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, 1999
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 21,681,581 Shares
($.01 Par Value) (Outstanding at October 31, 1999)
(Class of Stock)
<PAGE>
SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999
INDEX
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION PAGE
<S> <C>
Item 1. Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets
- September 30, 1999 and December 31, 1998 3
Condensed Consolidated Statements of Income
- For the Three-month and Nine-month periods ended
September 30, 1999 and 1998 5
Condensed Consolidated Statements of Stockholders' Equity
- September 30, 1999 and December 31, 1998 6
Condensed Consolidated Statements of Cash Flows
- For the Nine-month periods ended September 30, 1999 and 1998 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. None
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 22
Item 2. Changes in Securities and Use of Proceeds 22
Item 3. Defaults Upon Senior Securities 22
Item 4. Submission of Matters to a Vote of Security Holders 22
Item 5. Other 22
Item 6. Exhibits and Reports on Form 8-K. 22
SIGNATURES 24
</TABLE>
2
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, 1999 December 31, 1998
-------------------------- ---------------------------
(Unaudited)
ASSETS
<S> <C> <C>
Current Assets:
Cash and cash equivalents $ 42,142,165 $ 1,630,649
Accounts receivable -
Oil and gas sales 16,323,851 12,764,568
Associated limited partnerships
and joint ventures 5,796,597 10,058,239
Joint interest owners 3,870,270 9,767,940
Other current assets 967,276 1,025,035
-------------------------- ---------------------------
Total Current Assets 69,100,159 35,246,431
-------------------------- ---------------------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 531,769,004 497,296,068
Unproved properties not being amortized 54,592,745 56,041,886
-------------------------- ---------------------------
586,361,749 553,337,954
Furniture, fixtures, and other equipment 7,508,520 7,098,305
-------------------------- ---------------------------
593,870,269 560,436,259
Less-Accumulated depreciation, depletion,
and amortization (232,051,402) (200,713,621)
-------------------------- ---------------------------
361,818,867 359,722,638
-------------------------- ---------------------------
Other Assets:
Receivables from associated limited
partnerships, net of current portion 519,347 3,170,067
Limited partnership formation and
marketing costs 1,772,821 917,189
Deferred income taxes --- 254,984
Deferred charges 7,413,203 4,333,958
-------------------------- ---------------------------
9,705,371 8,676,198
-------------------------- ---------------------------
$ 440,624,397 $ 403,645,267
========================== ===========================
</TABLE>
See accompanying notes to condensed consolidated financial statements.
3
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, 1999 December 31, 1998
-------------------------- ----------------------------
(Unaudited)
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 17,484,979 $ 18,639,649
Payable to associated limited partnerships 562,785 380,692
Undistributed oil and gas revenues 14,429,843 12,394,713
-------------------------- ---------------------------
Total Current Liabilities 32,477,607 31,415,054
-------------------------- ---------------------------
Long-Term Debt 239,054,369 261,200,000
Deferred Revenues 826,057 1,667,574
Deferred Income Taxes 5,532,954 ---
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, 21,679,691 and 16,972,517
shares issued, and 20,820,235 and 16,291,242
shares outstanding, respectively 216,797 169,725
Additional paid-in capital 191,167,334 148,901,270
Treasury stock held, at cost, 859,456 and
681,275 shares, respectively (12,325,668) (11,841,884)
Retained earnings (16,325,053) (27,866,472)
-------------------------- ---------------------------
162,733,410 109,362,639
-------------------------- ---------------------------
$ 440,624,397 $ 403,645,267
========================== ===========================
</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
-----------------------------------------------------------------------------
09/30/99 09/30/98 09/30/99 09/30/98
---------------- ----------------- --------------- ------------------
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 30,737,150 $ 23,859,065 $ 75,405,571 $ 55,341,980
Fees from limited partnerships
and joint ventures 92,737 93,062 192,386 297,941
Interest income 243,998 32,636 267,280 95,511
Other, net 205,410 572,790 830,879 1,638,080
---------------- ----------------- --------------- ------------------
31,279,295 24,557,553 76,696,116 57,373,512
---------------- ----------------- --------------- ------------------
Costs and Expenses:
General and administrative, net 1,053,655 1,058,652 3,347,941 2,939,076
Depreciation, depletion and amortization 10,403,262 13,347,786 31,630,013 27,333,026
Oil and gas production 5,138,138 4,045,160 13,689,086 8,920,157
Interest expense, net 3,749,414 2,385,626 10,402,426 5,355,269
Write-down of oil and gas properties --- 90,772,628 --- 90,772,628
---------------- ----------------- --------------- ------------------
20,344,469 111,609,852 59,069,466 135,320,156
---------------- ----------------- --------------- ------------------
Income (Loss) before Income Taxes 10,934,826 (87,052,299) 17,626,650 (77,946,644)
Provision (Benefit) for Income Taxes 3,827,189 (29,621,284) 6,085,231 (26,641,714)
---------------- ----------------- --------------- ------------------
Net Income (Loss) $ 7,107,637 $ (57,431,015) $ 11,541,419 $ (51,304,930)
================ ================= =============== ==================
Per share amounts -
Basic: $ 0.37 $ (3.50) $ 0.67 $ (3.11)
================ ================= =============== ==================
Diluted: $ 0.36 $ (3.50) $ 0.67 $ (3.11)
================ ================= =============== ==================
Weighted Average Shares Outstanding 19,069,848 16,419,022 17,125,937 16,481,382
================ ================= =============== ==================
</TABLE>
See accompanying notes to condensed consolidated financial statements.
