Other Comprehensive Income (Loss). When the
hedged transactions are recorded upon the actual sale of oil and
natural gas, then these gains or losses are transferred from Other
Comprehensive Income (Loss) and recorded in Price-risk management
and other, net on the statement of income. The fair value of these
instruments is recognized on the balance sheet, in "Other current
assets", at September 30, 2002.
Crude Oil - Cash Flow Hedges Collars
---------------------------
Floors Ceilings Price Floor Contracts September 30,2002
Period and Type Volume in Weighted Weighted Weighted Fair Value
Of Contract Bbls (000s) Average Average Average (000s)
- ----------------------------------- --------------- ------------ ------------- ---------------------- -------------------
October 2002 - December 2002
Floor Contracts 195 $ 21.00 $ 2
January 2003 - March 2003
Collar Contracts 90 $ 21.00 $ 15
36 $ 30.80 $ (58)
-------------------
Total $ (41)
11
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
Natural Gas - Cash Flow Hedges Collars
---------------------------
Floors Ceilings Price Floor Contracts September 30,2002
Period and Type Volume in Weighted Weighted Weighted Fair Value
Of Contract Mmbtu (000s) Average Average Average (000s)
- ----------------------------------- --------------- ------------ ------------- ---------------------- -------------------
October 2002 - December 2002
Floor Contracts 900 $ 3.00 $ 7
January 2003 - March 2003
Collar Contracts 450 $ 3.00 $ 23
180 $ 4.75 $ (61)
-------------------
Total $ (31)
In October, 2002, the Company entered into a natural gas "collar"
financial transaction covering the contract period January 2003 to
March 2003. Notional volumes are 150,000 Mmbtu per month at a floor
price of $3.00 per Mmbtu, and 60,000 Mmbtu per month at a ceiling
price of $4.83 per Mmbtu. Also in October, 2002, the Company entered
into a crude oil "collar" financial transaction covering the
contract period January 2003 to March 2003. Notional volumes are
30,000 barrels per month at a floor price of $21.00 per barrel, and
12,000 barrels per month at a ceiling price of $32.50 per barrel.
As of September 30, 2002, the Company had entered into the
commodity derivative instruments set forth in the table below
covering contract periods through December 2002. These derivative
instruments are not accounted for as cash flow hedges and are marked
to market through earnings.
Crude oil - Mark to Market
Accounting Collars
------------------------------
Floors Ceilings September 30,2002
Period and Type Volume in Weighted Weighted Fair Value
Of Contract Bbls (000s) Average Average (000s)
--------------------------------- --------------- -------------- -------------- ---------------------
October 2002 - December 2002
Collar Contracts 135 $ 20.44 $ 1
54 $ 27.58 $ (160)
---------------------
Total $ (159)
Natural Gas - Mark to Market
Accounting Collars
------------------------------
Floors Ceilings September 30,2002
Period and Type Volume in Weighted Weighted Fair Value
Of Contract Mmbtu (000s) Average Average (000s)
--------------------------------- --------------- -------------- -------------- ---------------------
November 2002 - December 2002
Collar Contracts 560 $ 2.57 $ 1
224 $ 4.31 $ (68)
---------------------
Total $ (67)
12
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
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.
(3) LONG-TERM DEBT
Our long-term debt as of September 30, 2002 and December 31,
2001, is as follows (in thousands):
September 30, December 31,
2002 2001
----------------- -----------------
Bank Borrowings $ 4,500 $ 134,000
Senior Notes due 2009 124,253 124,197
Senior Notes due 2012 200,000 ---
----------------- -----------------
Long-Term Debt $ 328,753 $ 258,197
----------------- -----------------
The unamortized discount on the Senior Notes due 2009 was
approximately $747,000 and $803,000 at September 30, 2002 and
December 31, 2001 respectively.
Bank Borrowings
Under our $300.0 million credit facility with a syndicate of nine
banks, at September 30, 2002 we had $4.5 million in outstanding
borrowings and at year-end 2001 outstanding borrowings of $134.0
million. At September 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 September 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
by our bank group in November 2002 with the same $195.0 million
borrowing base. The next scheduled borrowing base review is May
2003.
