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, 2000
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 21,434,358 Shares
($.01 Par Value) (Outstanding at October 31, 2000)
(Class of Stock)
<PAGE>
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
INDEX
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION PAGE
<S> <C>
Item 1. Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets
- September 30, 2000 and December 31, 1999 3
Condensed Consolidated Statements of Income
- For the Three-month and Nine-month periods ended
September 30, 2000 and 1999 5
Condensed Consolidated Statements of Stockholders' Equity
- September 30, 2000 and December 31, 1999 6
Condensed Consolidated Statements of Cash Flows
- For the Nine-month periods ended September 30, 2000 and 1999 7
Notes to Condensed Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 14
Item 3. Quantitative and Qualitative Disclosures About Market Risk 21
PART II. OTHER INFORMATION
Item 1. Legal Proceedings None
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 22
SIGNATURES 23
</TABLE>
2
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, 2000 December 31, 1999
------------------ ------------------
(Unaudited)
ASSETS
<S> <C> <C>
Current Assets:
Cash and cash equivalents $ 32,312,754 $ 22,685,648
Accounts receivable -
Oil and gas sales 25,637,298 15,634,019
Associated limited partnerships
and joint ventures 7,225,890 5,359,596
Joint interest owners 4,831,631 5,550,048
Other current assets 1,350,714 1,376,177
------------------ ------------------
Total Current Assets 71,358,287 50,605,488
------------------ ------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 673,382,809 573,360,199
Unproved properties not being amortized 69,272,612 57,662,739
------------------ ------------------
742,655,421 631,022,938
Furniture, fixtures, and other equipment 8,462,918 7,778,571
------------------ ------------------
751,118,339 638,801,509
Less-Accumulated depreciation, depletion,
and amortization (277,545,091) (242,966,019)
------------------ ------------------
473,573,248 395,835,490
------------------ ------------------
Other Assets:
Receivables from associated limited
partnerships, net of current portion --- 628,228
Deferred charges 6,659,879 7,230,208
------------------ ------------------
6,659,879 7,858,436
------------------ ------------------
$ 551,591,414 $ 454,299,414
================== ==================
</TABLE>
See accompanying notes to condensed consolidated financial statements.
3
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, 2000 December 31, 1999
------------------ -----------------
(Unaudited)
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 41,493,669 $ 25,674,143
Payable to associated limited partnerships 14,717,076 609,967
Undistributed oil and gas revenues 11,207,348 7,785,975
------------------ -----------------
Total Current Liabilities 67,418,093 34,070,085
------------------ -----------------
Long-Term Debt 239,113,684 239,068,423
Deferred Revenues 53,139 576,658
Deferred Income Taxes 30,029,382 10,180,131
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000
shares authorized, none outstanding --- ---
Common stock, $.01 par value, 35,000,000 shares authorized,
22,269,670 and 21,683,185 shares issued, and 21,425,866
and 20,823,729 shares outstanding, respectively 222,697 216,832
Additional paid-in capital 195,800,066 191,092,851
Treasury stock held, at cost, 843,804 and 859,456
shares, respectively (12,101,199) (12,325,668)
Retained earnings (deficit) 31,055,552 (8,579,898)
------------------ -----------------
214,977,116 170,404,117
------------------ -----------------
$ 551,591,414 $ 454,299,414
================== =================
</TABLE>
See accompanying notes to condensed consolidated financial statements.
4
<PAGE>
SWIFT ENERGY COMPANY
Condensed Consolidated Statements of Income
(UNAUDITED)
<TABLE>
<CAPTION>
Three months ended Nine months ended
---------------------------------- ---------------------------------
09/30/00 09/30/99 09/30/00 09/30/99
--------------- -------------- -------------- ---------------
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 48,716,637 $ 30,737,150 $ 131,403,301 $ 75,405,571
Fees from limited partnerships
and joint ventures 138,487 92,737 257,653 192,386
Interest income 445,396 243,998 1,084,038 267,280
Other, net 224,646 205,410 655,194 830,879
--------------- -------------- -------------- ---------------
49,525,166 31,279,295 133,400,186 76,696,116
--------------- -------------- -------------- ---------------
Costs and Expenses:
General and administrative, net 1,649,354 1,053,655 4,256,879 3,347,941
Depreciation, depletion and
amortization 11,589,279 10,403,262 34,610,907 31,630,013
Oil and gas production 7,568,686 5,138,138 20,600,827 13,689,086
Interest expense, net 3,969,684 3,749,414 12,046,008 10,402,426
--------------- -------------- -------------- ---------------
24,777,003 20,344,469 71,514,621 59,069,466
--------------- -------------- -------------- ---------------
Income before Income Taxes 24,748,163 10,934,826 61,885,565 17,626,650
Provision for Income Taxes 8,915,815 3,827,189 22,250,115 6,085,231
--------------- -------------- -------------- ---------------
Net Income $ 15,832,348 $ 7,107,637 $ 39,635,450 $ 11,541,419
=============== ============== ============== ===============
Per share amounts -
Basic: $ 0.74 $ 0.37 $ 1.88 $ 0.67
=============== ============== ============== ===============
Diluted: $ 0.66 $ 0.36 $ 1.71 $ 0.67
=============== ============== ============== ===============
Weighted Average Shares Outstanding 21,347,883 19,069,848 21,068,015 17,125,937
=============== ============== ============== ===============
</TABLE>
See accompanying notes to condensed consolidated financial statements.