5
<PAGE>
SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Additional Unearned
Common Paid-In Treasury ESOP Retained
Stock(1) Capital Stock Compensation Earnings Total
----------- ------------- ------------- ------------ ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1997 $ 168,470 $ 147,542,977 $ (8,519,665) $ (150,055) $ 20,359,193 $ 159,400,920
Stock issued for benefit plans
(20,032 shares) 200 367,058 --- --- --- 367,258
Stock options exercised
(84,757 shares) 847 735,746 --- --- --- 736,593
Employee stock purchase plan
(20,756 shares) 208 317,340 --- --- --- 317,548
10/97 stock dividend adj
(16 shares) --- 461 --- --- (461) ---
Allocation of ESOP shares --- (62,312) --- 150,055 --- 87,743
Purchase of 293,474 shares as
treasury stock --- --- (3,322,219) --- --- (3,322,219)
Net loss --- --- --- --- (48,225,204) (48,225,204)
----------- ------------- ------------- ------------ ------------- -------------
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)(2) 224 (366,408) 978,956 --- --- 612,772
Stock options exercised
(61,983 shares)(2) 620 423,693 --- --- --- 424,313
Employee stock purchase plan
(22,771 shares)(2) 228 181,577 --- --- --- 181,805
Public stock offering
(4,600,000 shares)(2) 46,000 42,027,202 --- --- --- 42,073,202
Purchase of 246,500 shares
as treasury stock (2) --- --- (1,462,740) --- --- (1,462,740)
Net income (2) --- --- --- --- 11,541,419 11,541,419
----------- ------------- ------------- ------------ ------------- -------------
Balance, September 30, 1999(2) $ 216,797 $ 191,167,334 $ (12,325,668) $ --- $ (16,325,053) $ 162,733,410
=========== ============= ============= ============ ============= =============
</TABLE>
(1) $.01 Par Value
(2) Unaudited
See accompanying notes to condensed consolidated financial statements.
6
<PAGE>
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Period Ended September 30,
----------------------------------------------
1999 1998
-------------------- -------------------
<S> <C> <C>
Cash Flows From Operating Activities:
Net income (loss) $ 11,541,419 $ (51,304,930)
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization 31,630,013 27,333,026
Write-down of oil and gas properties --- 90,772,628
Deferred income taxes 5,787,938 (26,991,760)
Deferred revenue amortization related to production
payment (806,950) (948,040)
Other 422,196 355,942
Change in assets and liabilities -
Increase in accounts receivable (3,245,871) (4,170,800)
Increase in accounts payable and accrued
liabilities, excluding income taxes payable 2,930,390 2,713,583
Increase in income taxes payable 304,628 313,860
-------------------- -------------------
Net Cash Provided by Operating Activities 48,563,763 38,073,509
-------------------- -------------------
Cash Flows From Investing Activities:
Additions to property and equipment (34,907,498) (170,942,213)
Proceeds from the sale of property and equipment 3,914,578 1,294,383
Net cash received (distributed) as operator
of oil and gas properties 4,177,050 (11,210,890)
Net cash received (distributed) as operator
of partnerships and joint ventures 4,261,642 1,706,423
Limited partnership formation and marketing costs (855,632) (407,957)
Other (326,799) (95,752)
-------------------- -------------------
Net Cash Used in Investing Activities (23,736,659) (179,656,006)
-------------------- -------------------
Cash Flows From Financing Activities:
Proceeds from senior subordinated notes 124,054,369 ---
Net proceeds from (payments of) bank borrowings (146,200,000) 143,585,000
Net proceeds from issuances of common stock 42,794,224 1,192,811
Purchase of treasury stock (1,462,740) (3,050,459)
Payments of debt issuance costs (3,501,441) (540,671)
-------------------- -------------------
Net Cash Provided by Financing Activities 15,684,412 141,186,681
-------------------- -------------------
Net Increase (Decrease) in Cash and Cash Equivalents 40,511,516 (395,816)
Cash and Cash Equivalents at Beginning of Period 1,630,649 2,047,332
-------------------- -------------------
Cash and Cash Equivalents at End of Period $ 42,142,165 $ 1,651,516
==================== ===================
Supplemental disclosures of cash flows information:
Cash paid during period for interest, net of amounts
capitalized $ 6,180,930 $ 3,292,789
Cash paid during period for income taxes $ --- $ 36,186
</TABLE>
See accompanying notes to condensed consolidated financial statements.
7
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1999 (UNAUDITED) AND DECEMBER 31, 1998
(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, 1998, 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 generally
accepted accounting principles 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 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. Currently, the Company has
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. We expect this relationship will continue in the future.
We compute our 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
8
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 1999 (UNAUDITED) AND DECEMBER 31, 1998
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. We currently have production in the United States
only.
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. Because our international initiatives have not yet resulted
in the discovery of any proved reserves, to the extent costs accumulated
in our international initiatives are determined by management to be costs
that will not result in the addition of proved reserves, any impairment
determined by management will be 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,
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.
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.
Hedging Activities
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, but only to the
extent of buying protection price floors for portions of our and the
limited partnerships' oil and natural gas production. Costs and any
benefits derived from these price floors are accordingly recorded as a
reduction or increase, as applicable, in oil and gas sales revenue and
were not significant for any period presented. The costs to purchase put
options are amortized over the option period. The costs related to 1999
hedging activities through September 30, 1999 totaled approximately
$803,200 with benefits of approximately $348,400 having been received,
resulting in a net cash outflow of approximately $454,800, or $0.011 per
Mcfe. The costs related to open contracts as of September 30, 1999 totaled
approximately $106,500, which is our maximum exposure under these
contracts. These open contracts had a fair market value of $9,000 at
September 30, 1999.