13
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
Senior Notes Due 2009
Our Senior Notes due 2009 at September 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 principal, declining to
100% in 2007. Upon certain changes in control of Swift, each holder
of Senior Notes will have the right to require us to repurchase the
Senior Notes at a purchase price in cash equal to 101% of the
principal amount, plus accrued and unpaid interest to the date of
purchase. 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 September 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 $998,191. In September 2002, we
issued 300,000 shares of our common stock with a fair market value
of $3.9 million, along with $2.7 million in cash to acquire the
interests owned by Bligh Oil and Minerals N.L. ("Bligh") in the
Swift operated Rimu/Kauri and TAWN permits, mining licenses and
facilities in New Zealand.
(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 included 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
14
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
interest to 15%.
In September 2002, we completed the acquisition of Bligh's 5%
working interest in permit 38719 and 5% interest in the Rimu
petroleum mining permit 38151, along with their 3.24% working
interest in the four TAWN petroleum mining licenses. The Company's
interest in permit 38719, petroleum mining permit 38151 and the TAWN
petroleum mining licenses are now 100%.
As of September 30, 2002, our gross investment in New Zealand
totaled approximately $166.7 million. Approximately $133.9 million
of our investment costs have been included in the proved properties
portion of our oil and gas properties while $32.8 million is
included as unproved properties.
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. Commercial production from the
Rimu area began in May 2002.
During the first quarter of 2002, the Rimu-A2 sidetrack was
successfully completed and recently underwent fracture stimulation,
which was unsuccessful. The Rimu-B3 development well was also
sidetracked in early 2002 but was unsuccessful.
Kauri Area. The Kauri-A3 development well was drilled to the
Manutahi sands and is currently awaiting long-term production
testing. The Kauri-A4 exploratory well completed drilling in October
2002 and is undergoing production testing in the Kauri sands. This
well also intersected the Lower Tariki and Cretaceous sands, which
were deemed non-commercial in this well.
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 to meet electrical demand in New Zealand.
Sales gas deliveries to Contact have exceeded the contract minimum
during the first three quarters of 2002.
Solution gas gathered from an oil facility, the Waihapa
Production Station ("WPS"), flows to the Tariki Ahuroa gas plant
("TAG"). The current processing capacity of the WPS facility is over
15,000 barrels of oil and 45 MMcf of natural gas per day. Processing
capacity tests conducted following facility modifications completed
in the third quarter have confirmed a 12% increase in the gas
processing capacity of the TAG plant. 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 TAWN and Rimu/Kauri areas 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
15
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
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.
Rimu Production Station. We completed construction on the Rimu
Production Station ("RPS") during the first quarter of 2002 and
production was processed through this facility beginning 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, largely due to the fact that the
natural gas market has been dominated by one large field, the Maui
Field, which supplies approximately 80% of the natural gas supply
and is due to be depleted by 2007.
(6) SEGMENT INFORMATION
Below is a summary of financial information by country:
Three Months Ended September 30,
-----------------------------------------------------------------------------------------------
2002 2001
---------------------------------------------- ----------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------ -------------- --------------- ------------- --------------- --------------
Oil and gas sales $ 28,454,804 $ 8,137,525 $ 36,592,329 $ 38,387,134 $ 959,136 $ 39,346,270
Costs and Expenses:
Depreciation, depletion
and amortization 10,196,179 3,291,258 13,487,437 14,752,588 105,270 14,857,858
Oil and gas production 8,444,530 2,560,111 11,004,641 9,120,581 164,632 9,285,213
------------- -------------- --------------- ------------- --------------- --------------
Income from oil and gas
operations $ 9,814,095 $ 2,286,156 $ 12,100,251 $ 14,513,965 $ 689,234 $ 15,203,199
============= ============== =============== ============= =============== ==============
Nine Months Ended September 30,
-----------------------------------------------------------------------------------------------
2002 2001
--------------------------------------------- -------------------------------------------------
New New
Domestic Zealand Total Domestic Zealand Total
------------- -------------- --------------- ------------ --------------- --------------
Oil and gas sales $ 82,202,092 $ 19,334,420 $ 101,536,512 $ 151,374,366 $ 1,780,529 $ 153,154,895
Costs and Expenses:
Depreciation, depletion
and amortization 34,210,133 7,579,578 41,789,711 42,793,426 170,130 42,963,556
Oil and gas production 25,141,686 5,460,807 30,602,493 26,990,106 232,683 27,222,789
------------- -------------- --------------- ------------- --------------- --------------
Income from oil and gas
operations $ 22,850,273 $ 6,294,035 $ 29,144,308 $ 81,590,834 $ 1,377,716 $ 82,968,550
============= ============== =============== ============ =============== ==============
Property, Plant and Equipment,
net $ 551,583,952 $ 158,976,243 $ 710,560,195 $ 635,708,774 $ 65,106,631 $ 700,815,405
============= ============== =============== ============= =============== ==============
(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
16
SWIFT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 2002 (UNAUDITED) AND DECEMBER 31,2001
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 25% interest in
our permit 38719, which included 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.