5
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Additional
Common Paid-In Treasury Retained
Stock(1) Capital Stock Earnings Total
--------------- ----------------- --------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1998 $ 169,725 $ 148,901,270 $ (11,841,884) $ (27,866,472) $ 109,362,639
Stock issued for benefit plans
(90,738 shares) 224 (366,408) 978,956 --- 612,772
Stock options exercised
(65,477 shares) 655 461,102 --- --- 461,757
Employee stock purchase plan
(22,771 shares) 228 181,577 --- --- 181,805
Public stock offering
(4,600,000 shares) 46,000 41,915,310 --- --- 41,961,310
Purchase of 246,500 shares as
treasury stock --- --- (1,462,740) --- (1,462,740)
Net income --- --- --- 19,286,574 19,286,574
--------------- ----------------- --------------- --------------- --------------
Balance, December 31, 1999 $ 216,832 $ 191,092,851 $ (12,325,668) $ (8,579,898) $ 170,404,117
=============== ================= =============== =============== ==============
Stock issued for benefit plans
(46,632 shares)(2) 310 297,060 224,469 --- 521,839
Stock options exercised
(525,616 shares)(2) 5,256 4,112,741 --- --- 4,117,997
Employee stock purchase plan
(29,889 shares)(2) 299 297,414 --- --- 297,713
Net income (2) --- --- --- 39,635,450 39,635,450
--------------- ----------------- --------------- --------------- ---------------
Balance, September 30, 2000 (2) $ 222,697 $ 195,800,066 $ (12,101,199) $ 31,055,552 $ 214,977,116
=============== ================= =============== =============== ===============
(1) $.01 Par Value
(2) Unaudited
</TABLE>
See accompanying notes to condensed consolidated financial statements.
6
<PAGE>
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Period Ended September 30,
----------------------------------------------
2000 1999
-------------------- ---------------------
<S> <C> <C>
Cash Flows From Operating Activities:
Net income $ 39,635,450 $ 11,541,419
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization 34,610,907 31,630,013
Deferred income taxes 21,679,373 5,787,938
Deferred revenue amortization related to production payment (543,876) (806,950)
Other 615,590 422,196
Change in assets and liabilities -
Increase in accounts receivable (8,411,707) (3,245,871)
Increase in accounts payable and accrued
liabilities, excluding income taxes payable 249,650 2,930,390
Increase in income taxes payable --- 304,628
-------------------- ---------------------
Net Cash Provided by Operating Activities 87,835,387 48,563,763
-------------------- ---------------------
Cash Flows From Investing Activities:
Additions to property and equipment (102,121,338) (34,907,498)
Proceeds from the sale of property and equipment 3,378,234 3,914,578
Net cash received as operator of oil and gas properties 19,485,168 4,177,050
Net cash received (distributed) as operator of partnerships
and joint ventures (1,866,294) 4,261,642
Limited partnership formation and marketing costs --- (855,632)
Other (11,478) (326,799)
-------------------- ---------------------
Net Cash Used in Investing Activities (81,135,708) (23,736,659)
-------------------- ---------------------
Cash Flows From Financing Activities:
Proceeds from senior subordinated notes --- 124,054,369
Net payments of bank borrowings --- (146,200,000)
Net proceeds from issuances of common stock 2,927,427 42,794,224
Purchase of treasury stock --- (1,462,740)
Payments of debt issuance costs --- (3,501,441)
-------------------- ---------------------
Net Cash Provided by Financing Activities 2,927,427 15,684,412
-------------------- ---------------------
Net Increase in Cash and Cash Equivalents 9,627,106 40,511,516
Cash and Cash Equivalents at Beginning of Period 22,685,648 1,630,649
-------------------- ---------------------
Cash and Cash Equivalents at End of Period $ 32,312,754 $ 42,142,165
==================== =====================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts capitalized $ 12,729,897 $ 6,180,930
Cash paid during period for income taxes $ --- $ ---
</TABLE>
See accompanying notes to condensed consolidated financial statements.
7
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999
(1) GENERAL INFORMATION
The condensed consolidated financial statements included herein have
been prepared by Swift Energy Company and are unaudited, except for the
balance sheet at December 31, 1999, 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 condensed
consolidated financial statements should be read in conjunction with the
audited financial statements and the notes thereto included in the latest
Form 10-K and Annual Report.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 acquisition, exploration, and
development 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. General and administrative costs related to production and
general overhead are expensed as incurred.
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 current period-end prices, discounted to present value at 10% per
annum, 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. Currently, we have proved reserves in the United States only.