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). Certain of our stock options
that would potentially dilute Basic EPS in the future were not included in
the computation of
9
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 1999 (UNAUDITED) AND DECEMBER 31, 1998
Diluted EPS because to do so would have been antidilutive for the periods
presented except for the three month period ended September 30, 1999. The
following is a reconciliation of the calculation of Basic and Diluted EPS
for the three-month and nine-month periods ended September 30, 1999:
<TABLE>
<CAPTION>
Three Months Ended September 30,1999
--------------------------------------------------
Net Per Share
Income Shares Amount
---------------- -------------- --------------
<S> <C> <C> <C>
Basic EPS:
Net Income and Share Amounts $ 7,107,637 19,069,848 $ .37
Dilutive Securities:
Convertible Notes 1,230,527 3,646,847
Stock Options --- 222,286
---------------- ---------------
Diluted EPS:
Net Income and Assumed
Share Conversions $ 8,338,164 22,938,981 $ .36
================ =============== ==============
Nine Months Ended September 30,1999
--------------------------------------------------
Net Per Share
Income Shares Amount
---------------- --------------- --------------
Basic EPS:
Net Income and Share Amounts $ 11,541,419 17,125,937 $ .67
Dilutive Securities:
Convertible Notes (1) 3,715,567 3,646,847
Stock Options (1) --- 222,286
---------------- ---------------
Diluted EPS:
Net Income and Assumed
Share Conversions $ 15,256,986 20,995,070 $ .67
================ =============== ==============
</TABLE>
(1) The convertible notes and the stock options are antidilutive in
this period.
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, is effective for fiscal years beginning after
June 15, 2000. We are currently evaluating the new standard, but have not
yet determined the impact it will have on our financial position and
results of operations.
10
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 1999 (UNAUDITED) AND DECEMBER 31, 1998
(3) LONG-TERM DEBT
Under our $250.0 million revolving credit facility with a syndicate of
ten banks, at September 30, 1999, we had no outstanding borrowings, as
previous borrowings had been paid in full during August with proceeds from
our third quarter concurrent public offerings of senior subordinated notes
and common stock. At December 31, 1998, we had outstanding borrowings of
$146.2 million under our borrowing arrangements. At September 30, 1999,
the credit facility consisted of a $250.0 million revolving line of credit
with a $140 million borrowing base. The interest rate is either (a) the
lead bank's prime rate (8.25% at September 30, 1999) 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 our ratio of 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. We have
requested that the credit facility be reduced from $250.0 million to
$225.0 million and for the $140.0 million borrowing base to be reduced to
$100.0 million. The reduction in the borrowing base was requested in order
to reduce the amount of commitment fees paid on this facility. By its
terms, the credit facility extends until August 2002.
The Company's convertible notes at September 30, 1999 consist of
$115,000,000 of 6.25% Convertible Subordinated Notes due 2006. The notes
were issued on November 25, 1996, and will mature on November 15, 2006.
The notes are unsecured and convertible into common stock of the Company
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 October 1997 10% stock dividend.
Interest on the notes is payable semiannually on May 15 and November 15,
and commenced with the first payment on May 15, 1997. On or after November
15, 1999, the notes are redeemable for cash at the option of the Company,
with certain restrictions, at 104.375% of principal, declining to 100.625%
in 2005. Upon certain changes in control of the Company, if the price of
the Company's common stock is not above certain levels, each holder of
notes will have the right to require the Company to repurchase the 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.
The Company's senior notes at September 30, 1999 consist of
$125,000,000 of 10.25% Senior Subordinated Notes due 2009. The 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 notes is
payable semiannually on February 1 and August 1, and commences with the
first payment on February 1, 2000. On or after August 1, 2004, the 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 notes with the proceeds
of qualified
11
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 1999 (UNAUDITED) AND DECEMBER 31, 1998
offerings of our equity at 110.25% of the principal amount of the notes,
together with accrued and unpaid interest. Upon certain changes in control
of the Company, each holder of notes will have the right to require the
Company to repurchase the notes at a purchase price in cash equal to 101%
of the principal amount, plus accrued and unpaid interest to the date of
purchase.
(4) 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.
(5) ACQUISITION OF PROPERTIES
We purchased oil and gas interests in the Brookeland and Masters Creek
Fields from Sonat Exploration Company in the third quarter of 1998 for
approximately $85.5 million in cash. Of this purchase price, $55.2 million
was allocated to producing properties, $15.0 million to 20% interests in
two natural gas processing plants, and $15.3 million to leasehold
properties.
As of December 31, 1998, estimated proved reserves for these acquired
properties were 130.5 Bcfe, of which approximately 58% were natural gas,
and 59% were proved undeveloped. At such date the properties included 162
producing wells in the Brookeland Field in Southeast Texas and the Masters
Creek Field in Western Louisiana, 23 saltwater disposal wells, a 20%
interest in two natural gas plants, associated production facilities, and
working interests in approximately 444,000 net acres. Swift has become
operator of 115 of the 162 wells. Our production on these properties
amounted to approximately 11.6 Bcfe in 1998 and 17.5 Bcfe in the first
nine months of 1999, of which 56% was oil in each of these periods. The
two gas plants are operated by a third party and have combined capacity of
250 MMcfe per day.
This acquisition was accounted for by the purchase method and was
incorporated into our results of operations in the third quarter of 1998.