In September 2002, we purchased through our subsidiary, SENZ,
Bligh's 5% working interest in permit 38719 and 5% interest in the
Rimu petroleum mining permit 38151, along with their 3.24% working
interest in the four TAWN petroleum mining licenses for 300,000
shares of Swift Energy common stock and $2.7 million in cash.
17
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.
CONTRACTUAL COMMITMENTS AND OBLIGATIONS
Our contractual commitments for the next three and one quarter
years and thereafter as of September 30, 2002 are as follows:
2002 2003 2004 2005 Thereafter Total (3)
---- ---- ---- ---- ---------- ---------
Non-cancelable operating lease
commitments $ 348,274 $ 1,480,092 $ 1,492,268 $ 284,711 $ -- $ 3,605,345
Senior Subordinated Notes due 2009 (1) -- -- -- -- 125,000,000 125,000,000
Senior Subordinated Notes due 2012 (1) -- -- -- -- 200,000,000 200,000,000
Credit Facility which expires in
October 2005 (2) -- -- -- 4,500,000 -- 4,500,000
--------- ----------- ----------- ------------ ---------------- -------------
$ 348,274 $ 1,480,092 $ 1,492,268 $ 4,784,711 $ 325,000,000 $ 333,105,345
========= =========== =========== ============ ================ =============
(1) These amounts do not include the interest obligation, which
is paid semiannually.
(2) These amounts exclude a $0.8 million standby letter of credit
outstanding under this facility.
(3) These amounts exclude asset retirement obligations, as
accounted for under SFAS No. 143, "Accounting for Asset
Retirement Obligations." The Company will adopt this
statement on January 1, 2003. This standard will require the
Company to record a liability for the fair value of its
dismantlement and abandonment costs, excluding salvage
values.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 2002, we principally relied upon
our internally generated cash flows of $55.7 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
repayment of bank borrowings of $129.5 million, to fund capital
expenditures of $132.5 million.
During 2001, we primarily relied upon internally generated cash
flows of $121.8 million and bank borrowings of $115.7 million to
fund capital expenditures of $218.0 million.
Net Cash Provided by Operating Activities. For the first nine
months of 2002, net cash provided by our operating activities was
$55.7 million, representing a 54% decrease as compared to $121.8
million during the first nine months of 2001. The $66.1 million
decrease was primarily due to a decrease of $51.6 million in oil and
gas sales in the 2002 period, due to lower commodity prices, plus a
$7.4 million increase in interest expense due to higher debt
balances and interest rates in the 2002 period.
18
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Existing Credit Facility. We had $134.0 million in outstanding
borrowings under our credit facility at December 31, 2001, and $4.5
million of outstanding borrowings at September 30, 2002. At
September 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
and was reconfirmed by our bank group in November 2002 with the same
$195.0 million borrowing base. 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. 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 sold, 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 at that time 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 matched long-term debt with the 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 deficit
of $2.6 million at September 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.
Capital Expenditures. During the first nine months of 2002, we
used $132.5 million to fund capital expenditures for property,
plant, and equipment. These capital expenditures included:
Domestic activities of $43.9 million as follows:
o $33.5 million for drilling costs, both development and
exploratory;
o $8.0 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $1.5 million on property, plant and equipment;
o $0.7 million of producing property acquisitions; and
o $0.2 million spent primarily for computer equipment, software,
furniture and fixtures.