No gains or losses are recognized upon the sale or disposition of oil
and gas properties, except in transactions that involve 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. Fees
from associated oil and gas exploration and development limited
partnerships are credited to oil and gas property costs to the extent they
do not represent reimbursement of general and administrative expenses
currently charged to expense.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property
basis, based on current economic conditions, and are amortized to expense
as our capitalized oil and gas property costs are amortized. Our
properties are all onshore, and historically the salvage value of the
tangible equipment offsets our site restoration and dismantlement and
abandonment costs, which we expect to continue in the future.
8
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
We compute the provision for depreciation, depletion, and amortization
of oil and gas properties on 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, 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 for those countries with oil and gas
production.
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. Any impairment assessed is added to the
cost of proved properties being amortized and is therefore subject to the
Ceiling Test. To the extent costs accumulated in countries that do not
have proved reserves, any impairment is charged to income. In determining
whether such costs should be impaired, our management evaluates, among
other factors, the results of drilling, current oil and gas industry
conditions, 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.
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.
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. Such estimates are based
on management's best information at the time and accordingly, actual
results in the subsequent reporting period could differ from estimates.
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.
The calculation of diluted earnings per share ("Diluted EPS") assumes
conversion of our convertible notes as of the beginning of the respective
periods and the elimination of the related after-tax interest expense and
assumes, as of the beginning of the period, exercise of stock options and
warrants using the treasury stock method. The assumed conversion of our
convertible notes has been excluded from the calculation of Diluted EPS
for the nine-month 1999 period as they would have been antidilutive for
that period. The following is a reconciliation of the calculation of Basic
and Diluted EPS for the three-month and nine-month periods ended September
30, 2000 and 1999:
9
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
<TABLE>
<CAPTION>
Three Months Ended September 30,
------------------------------------------------------------------------------------
2000 1999
--------------------------------------- -----------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
----------- ----------- ------------ ------------ ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income and
Share Amounts $ 15,832,348 21,347,883 $ .74 $ 7,107,637 19,069,848 $ .37
Dilutive Securities:
6.25% Convertible Notes 1,214,904 3,646,847 1,230,527 3,646,847
Stock Options --- 817,361 --- 222,286
------------ ----------- ------------ -----------
Diluted EPS:
Net Income and
Assumed Share
Conversions $ 17,047,252 25,812,091 $ .66 $ 8,338,164 22,938,981 $ .36
------------ ----------- ------------ -----------
Nine Months Ended September 30,
------------------------------------------------------------------------------------
2000 1999
--------------------------------------- -----------------------------------------
Net Per Share Net Per Share
Income Shares Amount Income Shares Amount
------------ ----------- ------------ ------------ ----------- -------------
Basic EPS:
Net Income and
Share Amounts $ 39,635,450 21,068,015 $ 1.88 $ 11,541,419 17,125,937 $ .67
Dilutive Securities:
6.25% Convertible Notes 3,646,962 3,646,847 --- ---
Stock Options --- 648,323 --- 222,286
------------ ----------- ------------ -----------
Diluted EPS:
Net Income and
Assumed Share
Conversions $ 43,282,412 25,363,185 $ 1.71 $ 11,541,419 17,348,223 $ .67
------------ ----------- ------------ -----------
</TABLE>
New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." The
Statement establishes accounting and reporting standards requiring that
every derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either an
asset or 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 allows the gains and losses on derivatives to offset
related results on the hedged item in the income statements and requires
that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. SFAS No. 133,
as amended by SFAS No. 137 "Accounting for Derivative Instruments and
Hedging Activities - Deferral of the Effective Date of FASB Statement No.
133" and as amended by SFAS No. 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities - an Amendment of FASB
Statement No. 133"," is effective for fiscal years beginning after June
15, 2000.
We have a policy to use derivative instruments, mainly the buying of
protection price floors, to protect against price declines in oil and gas
prices. We currently believe that such derivatives would qualify for hedge
10
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
accounting under SFAS No.133. At September 30, 2000, our derivative
contracts accounted for as hedges will expire on or before December 31,
2000. Accordingly, we currently do not expect the initial adoption of SFAS
No. 133 to have a material effect on our results of operations. However,
we may enter into derivative contracts in the future, primarily purchased
options serving as protection price floors, to mitigate our exposure to
commodity prices, which may result in increased earnings volatility under
SFAS No. 133.
LONG-TERM DEBT
Our long-term debt as of September 30, 2000 and December 31, 1999, is
as follows (in thousands):
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------------ ---------------------
<S> <C> <C>
Bank Borrowings $ --- $ ---
Convertible Notes 115,000 115,000
Senior Notes 124,114 124,068
------------------ ---------------------
Long-Term debt $ 239,114 $ 239,068
------------------ ---------------------
</TABLE>
Under our restated $250.0 million revolving credit facility with a
syndicate of nine banks, at September 30, 2000 and at December 31, 1999 we
had no outstanding borrowings, as previous borrowings were paid in full
during August 1999 with proceeds from our third quarter concurrent public
offerings of senior subordinated notes and common stock. At September 30,
2000, the credit facility consisted of a $250.0 million secured revolving
line of credit with a $100 million borrowing base. The interest rate is
either (a) the lead bank's prime rate (9.5% at September 30, 2000) 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 our outstanding balance on the credit facility to
the last calculated borrowing base.