The following unaudited pro forma supplemental information presents
consolidated results of operations as if this acquisition had occurred 14
on January 1, 1998:
<TABLE>
<CAPTION>
Nine Months
Ended September 30,
1998
--------------------
<S> <C>
(Thousands, except per share amounts) (Unaudited)
Revenue $ 90,299
Net Income Before Non-Cash Charge $ 16,017
Net Loss $ (43,893)
Per Share Amounts-
Basic $ (2.66)
Diluted $ (2.66)
</TABLE>
12
<PAGE>
SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
SEPTEMBER 30, 1999 (UNAUDITED) AND DECEMBER 31, 1998
(6) FOREIGN ACTIVITIES
New Zealand. Since October 1995, the New Zealand Minister of Energy has
issued to Swift two petroleum exploration permits. 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. A wholly-owned subsidiary, Swift Energy New Zealand
Limited, formed in late 1997, conducts our New Zealand activities and owns
the interest in the permits. In March 1998, we surrendered approximately
46,400 acres covered in 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. Under the terms of the expanded permit, we were required to
commence drilling one exploratory well prior to August 12, 1999.
We spudded an exploratory well in July which has been drilled to its
total depth. While drilling, hydrocarbon shows were encountered and
further evaluation of the well will be done through production tests. The
production tests are expected to commence in mid- November. Our portion of
the drilling costs incurred at September 30, 1999 are approximately $4.6
million. We expect to conclude the production tests of this well during
the fourth quarter of 1999, with our portion of such costs estimated to be
$1.4 million. Should this exploratory well fail to discover economic
reserves, in the fourth quarter of 1999 we would be required to charge
against earnings the drilling costs plus a portion of the capitalized
costs in the unproved properties portion of oil and gas properties, with
the estimated potential aggregate impairment currently estimated to total
up to $7.5 million. We have fulfilled all other obligations under the
permit.
On October 23, 1998, we entered into separate agreements with Marabella
Enterprises Ltd., a subsidiary of Bligh Oil & Minerals N.L., an Australian
company, under which we obtained from Marabella a 25% working interest in
another New Zealand petroleum exploration permit and under which Marabella
became a 5% participant in our permit. During the fourth quarter of 1998,
Marabella drilled an unsuccessful exploration well on its permit.
Accordingly, we charged $400,000 against earnings, representing our costs
of such well. We also agreed in principle to participate with Marabella in
an additional permit as a 17.5% working interest owner. Additionally,
Swift obtained a 7.5% working interest in another New Zealand permit from
Antrim Oil and Gas Limited, a Canadian company, and Antrim became a 5%
participant in our permit. An exploratory well was drilled and temporarily
abandoned on Antrim's permit during the second quarter of 1999, and we
charged our $290,000 portion of the costs on this well against earnings in
that quarter. As of September 30, 1999, our investment in New Zealand
totaled approximately $9.1 million. We have included these costs in the
unproved properties portion of oil and gas properties.
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 Fields from Sonat
Exploration Company. In 1996, 1997, and 1998, we used this flexible
strategy of employing both drilling and acquisitions to add more reserves
than we depleted through production. Our revenues are primarily from oil
and gas sales attributable to properties in which we own a direct or
indirect interest.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 1999, we relied upon our internally
generated cash flows of $48.6 million to fund capital expenditures of
$34.9 million. We expect internally generated cash flows, together with
the remaining net proceeds of approximately $26.6 million from our third
quarter public sale of senior notes and common stock, to provide cash and
working capital through the remainder of 1999. During 1998, we used $138.3
million borrowed under our credit facilities, along with our internal cash
flows of $54.2 million, to fund capital expenditures of $183.8 million.
Net Cash Provided by Operating Activities. For the first nine months of
1999, net cash provided by our operating activities increased by 28% to
$48.6 million, as compared to $38.1 million during the first nine months a
year earlier. The 1999 increase of $10.5 million was primarily due to
$20.1 million of additional oil and gas sales. However, this increase was
substantially offset by the $4.8 million increase in oil and gas
production costs and the $5.0 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 on August 4, 1999, and will
mature on August 1, 2009. Proceeds from the two offerings were used to
repay all of our bank borrowings ($136.0 million on August 4, 1999). The
remainder of the proceeds will be used, together with internally generated
cash flows, to fund capital expenditures and working capital needs through
1999. The principal terms of these notes are more fully described in Note
3 to our condensed consolidated financial statements.
Credit Facility. At September 30, 1999, we had no outstanding
borrowings under our credit facility. At December 31, 1998, we had
outstanding borrowings of $146.2 million under that facility. At September
30, 1999, our credit facility consists of a $250.0 million revolving line
of credit with a $140.0 borrowing base. Our $250.0 million 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.
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.
14
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
Working Capital. Our working capital increased from $3.8 million at
December 31, 1998, to $36.6 million at September 30, 1999, primarily due
to $26.6 million of remaining proceeds from our third quarter 1999 public
offerings of common stock and senior notes, and due to our internally
generated funds exceeding our capital expenditures during that period.
Due to the nature of our business, the individual components of our
working capital fluctuate considerably from period to period. We incur
significant working capital requirements in our role as operator of
approximately 770 wells and in our drilling and acquisition activities. In
this capacity, we are responsible for certain day-to-day cash management,
including the collection and disbursement of oil and gas revenues and
related expenses.
Common Stock Repurchase Program. In March 1997, we commenced a common
stock repurchase program which terminated pursuant to its terms as of June
30, 1999. We have spent $13.3 million through June 30, 1999 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 liability in the 401(k) program for our employees.
Capital Expenditures. During the first nine months of 1999, we used
$34.9 million to fund capital expenditures for property, plant, and
equipment. These capital expenditures included:
o $25.0 million for drilling costs, both development and exploratory;
o $8.8 million of domestic prospect costs, principally prospect
leasehold, seismic and geological costs of unproved prospects for our
account;
o $0.7 million invested in New Zealand; and
o $0.4 million spent primarily for computer equipment, software and
furniture and fixtures.