New Zealand activities of $88.6 million as follows:
o $56.5 million for property acquisitions comprised of
approximately $52.1 million for the TAWN acquisition,
approximately $1.5 million for the Antrim acquisition
(excluding the value of common stock issued in the Antrim
acquisition) and $2.9 million for the Bligh acquisition
(excluding the value of common stock issued in the Bligh
acquisition);
o $19.6 million for drilling costs, both development and
exploratory;
19
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
o $8.3 million for the construction of production facilities;
o $3.8 million on prospect costs, principally seismic and
geological costs; and
o $0.4 million for fixed assets.
For the remaining three months of 2002, we expect to make capital
expenditures of approximately $21 to $30 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 nine months of the year, excluding
acquisitions, as described above. We currently estimate total
capital expenditures for 2002 to be between $154 to $162 million
excluding the value of stock issued in the Antrim and Bligh
acquisitions, a decrease from 2001 capital expenditures of $275.1
million. We anticipate that our fourth quarter 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 drilled or participated in drilling 23 domestic wells in the
first nine months of 2002, made up of 21 in the Lake Washington
area, one in the Grand Lake area and one non-operated well in San
Jacinto County, Texas. Eighteen were development wells, thirteen of
which were successful. Five exploratory wells were drilled; two were
successful. In New Zealand the Rimu-A2 sidetrack was successfully
completed and underwent fracture stimulation, while the Rimu-B3
sidetrack completed drilling but was unsuccessful. The Kauri-A3 was
drilled to the Manutahi sands, and is currently awaiting long-term
production testing. The Kauri-A4 exploratory well completed drilling
in October 2002, and is undergoing production testing in the Kauri
sands. The Huinga-1B, a non-operated exploratory well in which Swift
owns a 15% working interest, was completed but production testing
failed to yield significant hydrocarbon production. Bligh, the
operator of the Huinga-1B, is evaluating the well.
For the remaining three months of 2002, we anticipate drilling or
participating in the drilling of an additional 11 domestic
development wells, primarily in the Lake Washington area. In New
Zealand, we have a well associated with the development of oil
reserves in the shallow Manutahi sands interval planned for drilling
in the fourth quarter of 2002.
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 9% to 10% over 2001 levels primarily
from these areas and 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.
We currently anticipate that our capital expenditures for 2003
will range between $ 125 and $ 150 million. Depending on a number of
factors, such as commodity pricing, production levels and the level
and success of planned non-core property dispositions, our
internally generated cash flows are expected to fund a majority of
these expenditures. Although current plans do not call for extensive
use of our bank credit facility in 2003, we believe that our bank
borrowing base will continue to stay at or near its current level,
as our proved reserve base continues to grow. If oil and gas prices
were to drop precipitously on a sustained basis, it would negatively
affect our liquidity and cash flows, including our ability to stay
in compliance with certain financial covenants under our credit
facility. We would reduce the level of our capital expenditures in
response to any such precipitous drop in prices, as required.
20
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
RESULTS OF OPERATIONS - Three Months Ended September 30, 2002 and
2001
Revenues. Our revenues decreased 11% to $36.6 million during the
third quarter of 2002, as compared to revenues of $41.2 million for
the same period in 2001. This decrease was primarily from reductions
in our oil and gas sales that resulted from the 21% decrease in
domestic gas prices received and the 3% 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 areas.
Oil and Gas Sales. Our oil and gas sales decreased 7% to $36.6
million in the third quarter of 2002, compared to $39.3 million for
the comparable period in 2001. Our natural gas production decreased
1%, while our oil production increased 12%, resulting in a 4%, or
0.5 Bcfe, increase in equivalent volumes produced compared to
production in the same period in 2001. Our average price on a Mcfe
basis, however, decreased 11% comparing the two periods. The
increase in production during the 2002 period is primarily from our
New Zealand and Lake Washington areas.
This $2.7 million decrease in oil and gas sales during the third
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 $4.8
million, with $4.2 million of the decrease coming from the 21%
decrease in average gas prices received, and $0.6 million of
the decrease due to the 3% lower average oil prices received;
and
o Volume variances, which had a $2.1 million favorable impact on
sales, with a $2.3 million increase coming from the 95 MBbl
increase in oil sales volumes, offset by a decrease of $0.2
million from the 0.06 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 third quarter periods of
2002 and 2001. Natural gas accounted for 55% of total production
volumes during the third quarter 2002 as compared to 58% in the 2001
period.