The terms of the credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $2.0 million in
any fiscal year), 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 borrowing base is
redetermined at least every six months and is currently under its November
review which had not been completed as of the date of this report. By its
terms, the credit facility extends until August 2002.
Our Convertible Notes at September 30, 2000, consist of $115,000,000 of
6.25% Convertible Subordinated Notes due 2006. The Convertible Notes were
issued on November 25, 1996, and will mature on November 15, 2006. The
Convertible Notes are unsecured and convertible into common stock of Swift
at the option of the holders at any time prior to maturity at an adjusted
conversion price of $31.534 per share, subject to adjustment upon the
occurrence of certain events. The original conversion price of $34.6875
was adjusted downward to reflect the 10% stock dividend in October 1997.
Interest on the notes is payable semiannually on May 15 and November 15.
The Convertible Notes are redeemable for cash at the option of Swift, with
certain restrictions, at 103.75% of principal commencing November 16, 2000
and for a year thereafter, then declining ratably each year to 100.625% in
2005. Upon certain changes in control of Swift, if the price of our common
stock is not above certain levels, each holder of Convertible Notes will
have the right to require us to repurchase the Convertible Notes at 101%
of the principal amount thereof, together with accrued and unpaid interest
to the date of repurchase, but after the repayment of any Senior
Indebtedness, as defined.
11
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
Our Senior Notes at September 30, 2000, 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, and commenced with the
first payment on February 1, 2000. 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. In
addition, prior to August 1, 2002, we may redeem up to 33.33% of the
Senior Notes with the proceeds of qualified offerings of our equity at
110.25% 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.
(3) STOCKHOLDERS' EQUITY
In August of 1999, we sold 4.6 million shares of common stock in a
public offering for $9.75 per share, with net proceeds of approximately
$42.1 million.
(4) FOREIGN ACTIVITIES
New Zealand. We own a petroleum exploration permit in New Zealand. The
first permit covered approximately 65,000 acres in the Onshore Taranaki
Basin of New Zealand's North Island, and the second covered approximately
69,300 adjacent acres. In March 1998, we surrendered approximately 46,400
acres covered by the first permit, and the remaining acreage has been
included as an extension of the area covered in the second permit, leaving
us with only one expanded permit. On October 18, 1999, this expanded
permit was again extended to include approximately 12,800 adjacent
offshore acres. This permit now contains approximately 100,700 acres.
In late 1999, our first exploratory well on this permit, the Rimu-A1
was completed, and a ten-day production draw-down/build-up test was
performed. Our portion of the drilling, completion, and testing costs
incurred on the Rimu-A1 through September 30, 2000 was approximately $7.0
million. We are performing additional seismic acquisition and analysis on
the permit area and are analyzing further delineation activities on the
Rimu block.
We commenced drilling the first delineation well, the Rimu-B1, on July
18, 2000. In mid-October 2000, we completed the preliminary testing phase
which exclusively tested the Lower Tariki sandstone and produced at daily
equivalent rates up to 1,086 barrels of oil and 1,432 thousand cubic feet
of natural gas. However, due to either formation damage incurred while
drilling or lower than expected permeability, the production declined over
the 108 hour test period. We are considering a stimulation treatment of
the Lower Tariki sandstone, a sidetrack of the well in order to achieve a
more advantageous geological position in both the Upper and Lower Tariki
sandstones, and/or testing other potential intervals in the well bore.
Future activities will be determined subsequent to drilling and evaluation
of the next delineation well, the Rimu-B2 well which commenced drilling
October 24, 2000. The drilling of the first Kauri Prospect well is
scheduled to begin, if consenting permits, upon the completion of drilling
of the Rimu-B2 well or the Rimu-A2. Our portion of the drilling,
completion, and testing costs incurred through September 30, 2000 on
Rimu-B1 was approximately $4.6 million.
12
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000 (UNAUDITED) AND DECEMBER 31, 1999-CONTINUED
Additionally, we have entered into agreements with Fletcher Challenge
Energy Limited whereby we will earn a 20% participating interest in permit
38718 containing approximately 57,400 acres and a 25% participating
interest in permit 38730 with approximately 48,900 acres. The operator
commenced drilling the Tuihu Prospect well on October 28, 2000 on permit
38718 which should take from 45 to 60 days to complete.
As of September 30, 2000, our investment in New Zealand totaled
approximately $22.2 million comprised of drilling costs, seismic costs,
and other such prospect generation costs. Approximately $0.7 million of
such costs have been impaired, while the remaining $21.5 million is
included in the unproved properties portion of oil and gas properties. All
other obligations under the permit have been fulfilled.