In the remaining three months of 1999, we expect to spend approximately
$30.0 million on capital expenditures, including investments in all areas
in which investments were made during the first nine months of the year as
described above. Eighteen wells were drilled in the first nine months of
1999, and thirteen were successful. Twelve of the successful wells were
development wells. For the remaining three months of 1999, we anticipate
drilling an additional 13 wells, made up of 11 development wells and two
exploratory wells. We estimate capital expenditures for 1999 to be
approximately $65 million, an increase from the original 1999 budget of
$54 million, but still substantially lower than budgets in prior years.
This upward adjustment in the 1999 capital expenditures budget is in
response to the recent improvement in commodity prices. Approximately $50
million of the revised 1999 budget is allocated to drilling, primarily in
our core fields. The remaining $15 million is targeted principally for
leasehold, seismic and geological costs of unproved properties. We believe
that 1999's anticipated internally generated cash flows, together with the
unspent proceeds from our third quarter financing activities, will be
sufficient to finance the costs associated with our currently budgeted
remaining 1999 capital expenditures. We anticipate that our 2000 capital
expenditures budget will be in excess of the revised 1999 budget, also in
response to the recent improvements in commodity prices.
15
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
RESULTS OF OPERATIONS - Three Months Ended September 30, 1999 and 1998
Revenues. Our revenues increased 27% during the third quarter of 1999
as compared to the same period in 1998. This increase was caused by growth
in our oil and gas sales, which resulted from the 55% increase in oil
prices received and the 48% increase in gas prices received.
Oil and Gas Sales. Our oil and gas sales increased 29% to $30.7 million
in the third quarter of 1999, compared to $23.9 million for the comparable
period in 1998. Our natural gas production decreased 15% and oil
production decreased 12% resulting in a 14%, or 1.7 Bcfe, decrease over
volumes in the same period in 1998. These volume decreases were more than
offset by the increased prices received. The decrease in production
volumes resulted primarily from our decision to reduce development
drilling during the latter part of 1998 and the first half of 1999 due to
low oil and gas prices. Additionally, several new Masters Creek wells,
with their high initial rates of production, were placed into production
last year during the third quarter.
Our $6.8 million increase in oil and gas sales during the third quarter
of 1999 resulted from:
o Price increases which had a favorable impact on sales of $10.2
million, with $6.2 million of the increase coming from the increase in
average gas prices received and $4.0 million coming from the increase
in average oil prices received; offset by
o Volume decreases which had an unfavorable impact on sales of $3.4
million, with $2.4 million of the decrease coming from the 1.2 Bcf
decrease in gas sales volumes and $1.0 million of the decrease coming
from the 83,000 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 for the third
quarter periods of 1999 and 1998.
<TABLE>
<CAPTION>
Field Revenues (In Millions) Net Sales Volumes (Bcfe)
----- ------------------------- ------------------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
AWP Olmos $ 8.8 $ 8.5 3.2 4.1
Brookeland $ 4.3 $ 3.7 1.3 1.8
Giddings $ 2.5 $ 2.7 0.9 1.6
Masters Creek $13.2 $ 8.2 4.1 3.8
</TABLE>
Due to the decrease in the 1999 capital expenditures budget, and the
resulting curtailment of drilling, the natural production decline in three
of these fields was not offset by newly developed production.
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) Oil (Bbl) Gas (Mcf)
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
1998
----
Three Months Ended
September 30, 695,434 8,076,988 $11.94 $1.93
1999
----
Three Months Ended
September 30, 611,948 6,838,924 $18.46 $2.84
</TABLE>
Costs and Expenses. Our general and administrative expenses for the
third quarter of 1999 decreased slightly when compared to the same period
in 1998. However, our general and administrative expenses per Mcfe
produced increased from $0.09 per Mcfe for the third quarter of 1998 to
$0.10 per Mcfe for the comparable period in 1999 as production volumes
decreased as described above. Supervision fees netted from general and
administrative expenses for the third quarter of 1999 were $0.8 million
and for the same period of 1998 were $0.6 million.
Depreciation, depletion and amortization of our assets, or DD&A,
decreased 22% or approximately $2.9 million for the third quarter of 1999.
This was primarily due to additions to our reserves and associated costs
and to the related 14% decrease in production volumes. Our DD&A rate per
Mcfe of production decreased from $1.09 per Mcfe in the third quarter of
1998 to $0.99 per Mcfe in the same 1999 period.
Our production costs per Mcfe increased to $0.49 per Mcfe in the third
quarter of 1999 from $0.33 per Mcfe in the same 1998 period. Increased
severance taxes resulting from higher commodity prices and the expiration
of certain specific well severance tax exemptions, along with an increase
in planned remedial well work contributed to the $1.1 million, or 27%
increase. While the planned remedial well work is expected to increase
production on those wells in the future, these costs are expensed as
incurred. Supervision fees netted from production costs for the third
quarter of 1999 were $0.8 million and for the same period of 1998 were
$0.6 million.
Interest expense on our convertible notes due 2006, including
amortization of debt issuance costs, was the same in the third quarter of
1999 and 1998, totaling $1.9 million. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance
costs, totaled $1.1 million in the third quarter of 1999, compared to $1.9
million for our credit facilities in the same 1998 period. Interest
expense and discount on our newly issued senior notes due 2009, including
amortization of debt issuance costs, totaled $2.0 million in 1999 only.
Thus, 1999 total interest charges were $5.0 million, of which $1.2 million
was capitalized. In the third quarter of 1998, these charges totaled $3.8
million, of which $1.4 million was capitalized. We capitalized that
portion of interest related to our exploration, partnership and foreign
business development activities. The increase in interest expense in 1999
is attributable to the increase in amounts outstanding and to the higher
interest rate on our new senior notes.