Three Months Ended September 30,
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
----
--------------------------------- -----------------------------
2002 2001 2002 2001
---- ---- ---- ----
AWP Olmos $ 7.9 $ 10.3 2.8 3.5
Brookeland 3.2 6.7 0.8 1.8
Lake Washington 5.2 1.2 1.2 0.3
Masters Creek 8.1 14.9 2.1 3.9
Other 4.1 5.2 1.2 1.9
--------------- ---------------- ------------- --------------
Total Domestic $ 28.5 $ 38.3 8.1 11.4
Rimu/Kauri 1.4 1.0 0.7 0.3
TAWN 6.7 --- 3.4 ---
--------------- ---------------- ------------- --------------
Total New Zealand $ 8.1 $ 1.0 4.1 0.3
--------------- ---------------- ------------- --------------
Total $ 36.6 $ 39.3 12.2 11.7
Our third 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 34% of total production for the
quarter.
21
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
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
2001 (MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
---- ------------ ---------- ----------- ------------- ------------
Three Months Ended September 30:
Domestic 767 6.8 11.4 $23.94 $2.94
New Zealand 46 --- 0.3 $20.70 ---
------------ ---------- ----------- ------------- ------------
Total 813 6.8 11.7 $23.76 $2.94
2002
----
Three Months Ended September 30:
Domestic 687 4.0 8.1 $23.85 $3.06
New Zealand 221 2.8 4.1 $20.56 $1.28
------------ ---------- ----------- ------------- ------------
Total 908 6.8 12.2 $23.05 $2.32
In the table above, for the third 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 225 MBbls, at an average price of $13.58 per barrel.
Price-Risk Management. During the third quarter of 2002, we
recognized net losses of $181,595 relating to our derivative
activities, as compared to net gains of $1,631,187 in the 2001
period. In the third quarter of 2002, $162,727 of the losses were
unrealized, while $775,056 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 third quarter of 2002
increased $4.0 million, or 14% when compared to the same period in
2001. The majority of this increase, or $3.3 million, resulted from
the increased interest expense due to higher debt balances and
interest rates in the current period.
Our general and administrative expenses for the third quarter of
2002 increased $0.4 million, or 19%, 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 third
quarter of 2002. Such increases reflect additional costs needed to
run our increased activities in New Zealand.
Depreciation, depletion and amortization (DD&A) of our assets,
decreased approximately $1.4 million, or 9%, for the third quarter
of 2002. Domestically, DD&A decreased $4.6 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 and to higher reserve
volumes which were added primarily through our Lake Washington
activities. In New Zealand, DD&A increased by $3.2 million as
production and the depletable oil and gas property base both
increased in the 2002 period primarily due to the TAWN acquisition.
The May 2002 commissioning of our Rimu Processing Station also
increased the depletable oil and gas property base. Our overall DD&A
rate per Mcfe of production decreased to $1.10 per Mcfe in the third
quarter of 2002 from $1.27 per Mcfe in the same 2001 period.
Our production costs increased by $1.7 million, or 19%, due to
$2.4 million of production costs in our New Zealand operations that
were not present in the 2001 period, partially offset by domestic
production cost
22
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
decreases of $0.7 million due to decreased production in the 2002
period. These domestic cost decreases were partially offset by
increased workover and remedial well work which amounted to $1.1
million, or $0.09 per Mcfe in the 2002 period, while this cost
amounted to $0.5 million, or $0.04 per Mcfe in the 2001 period. Our
combined production cost per Mcfe increased by $0.11 per Mcfe, to
$0.90 in the third quarter of 2002, from $0.79 per Mcfe in the same
2001 period.
Interest expense on the credit facility, including commitment
fees and amortization of debt issuance costs, totaled $0.4 million
in the third quarter of 2002, compared to $1.7 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
third 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 $4.7 million in the third
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 third quarter of 2002
were $8.4 million, of which $1.8 million was capitalized, compared
to the 2001 total of $5.0 million, of which $1.6 million was
capitalized. The capitalized portion of interest is related to our
unproved properties.
Net Income. Our third quarter 2002 net income of $1.9 million was
74% lower than net income of $7.4 million in the third 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 $0.07 for the third quarter
of 2002 was 76% lower than Basic EPS of $0.30 in the 2001 period.