We expect that at year-end we will record some level of reserves on
our New Zealand activities based on the wells that have been drilled and
the wells currently drilling. Recording of reserves will result in the
reclassification of a portion of the costs associated with those booked
reserves from the unproved properties portion of our oil and gas
properties to the proved properties portion of our oil and gas properties.
We are currently in discussions with New Zealand purchasers of oil and
gas, with the intent of having marketing arrangements in place, and
production on line for oil and gas sales in New Zealand on or around July
1, 2001.
13
<PAGE>
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, as we did in the third quarter of 1998 with
the purchase of the Masters Creek and Brookeland Areas from Sonat
Exploration Company. In 1997, 1998, and 1999, we used this flexible
strategy of employing both drilling and acquisitions to add more reserves
than we depleted through production. Oil and gas sales attributable to
properties in which we own a direct or indirect interest comprise
virtually all of our revenues.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 2000, we principally relied upon our
internally generated cash flows of $87.8 million to fund capital
expenditures of $102.1 million. We expect that internally generated cash
flows, cash on hand of $32.3 million at September 30, 2000, and a limited
amount of bank debt if needed, will provide all necessary funds for
capital costs and working capital for the remainder of 2000. We believe
that these same sources will also provide adequate funds for currently
planned capital expenditures and working capital needs in 2001.
During 1999, we primarily relied upon internally generated cash flows
of $73.6 million to fund capital expenditures of $78.1 million. Capital
expenditures were also partially funded with the remaining proceeds, after
repayment of our bank borrowings, from our public sale of senior notes and
common stock in August 1999.
Net Cash Provided by Operating Activities. For the first nine months of
2000, net cash provided by our operating activities increased by 81% to
$87.8 million, as compared to $48.6 million during the first nine months a
year earlier. The increase of $39.2 million was primarily due to $56.0
million of additional oil and gas sales during the 2000 period due to
commodity prices. However, this increase was partially offset by a $6.9
million increase in oil and gas production costs and a $1.6 million
increase in interest expense.
Financing Activities. In August 1999, in two concurrent public
offerings, we sold $125.0 million of 10.25% Senior Subordinated Notes and
4.6 million shares of common stock for $44.9 million. The notes were
issued at 99.236% of the principal amount and will mature on August 1,
2009. Proceeds from the two offerings were used to repay our bank
borrowings of $136.0 million. The remaining proceeds were used, together
with internally generated cash flows, to fund capital expenditures and
working capital needs. The principal terms of these notes are more fully
described in Note 3 to our condensed consolidated financial statements.
Credit Facility. At September 30, 2000 and at December 31, 1999, we had
no outstanding borrowings under our credit facility. At September 30,
2000, our credit facility was a $250.0 million revolving line of credit
with a $100.0 million borrowing base. Effective October 24, 2000, our
borrowing base was increased to $150.0 million. 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.
14
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Debt Maturities. The credit facility extends until August 18, 2002. Our
$115.0 million convertible notes mature November 15, 2006. Our $125.0
million senior notes mature August 1, 2009.
Working Capital. Our working capital decreased from $16.5 million at
December 31, 1999, to $3.9 million at September 30, 2000, primarily due to
our capital expenditures exceeding our internally generated cash flows.
Common Stock Repurchase Program. In March 1997, we commenced a common
stock repurchase program that terminated pursuant to its terms as of June
30, 1999. We spent $13.3 million to acquire 927,774 shares at an average
cost of $14.34 per share. In March 1999, we used 68,318 shares of common
stock held as treasury stock to fund our employer contribution in the
401(k) program for our employees. In May 2000, we contributed 15,652
shares of common stock held as treasury stock to our Employee Stock
Ownership Plan.
Capital Expenditures. During the first nine months of 2000, we used
$102.1 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
o $66.6 million for drilling costs, both development and exploratory;
o $13.0 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects;
o $17.1 million of producing property acquisitions, mainly
additional interests in the AWP Olmos Area purchased from
partnerships managed by us;
o $4.0 million invested in New Zealand;
o $0.7 million on property, plant and equipment; and
o $0.7 million spent primarily for computer equipment, software and
furniture and fixtures.
In the remaining three months of 2000, we expect to make capital
expenditures of approximately $50.0 to $60.0 million, including
investments in all areas in which they were made during the first nine
months of the year as described above. These amounts include approximately
$17.0 million for property acquisitions in the Texas Gulf Coast area from
a third party already underway in the fourth quarter, including both
onshore properties and smaller offshore interests.
We drilled or participated in the drilling of 52 wells in the first
nine months of 2000, and 44 were successful. Development wells had a
success rate of 41 out of 46, while three out of six exploratory wells
drilled were successful. For the remaining three months of 2000 we
anticipate drilling or participating in the drilling of an additional 21
wells, made up of 16 domestic development wells and two domestic
exploratory wells, one exploratory New Zealand well on the Tuihu Prospect,
and two New Zealand delineation wells, the first of which was the recently
completed Rimu B-1 well and the other the Rimu B-2 well that recently
commenced drilling. We estimate capital expenditures for 2000 to be
approximately $150.0 to $160.0 million, an increase from 1999 capital
expenditures of $78.0 million. This upward adjustment in the 2000 capital
expenditures budget is in response to increased cash
15
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
flows resulting from the improvement in commodity prices. We believe that
2000's anticipated internally generated cash flows, together with cash on
hand, and limited bank borrowings if needed will be sufficient to finance
the costs associated with our currently budgeted remaining 2000 capital
expenditures.