Net Income. Our net income for the third quarter of 1999 of $7.1
million and Basic EPS of $0.37 were 187% and 145% higher than net income
of $2.5 million and Basic EPS of $0.15 before the non-cash charge taken in
the third quarter of 1998. This increase primarily
17
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
reflected the effect of the increased oil and gas prices received in the
1999 period, as discussed above. The non-cash charge, necessitated by the
low oil and gas prices experienced at the end of September 1998, resulted
in a net loss of $57.4 million or $3.50 basic loss per share in the third
quarter of 1998.
RESULTS OF OPERATIONS - Nine Months Ended September 30, 1999 and 1998
Revenues. Our revenues increased 34% during the first nine months of
1999 as compared to the same period in 1998. This increase was caused by
growth in our oil and gas sales, which resulted from increases in
production volumes and increases in both oil and gas prices.
Oil and Gas Sales. Our oil and gas sales increased 36% to $75.4 million
in the first nine months of 1999, compared to $55.3 million for the
comparable period in 1998. Our gas production increased 3% and oil
production increased 84% primarily due to production from the Brookeland
and Masters Creek Fields, which were acquired in the third quarter of
1998. Our net sales volume in the first nine months of 1999 increased by
23%, or 6.1 Bcfe, over volumes in the same period in 1998. A 6% increase
in gas prices and a 23% increase in oil prices between the two periods
were significant factors contributing to these increased revenues.
Our $20.1 million increase in oil and gas sales during the first nine
months of 1999 resulted from:
o Volume increases which added $12.2 million of sales, with $1.4 million
of the increase coming from the 0.7 Bcf increase in gas sales volumes
and $10.8 million of the increase coming from the 903,000 barrel
increase in oil sales volumes; and
o Price variances which added $7.9 million of sales, with $2.5 million
of the increase coming from the increase in average gas prices
received and $5.4 million of the increase coming from the increase in
average oil prices received.
The following table provides additional information regarding the
changes in the sources of our oil and gas sales and volumes for the
nine-month periods of 1999 and 1998.
<TABLE>
<CAPTION>
Field Revenues (In Millions) Net Sales Volumes (Bcfe)
----- ---------------------- ------------------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
AWP Olmos $ 22.7 $ 25.7 10.1 11.9
Brookeland $ 10.1 $ 3.7 4.3 1.8
Giddings $ 6.1 $ 11.6 2.9 5.5
Masters Creek $ 32.5 $ 8.2 13.2 3.8
</TABLE>
Our acquisition of interests in the Masters Creek and Brookeland
Fields, which have a higher percentage of production from oil, has
decreased the predominance of gas in our production mix from 84% in 1998
prior to the acquisition to 64% in the first nine months of 1999. Even
though we scaled back our 1999 capital expenditures budget from budgeted
amounts in prior years, we expect oil and gas sales volumes to increase in
1999 when
18
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
compared to 1998, primarily due to the full year of production from the
Masters Creek and Brookeland Fields, as the 1998 amounts above from these
two fields includes production only from the third quarter. However, due
to the decrease in the 1999 capital expenditures budget, and the resulting
curtailment of drilling in the Giddings Field and the AWP Olmos Field, the
natural production decline in these fields were not offset by newly
developed production.
Thefollowing table provides additional information regarding our oil
and gas sales:
<TABLE>
<CAPTION>
Net Sales Volume Average Sales Price
---------------------------- -----------------------
Oil (Bbl) Gas (Mcf) Oil (Bbl) Gas (Mcf)
--------- ---------- --------- ---------
1998
----
<S> <C> <C> <C> <C>
Three Months Ended 3-31-98 195,114 5,858,509 $12.61 $2.28
Three Months Ended 6-30-98 190,225 6,159,255 $11.20 $2.20
Three Months Ended 9-30-98 695,434 8,076,988 $11.94 $1.93
--------- ----------
Nine Months Ended 9-30-98 1,080,773 20,094,752 $11.93 $2.11
1999
----
Three Months Ended 3-31-99 727,810 7,224,188 $10.87 $1.82
Three Months Ended 6-30-99 644,323 6,688,316 $15.25 $2.05
Three Months Ended 9-30-99 611,948 6,838,924 $18.46 $2.84
--------- ----------
Nine Months Ended 9-30-99 1,984,081 20,751,428 $14.64 $2.23
</TABLE>
Costs and Expenses. Our general and administrative expenses for the
first nine months of 1999 increased approximately $0.4 million, when
compared to the same period in 1998. However, our general and
administrative expenses per Mcfe produced decreased by 7% from $0.11 per
Mcfe for the first nine months of 1998 to $0.10 per Mcfe for the
comparable period in 1999. Supervision fees netted from general and
administrative expenses for the first nine months of 1999 were $2.4
million and for the same period of 1998 were $2.0 million.
Depreciation, depletion and amortization of our assets, or DD&A,
increased 16% or approximately $4.3 million for the first nine months of
1999. This was primarily due to additions to our reserves and associated
costs and to the related 23% increase in production volumes from the added
reserves, primarily resulting from the Sonat acquisition. Our DD&A rate
per Mcfe of production has decreased from $1.03 per Mcfe in the first nine
months of 1998 to $0.97 per Mcfe in the same 1999 period.
Oil and gas production costs increased by 53%, or approximately $4.8
million, in the first nine months of 1999 when compared to the first nine
months of 1998. Our production costs per Mcfe increased to $0.42 per Mcfe
in the first nine months of 1999 from $0.34 per Mcfe in the same 1998
period. This increase is primarily due to the 23% increase in our
production volumes, increased severance taxes resulting from higher
commodity prices and the expiration of certain specific well severance tax
exemptions, along with an increase in planned remedial well work. While
the planned remedial well work is expected to increase production on those
wells in the future, these costs are expensed as incurred. Supervision
fees netted from production costs for the first nine months of 1999 were
$2.4 million and for the first nine months of 1998 were $2.0 million.