RESULTS OF OPERATIONS - Nine Months Ended September 30, 2002 and
2001
Revenues. Our revenues decreased 30% to $109.5 million during the
first nine months of 2002, as compared to revenues of $155.9 million
for the same period in 2001. This decrease was primarily from
reductions in our oil and gas sales that resulted from the 54%
decrease in domestic gas prices received and the 22% 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 areas.
Oil and Gas Sales. Our oil and gas sales decreased 34% to $101.5
million in the first nine months of 2002, compared to $153.2 million
for the comparable period in 2001. Our natural gas production
decreased 3%, while our oil production increased 35%, resulting in a
12%, or 3.9 Bcfe, increase in equivalent volumes produced compared
to production in the same period in 2001. Our average price on a
Mcfe basis, however, decreased 41% comparing the two periods. The
increase in production during the 2002 period is primarily from our
New Zealand and Lake Washington areas.
This $51.7 million decrease in oil and gas sales during the first
nine 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 $68.0
million, with $52.0 million of the decrease coming from the 54%
decrease in average gas prices received, and by a $16.0 million
decrease due to a 22% lower average oil price received; and
o Volume variances, which had a $16.3 million favorable impact on
sales, with $19.1 million of the increase coming from the 747 MBbl
increase in oil sales volumes, offset by a decrease of $2.8
million from the 0.6 Bcfe decrease in gas sales volumes.
23
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 nine month periods of 2002
and 2001. Natural gas accounted for 54% of total production volumes
during the first nine months of 2002 as compared to 62% in 2001.
Nine Months Ended September 30,
--------------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- ------------------------------ -----------------------------
2002 2001 2002 2001
---- ---- ---- ----
AWP Olmos $ 24.1 $ 48.9 8.4 10.0
Brookeland 9.2 22.0 3.1 4.9
Lake Washington 12.1 3.6 3.1 0.8
Masters Creek 25.5 51.9 8.0 11.2
Other 11.3 25.0 4.0 5.9
-------------- ------------- -------------- -------------
Total Domestic $ 82.2 $ 151.4 26.6 32.8
Rimu/Kauri 2.5 1.8 1.0 0.5
TAWN 16.8 --- 9.6 ---
-------------- ------------- -------------- -------------
Total New Zealand $ 19.3 $ 1.8 10.6 0.5
-------------- ------------- -------------- -------------
Total $ 101.5 $ 153.2 37.2 33.3
Our first nine months 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 28% 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
2001 (MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
---- ------------ ---------- ----------- ------------ -----------
Nine Months Ended September 30:
Domestic 2,025 20.6 32.8 $25.78 $4.81
New Zealand 82 --- 0.5 $21.73 ---
------------ ---------- ------------ ------------ -----------
Total 2,107 20.6 33.3 $25.62 $4.81
2002
----
Nine Months Ended September 30:
Domestic 2,368 12.4 26.6 $20.12 $2.78
New Zealand 486 7.6 10.6 $19.55 $1.29
------------ ---------- ----------- ------------ -----------
Total 2,854 20.0 37.2 $20.02 $2.21
In the table above, for the first nine months of 2002, natural
gas liquids have been combined with oil and condensate for reporting
purposes. The natural gas liquids production for the first nine
months of 2002 was 1,255 MBbls, at an average price of $11.77 per
barrel.
24
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
In March 2002, we received $7.5 million for our interest in the
Samburg project located in Western Siberia, Russia as a result of
the sale by a third party of its ownership in a Russian joint stock
company, which owned and operated this field. Although the proceeds
from sales of oil and gas properties are generally treated as a
reduction of oil and gas property costs, because we had previously
charged to expense all $10.8 million of cumulative costs relating to
our Russian activities, this cash payment, net of transaction
expenses, resulted in recognition of a $7.3 million non-recurring
gain on asset disposition in the first quarter of 2002. This
activity was recorded in Gain on Asset Disposition in the
accompanying statements of income.
Price-Risk Management. During the first nine months of 2002, we
recognized net losses of $201,474 relating to our derivative
activities, as compared to net gains of $1,924,931 in the 2001
period. In the first nine months of 2002, $162,727 of the losses
recognized were unrealized, while $775,056 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 nine months of
2002 increased $11.0 million, or 13% when compared to the same
period in 2001. The majority of this increase, or $7.4 million,
resulted from increased interest expense due to higher debt balances
and interest rates in the current period while the remainder
primarily came from increased production costs mostly from increases
in overall operating activity in New Zealand.