RESULTS OF OPERATIONS - Three Months Ended September 30, 2000 and 1999
Revenues. Our revenues increased 58% during the third quarter of 2000
as compared to the same period in 1999. This increase was caused by growth
in our oil and gas sales which resulted from the 66% increase in oil
prices received and the 54% increase in gas prices received.
Oil and Gas Sales. Our oil and gas sales increased 58% to $48.7 million
in the third quarter of 2000, compared to $30.7 million for the comparable
period in 1999. Our natural gas production increased 2% while our oil
production decreased 3% resulting in a slight increase in equivalent
volumes produced compared to production in the same period in 1999.
Our $18.0 million increase in oil and gas sales during the third
quarter of 2000 resulted from:
o Price increases which solely attributed to the favorable increase
in sales of $18.0 million, with $7.2 million of the increase coming
from the increase in average oil prices received and $10.8 million
coming from the increase in average gas prices received; and
o Volume increases which had no impact on sales, with $0.4 million of
an increase coming from the 0.1 Bcf increase in gas sales volumes
and $0.4 million of a decrease coming from the 20,789 barrel
decrease in oil sales volumes.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes from our four
core areas in the third quarter periods of 2000 and 1999.
<TABLE>
<CAPTION>
Three Months Ended September 30,
-------------------------------------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- ---------------------- ------------------------
<S> <C> <C> <C> <C>
2000 1999 2000 1999
---- ---- ---- ----
AWP Olmos $15.7 $ 8.8 3.6 3.2
Brookeland $ 4.8 $ 3.2 1.1 1.0
Giddings $ 3.4 $ 2.5 0.7 0.9
Masters Creek $22.9 $14.3 4.6 4.4
</TABLE>
16
<PAGE>
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:
<TABLE>
<CAPTION>
Net Sales Volume Average Sales Price
---------------- -------------------
Oil (Bbl) Gas (Mcf) Combined (Mcfe) Oil (Bbl) Gas (Mcf)
----------- ------------ ----------------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
1999
----
Three Months Ended
September 30, 611,948 6,838,924 10,510,612 $18.46 $2.84
2000
----
Three Months Ended
September 30, 591,159 6,970,980 10,517,934 $30.68 $4.39
</TABLE>
Costs and Expenses. Our general and administrative expenses for the
third quarter of 2000 increased $596,000, or 56%, when compared to the
same period in 1999. Our general and administrative expenses per Mcfe
produced also increased to $0.16 per Mcfe from $0.10 per Mcfe for the
comparable period in 1999. Such increases are reflective of additional
staffing costs as our activities increased, and retirement related costs
that were specific to this quarter. Supervision fees netted from general
and administrative expenses were $0.9 million and $0.8 million for the
three-month periods ended September 30, 2000 and 1999, respectively.
Depreciation, depletion and amortization of our assets, or DD&A,
increased approximately $1.2 million, or 11%, for the third quarter of
2000. This was primarily due to additions to our reserves and associated
costs and to the slight increase in production volumes. Our DD&A rate per
Mcfe of production increased to $1.10 per Mcfe in the third quarter of
2000 from $0.99 per Mcfe in the same 1999 period.
Our production costs increased by $2.4 million to $0.72 per Mcfe in the
third quarter of 2000 from $0.49 per Mcfe in the same 1999 period. Of the
$2.4 million increase, $1.4 million related to the increase in severance
and ad valorem taxes, which are commodity price sensitive. Severance taxes
increased primarily from the higher commodity prices received, from the
expiration of certain specific well severance tax exemptions, and from the
slight increase in production volumes. The remainder of the $2.4 million
increase reflects costs associated with new wells, as well as increased
activities related to production enhancements during periods of high
commodity prices and the related increase in costs in procuring such
services in an environment where demand for such services is increasing.
Supervision fees netted from production costs were $0.9 million and $0.8
million for the three-month periods ended September 30, 2000 and 1999,
respectively.
Interest expense on our convertible notes due 2006, including
amortization of debt issuance costs, was the same in the third quarter of
2000 and 1999, totaling $1.9 million. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance
costs, totaled $0.1 million in the third quarter of 2000, compared to $1.1
million in the same 1999 period. Interest expense and discount on our
senior notes due 2009, including amortization of debt issuance costs,
totaled $3.3 million in the third quarter of 2000, compared to $2.0
million in the same 1999 period. Thus, total interest charges for the
third quarter of 2000 were $5.3 million, of which $1.3 million was
capitalized, compared to the 1999 total of $5.0 million, of which $1.2
million was capitalized. The increase in interest expense in 2000 is
attributable to the higher interest rate on our new senior notes. The
capitalized portion of interest is related to our exploration and foreign
business development activities.