Interest expense on our convertible notes due 2006, including
amortization of debt issuance costs, was the same in the first nine months
of 1999 and in 1998, totaling $5.7 million. Interest expense on the credit
facility, including commitment fees and amortization of debt issuance
costs, totaled $6.0 million in the first nine months of 1999, compared to
$2.9 million for our credit facilities in the same 1998 period. Interest
expense and discount
19
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
on our newly issued senior notes due 2009, including amortization of debt
issuance costs, totaled $2.0 million in 1999 only. Thus, 1999 total
interest charges were $13.7 million, of which $3.3 million was
capitalized. In the first nine months of 1998, these charges totaled $8.6
million, of which $3.2 million was capitalized. We capitalized that
portion of interest related to our exploration, partnership and foreign
business development activities. The increase in interest expense in 1999
is attributable to the increase in amounts outstanding to fund our 1998
capital expenditures which included the Toledo Bend acquisition in the
third quarter of 1998.
Net Income. Our net income for the first nine months of 1999 of $11.5
million and Basic EPS of $0.67 were 34% and 28% higher, respectively than
net income of $8.6 million and Basic EPS of $0.52 before the non-cash
charge taken in the third quarter of 1998. This increase primarily
reflected the effect of the increased production volumes and prices
received, as discussed above. Oil and gas prices have risen rapidly since
the middle of the second quarter of this year, which is reflected by the
third quarter net income representing 62% of net income for the nine month
period. The non-cash charge, necessitated by low oil and gas prices
experienced at the end of September 1998, resulted in a net loss of $51.3
million or $3.11 basic loss per share in the nine-month 1998 period.
Year 2000. The Year 2000 issue arose because many existing computer
programs use only the last two digits to refer to a year. Therefore, these
programs cannot distinguish between the years 1900 and 2000. Errors of
this type can result in systems failures, miscalculations and the
disruption of normal business activities. We formed a task force during
1998 to address the Year 2000 issue and to prepare our business systems
for the Year 2000. This task force developed our Year 2000 program which
includes testing our in-house business systems and field operations
systems, reviewing Year 2000 compliance certifications and reports issued
by third parties, upgrading or replacing noncompliance systems and
preparing a contingency plan for unforeseen difficulties. We are
continuing to implement this plan in an effort to make our operations
capable of addressing the Year 2000.
Our in-house business systems are almost entirely comprised of
off-the-shelf software. We identified and tested all in-house software
which was not certified by the licensor as Year 2000 compliant. To date,
with minor exceptions these systems have been either tested, certified as
compliant by the licensor of the software, or categorized as not date
specific. During the testing phase we identified the software which
experienced difficulties addressing the Year 2000. We solved most of these
potential Year 2000 problems by upgrading or replacing this software,
which we test as it is installed. We have not experienced any material
system disruption during testing procedures, and based on testing and
remedial activities, we believe that we have resolved potential Year 2000
problems concerning our financial and administrative systems. We have
completed testing and are awaiting additional certification documentation
from licensors but will continue remedial actions as needed.
Our core business function consists of oil and gas exploration. The
systems and equipment which perform these functions are primarily
non-information technology systems which are not date specific. Therefore,
although we cannot predict all effects of the Year 2000 issue, we expect
that our field operation systems will continue to perform normally when
faced with the Year 2000. In the event of unforeseen Year 2000
difficulties, employees can manually perform most, if not all, in-house
functions, although such acts may require additional time to perform. Our
most reasonably likely worst case scenario would therefore involve a
prolonged disruption of external power sources upon which our core field
operations equipment relies. Such a disruption could result in a
substantial decrease in our
20
<PAGE>
SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS-CONTINUED
oil and gas production activities. Although we maintain limited on-site
secondary power supplies such as generators, it is not economically
feasible to maintain a secondary power supply to fully replace primary
power for all field operations systems. A prolonged interruption could
materially affect our operations, liquidity or capital resources.
In our business, we also depend on third parties such as pipeline
operators to whom we sell natural gas, customers and suppliers, any one of
whom could be prone to Year 2000 problems that we cannot assess or detect.
We have contacted our major purchasers, customers, suppliers, financial
institutions and others with whom we conduct business to assess their Year
2000 program and to inform them of our Year 2000 review. Over 60% have
responded that they are compliant, while the remainder continue their
progress and expect to complete their reviews prior to the end of 1999. We
cannot be certain that such third parties will appropriately address the
Year 2000 issue or will not themselves suffer a Year 2000 disruption that
could have a material adverse effect on our business, financial condition
or operating results.
Based on these third party representations and results of our testing
phase, we are continuing to develop our contingency plan, such as using
on-site generators and identifying substitute suppliers. We do not believe
that costs incurred to address the Year 2000 issue will have a material
effect on our results of operations or our liquidity and financial
condition. We estimate our total cost to address the Year 2000 issue to be
less than $150,000, most of which was spent during the testing phase. We
have used and will continue to use both internal and external resources to
complete our Year 2000 program and perform tasks necessary to address the
Year 2000 problem.
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, and therefore involve
a number of risks and uncertainties. Such forward-looking statements may
be or may concern, among other things, 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," "estimate," "expect," "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 and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and our financial condition and
results of operations. As a consequence, actual results may differ
materially from expectations, estimates or assumptions expressed in or
implied by any forward-looking statements made by or on behalf of us,
including those regarding our financial results, levels of oil and gas
production or revenues, capital expenditures, and capital resource
activities. Among the factors that could cause actual results to differ
materially are: 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; competition and government regulations; as well as the risks
and uncertainties discussed herein, including, without limitation, the
portions referenced above, and the uncertainties 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.