Our general and administrative expenses for the first nine months
of 2002 increased $1.4 million, or 23%, 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 nine
months of 2002. Such increases reflect additional costs needed to
run our increased activities in New Zealand.
Depreciation, depletion and amortization (DD&A) of our assets,
decreased approximately $1.2 million, or 3%, for the first nine
months of 2002. Domestically, DD&A decreased $8.6 million due to
decreased production in the 2002 period, 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 and to higher
reserve volumes which were added primarily through our Lake
Washington activities. In New Zealand, production and the depletable
oil and gas property base both increased in the 2002 period due
primarily to the TAWN acquisition. The May 2002 commissioning of our
Rimu Production Station also increased the depletable oil and gas
property base. Our overall DD&A rate per Mcfe of production
decreased to $1.12 per Mcfe in the first nine months of 2002 from
$1.29 per Mcfe in the same 2001 period.
Our production costs increased by $3.4 million, or 12%, due to
$5.2 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 $1.8 million due to decreased
production in the 2002 period. Our combined production cost per Mcfe
was $0.82 in both the first nine months of 2002 and 2001.
Interest expense on the credit facility, including commitment
fees and amortization of debt issuance costs, totaled $3.3 million
in the first nine months of 2002, compared to $4.1 million in the
same 2001 period. Proceeds from the senior notes and common stock
offering in the second quarter of 2002 were applied against the
credit facility, which reduced interest expense on the credit
facility in the 2002 period. Interest expense and discount on our
senior notes due 2009, including amortization of debt issuance
costs, was $9.9 million in the first nine months of 2002 and $9.8
million in the same 2001 period. Interest expense on our senior
notes due 2012, including amortization of debt issuance costs was
$8.7 million in the first nine months 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 nine months of 2002 were $21.9 million, of which $5.3
million was capitalized, compared to the 2001 total of $13.9
million, of which $4.7 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 nine months of 2002 of $8.6
million was 81% lower than net income of $44.7 million in the 2001 period.
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 $0.33 for the first nine months of 2002 was 82% lower
than Basic EPS of $1.81 in the 2001 period.
26
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Forward Looking Statements
The statements contained in this report that are not historical
facts are forward-looking statements as that term is defined in
Section 21E of the Securities and Exchange Act of 1934, as amended.
Such forward-looking statements may pertain to, among other things,
financial results, capital expenditures, drilling activity,
development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity,
regulatory matters and competition. Such forward-looking statements
generally are accompanied by words such as "plan," "future,"
"estimate," "expect," "budget," "predict," "anticipate,"
"projected," "should," "believe" or other words that convey the
uncertainty of future events or outcomes. Such forward-looking
information is based upon management's current plans, expectations,
estimates and assumptions, upon current market conditions, and upon
engineering and geologic information available at this time, and is
subject to change and to a number of risks and uncertainties, and
therefore, actual results may differ materially. Among the factors
that could cause actual results to differ materially are: volatility
in oil and gas prices; fluctuations of the prices received or demand
for our oil and natural gas; the uncertainty of drilling results and
reserve estimates; operating hazards; requirements for capital;
general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and
government regulations; as well as the risks and uncertainties
discussed herein, and set forth from time to time in our other
public reports, filings and public statements. Also, because of the
volatility in oil and gas prices and other factors, interim results
are not necessarily indicative of those for a full year.
27
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.
|X| Price Floors - At October 31, 2002, we had in place price
floors in effect through the December 2002 contract month.
The crude oil price floors cover notional volumes of 130,000
barrels of oil, with a floor price of $21 per barrel. The
natural gas price floors cover notional volumes of 300,000
Mmbtu, with a floor price of $3 per Mmbtu.
|X| Collars - At October 31, 2002, we had in place certain
"collar" financial transactions in effect through the
remainder of 2002 and the first quarter of 2003. The crude
oil collars cover notional volumes of 225,000 barrels of oil,
with floor prices ranging from $20.00 to $21.00 per barrel
and ceiling prices ranging from $27.52 to $32.50 per barrel,
plus 60% participation by the Company in prices realized
above the ceiling. The natural gas collars cover notional
volum