17
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Net Income. Our net income for the third quarter of 2000 of $15.8
million and Basic EPS of $0.74 were 123% and 100% higher than net income
of $7.1 million and Basic EPS of $0.37 in the third quarter of 1999. These
increases primarily reflected the effect of the increased oil and gas
prices received in the 2000 period, as discussed above. The lower
percentage increase in Basic EPS, as compared to net income, resulted from
the public sale of 4.6 million shares of common stock in the third quarter
of 1999.
RESULTS OF OPERATIONS - Nine Months Ended September 30, 2000 and 1999
Revenues. Our revenues increased 74% during the first nine months of
2000 as compared to the same period in 1999. This increase was caused by
growth in our oil and gas sales which resulted from the 94% increase in
oil prices received and the 69% increase in gas prices received.
Oil and Gas Sales. Our oil and gas sales increased 74% to $131.4
million in the first nine months of 2000, compared to $75.4 million for
the comparable period in 1999. Our natural gas production decreased 1% and
oil production decreased 5% resulting in a 2%, or 0.8 Bcfe, decrease in
volumes produced compared to production in the same period in 1999. Our
second and third quarter 2000 production volumes increased when compared
to the same prior year periods, however, our first quarter 2000 production
volumes were 1.1 Bcfe less than the first quarter 1999 production volumes,
resulting in the year to date decrease of 0.8 Bcfe. These volume decreases
were more than offset by increased prices received. The decrease in
production volumes in the first quarter comparisons resulted primarily
from our decision to reduce development drilling during 1999 due to low
oil and gas prices at the time. With drilling curtailed in 1999, not
enough new production was placed online to offset the normal production
decline in the Giddings area, as can be seen in the table below. Also,
property sales relating to the ongoing liquidation of partnerships we
manage reduced our share of production volumes in areas outside of our
four core areas. With increased levels of drilling in late 1999 and in
2000, we have begun to turn this production trend around, as second and
third quarter 2000 production exceeded second and third quarter 1999
production. However, tightness in supplies of drilling and other services
have hampered our ability to increase production at a pace as fast as we
would have liked. We currently expect that production for the fourth
quarter of 2000 will range from 10.5 Mcfe to 11.0 Mcfe.
Our $56.0 million increase in oil and gas sales during the first nine
months of 2000 resulted from:
o Price increases which had a favorable impact on sales of $57.9
million, with $26.2 million of the increase coming from the
increase in average oil prices received and $31.7 million coming
from the increase in average gas prices received; offset by
o Volume decreases which had an unfavorable impact on sales of $1.9
million, with $0.6 million of the decrease coming from the 0.3 Bcf
decrease in gas sales volumes and $1.3 million of the decrease
coming from the 90,280 barrel decrease in oil sales volumes.
18
<PAGE>
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 four
core areas in the first nine-month periods of 2000 and 1999.
<TABLE>
<CAPTION>
Nine Months Ended September 30,
-------------------------------
Area Revenues (In Millions) Net Sales Volumes (Bcfe)
---- ----------------------- ------------------------
2000 1999 2000 1999
---- ---- ---- ----
<S> <C> <C> <C> <C>
AWP Olmos $37.4 $22.7 10.1 10.1
Brookeland $13.5 $ 7.9 3.2 3.1
Giddings $ 8.8 $ 6.1 2.3 2.9
Masters Creek $66.9 $34.8 14.8 14.3
</TABLE>
The following table provides additional information regarding our oil
and gas sales:
<TABLE>
<CAPTION>
Net Sales Volume Average Sales Price
---------------- -------------------
Oil (Bbl) Gas (Mcf) Combined (Mcfe) Oil (Bbl) Gas (Mcf)
----------- ------------- ------------------ ---------- ------------
<S> <C> <C> <C> <C> <C>
1999
----
Nine Months Ended
September 30, 1,984,081 20,751,428 32,655,914 $14.64 $2.23
2000
----
Nine Months Ended
September 30, 1,893,801 20,484,298 31,847,104 $28.46 $3.78
</TABLE>
Costs and Expenses. Our general and administrative expenses for the
first nine months of 2000 increased $909,000, or 27%, when compared to the
same period in 1999. Our general and administrative expenses per Mcfe
produced also increased to $0.13 per Mcfe from $0.10 per Mcfe for the
comparable period in 1999. Such increases are reflective of increases in
our activities as discussed above in the comparison of third quarter
results. Supervision fees netted from general and administrative expenses
were $2.6 million for the current year period and $2.4 million for the
1999 period.
DD&A increased approximately $3.0 million, or 9%, for the first nine
months of 2000. This was primarily due to additions to our reserves and
associated costs and to the related 2% decrease in production volumes. Our
DD&A rate per Mcfe of production increased to $1.09 per Mcfe in the first
nine months of 2000 from $0.97 per Mcfe in the same 1999 period.