21
<PAGE>
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings -
From time to time, litigation arises in the ordinary course of
Swift's oil and gas drilling and production activities. In early 1997,
Swift and the Lower Colorado River authority, the LCRA, filed claims
against each other in the 155th Judicial District Court of Fayette County,
Texas, over the interpretation of an oil and gas farmout agreement from
LCRA to Swift covering land in Fayette County, Texas. Swift originally
sued to force LCRA to assign to Swift leases which LCRA had refused to
assign, covering wells successfully drilled by Swift on the farmout
acreage, and seeking declaration as to the parties' interest in the
properties involved. LCRA counterclaimed for damages and claimed fraud and
conversion, plus conspiracy to convert oil and gas among Swift, certain of
its officers and managed partnerships. The parties have tentatively
settled this litigation during a mediation held in late May 1999, although
this settlement has not been finalized. Swift does not believe that the
ultimate resolution of this case will have a material adverse impact upon
its financial condition or results of operations.
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 -
A. Earl Swift has indicated a desire to retire as Swift's chief
executive officer during the fourth quarter of 2000, rather than his
intention announced earlier this year to retire in late 1999. Mr. Swift
intends to remain as chairman of the board of directors. The board of
directors has commenced its search for Mr. Swift's replacement as chief
executive officer.
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, 1999:
(1) Form 8-K dated July 30, 1999, filed under Item 5-Other Events
and under Item 7-Financial Statements and Exhibits, filed for
the purpose of including the statement of Eligibility, and
Qualification on Form T-1 under the Trust Indenture Act of
1939 of Bank One, N.A., to serve as Trustee of an offering of
$125,000,000 principal amount of 10.25% Senior Subordinated
Notes Due 2009 (the "Senior Notes") under a shelf registration
statement (No. 333-81651) declared effective by the Commission
July 9, 1999.
(2) Form 8-K dated August 4, 1999 filed under Item 5-Other Events
and under Item 7-Financial Statements and Exhibits filed for
the purpose of including exhibits to
22
<PAGE>
SWIFT ENERGY COMPANY
PART II. - OTHER INFORMATION-CONTINUED
the above-listed shelf registration statement and the offering
thereunder of the Senior Notes and 4.6 million shares of Swift
common stock. The exhibits filed were underwriting agreements
for both offerings, a form of supplemental indenture covering
the Senior Notes, legal opinions covering the legality of the
Senior Notes and common stock, a third amendment to Swift's
credit agreement and a letter agreement amending that credit
agreement.
23
<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 12, 1999 By: (Original Signed By)
-------------------------- -------------------------------------
John R. Alden
Sr. Vice President - Finance
Chief Financial Officer, Secretary
Date: November 12, 1999 By: (Original Signed By)
------------------------- -------------------------------------
Alton D. Heckaman, Jr.
Vice President,
Controller and Principal
Accounting Officer
24
<PAGE>
Exhibit 12
25
<PAGE>
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
Nine Months Ended September 30,
------------------------------------
1999 1998
----------------- ---------------
<S> <C> <C>
GROSS G&A 15,406,200 15,752,533
NET G&A 3,347,941 2,939,076
INTEREST EXPENSE 10,402,426 5,355,269
RENT EXPENSE 970,876 837,429
NET INCOME BEFORE TAXES 17,626,650 (77,946,644)
CAPITALIZED INTEREST 2,993,868 2,899,618
DEPLETED CAPITALIZED INTEREST 261,363 219,198
CALCULATED DATA
-----------------------------------------------------------
UNALLOCATED G&A (%) 21.73% 18.66%
NON-CAPITAL RENT EXPENSE 210,982 156,246
1/3 NON-CAPITAL RENT EXPENSE 70,327 52,082
FIXED CHARGES 13,466,621 8,306,969
EARNINGS 28,360,767 (72,320,095)
RATIO OF EARNINGS TO FIXED CHARGES 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
represents income before income taxes from continuing operations before
fixed charges. Due to the $90.8 million non-cash charge incurred in the
third quarter of 1998 caused by a write-down in the carrying value of oil
and gas properties, nine months ended September 30, 1998 earnings are
insufficient by $80.6 million to cover fixed charges in this period. If
the $90.8 million non-cash charge is excluded, the ratio of earnings to
fixed charges would have been 2.22 for the nine months ended September 30,
1998.
26
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from Swift Energy
Company's financial statements contained in its quarterly report on Form 10-Q
for the period ended September 30, 1999.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 42,142,165
<SECURITIES> 0
<RECEIVABLES> 26,510,065
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 69,100,159
<PP&E> 593,870,269
<DEPRECIATION> (232,051,402)
<TOTAL-ASSETS> 440,624,397
<CURRENT-LIABILITIES> 32,477,607
<BONDS> 0
0
0
<COMMON> 216,797
<OTHER-SE> 162,516,613
<TOTAL-LIABILITY-AND-EQUITY> 440,624,397
<SALES> 75,405,571
<TOTAL-REVENUES> 76,696,116
<CGS> 0
<TOTAL-COSTS> 45,319,099<F1>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,402,426
<INCOME-PRETAX> 17,626,650
<INCOME-TAX> 6,085,231
<INCOME-CONTINUING> 11,541,419
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 11,541,419
<EPS-BASIC> 0.67
<EPS-DILUTED> 0.67
<FN>
<F1>Includes depreciation, depletion and amortization expense and oil and gas
production costs. Excludes general and administrative and interest expense.
</FN>
</TABLE>