Our production costs per Mcfe increased by $6.9 million or $0.65 per
Mcfe in the first nine months of 2000 from $0.42 per Mcfe in the same 1999
period. Of the $6.9 million increase, $3.9 million related to the increase
in severance and ad valorem taxes which are
19
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
commodity price sensitive. Severance taxes increased primarily from the
higher commodity prices received and from the expiration of certain
specific well severance tax exemptions. The remainder of the $6.9 million
increase reflects increased activities discussed above in the comparison
of third quarter results. Supervision fees netted from production costs
for the first nine months of 2000 were $2.6 million and for the same
period of 1999 were $2.4 million.
Interest expense on our convertible notes due 2006, including
amortization of debt issuance costs, was the same in the first nine months
of 2000 and 1999, totaling $5.7 million. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance
costs, totaled $0.4 million in the first nine months of 2000, compared to
$6.0 million in the same 1999 period. Interest expense and discount on our
senior notes due 2009, including amortization of debt issuance costs,
totaled $9.8 million in the first nine months of 2000, compared to $2.0
million in the same 1999 period. Thus, total interest charges for the
first nine months of 2000 were $15.9 million, of which $3.9 million was
capitalized, compared to the 1999 total of $13.7 million, of which $3.3
million was capitalized. The increase in interest expense in 2000 is
attributable to the higher interest rate on our new senior notes. The
capitalized portion of interest is related to our exploration and foreign
business development activities.
Net Income. Our net income for the first nine months of 2000 of $39.6
million and Basic EPS of $1.88 were 243% and 181% higher than net income
of $11.5 million and Basic EPS of $0.67 in the first nine months of 1999.
This increase primarily reflected the effect of increased oil and gas
prices received in the 2000 period, as discussed above. The lower
percentage increase in Basic EPS, as compared to net income, resulted from
the public sale of 4.6 million shares of common stock in the third quarter
of 1999.
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, and lately availability of services
and supplies; 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.
20
<PAGE>
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Risk
Our revenues are primarily the result of sales of our oil and natural
gas production. Market prices of oil and natural gas may fluctuate and
adversely affect operating results. To mitigate some of this risk, we do
engage periodically in certain limited hedging activities, which includes
buying protection price floors and entering into participating collars for
portions of our and our managed limited partnerships' oil and natural gas
production. These derivative financial instruments are placed with major
financial institutions that we believe present minimum credit risk. Costs
and any benefits derived from the price floors are recorded as a reduction
or increase, as applicable, in oil and gas sales revenue. The costs to
purchase the price floors are amortized over the option period. The
participating collars are designated as hedges and realized gains or
losses are recognized in oil and gas revenues when the associated
production occurs.
The costs related to 2000 hedging activities through September 30, 2000
on both the price floors and the participating collars totaled $1,007,234,
or $0.032 per Mcfe produced.
The costs relating to 2000 hedging activities through September 30,
2000 on the price floors totaled $397,614 with no benefits having been
received, resulting in a net cash outflow of $397,614, or $0.013 per Mcfe
produced. At September 30, 2000, participating collars covering the first
six months of 2000 had closed with our recording a loss of $609,620, or
$0.019 per Mcfe produced.
The costs related to open price floor contracts as of September 30,
2000 totaled $310,500, which is our maximum exposure under these
contracts. These open contracts had a fair market value of $6,000 at
September 30, 2000. These contracts expire on or before December 31, 2000.
There are no open participating collars at this time.
21
<PAGE>
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings - N/A
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 - N/A
Item 5. Other Information - N/A
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
(b) Reports on Form 8-K filed during the quarter ended
September 30, 2000 - None
22
<PAGE>
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: November 13, 2000 By: (Original Signed By)
-------------------------- -------------------------
Alton D. Heckaman, Jr.
Senior Vice President,
Chief Financial Officer, Controller
and Principal Accounting Officer
23
<PAGE>
Exhibit 12
24
<PAGE>
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------------------------
2000 1999
----------------- ----------------
<S> <C> <C>
GROSS G&A 17,522,334 15,406,200
NET G&A 4,256,879 3,347,941
INTEREST EXPENSE 12,046,008 10,402,426
RENT EXPENSE 941,715 970,876
NET INCOME BEFORE TAXES 61,885,565 17,626,650
CAPITALIZED INTEREST 3,721,259 2,993,868
DEPLETED CAPITALIZED INTEREST 252,382 261,363
CALCULATED DATA
--------------------------------------
UNALLOCATED G&A (%) 24.29% 21.73%
NON-CAPITAL RENT EXPENSE 228,780 210,982
1/3 NON-CAPITAL RENT EXPENSE 76,260 70,327
FIXED CHARGES 15,843,527 13,466,621
EARNINGS 74,260,216 28,360,767
RATIO OF EARNINGS TO FIXED CHARGES 4.69 2.11
================= =================
</TABLE>
For purposes of calculating the ratio of earnings to fixed charges,
fixed charges include interest expense, capitalized interest, amortization
of debt issuance costs and discounts, and that portion of non-capitalized
rental expense deemed to be the equivalent of interest. Earnings represent
income before income taxes from continuing operations before fixed
charges.
25
