<PAGE> 1
Filed Pursuant to Rule 424(b)(1)
Registration No. 333-14785
PROSPECTUS
$100,000,000
SWIFT ENERGY COMPANY [SWIFT ENERGY LOGO]
6 1/4% CONVERTIBLE SUBORDINATED NOTES DUE 2006
The 6 1/4% Convertible Subordinated Notes due 2006 (the "Notes") of Swift Energy
Company (the "Company" or "Swift") offered hereby will mature on November 15,
2006. Interest on the Notes will accrue from November 25, 1996 and is payable on
May 15 and November 15 of each year commencing May 15, 1997. The Notes are
convertible at the option of the holder at any time after 90 days following the
date of original issuance thereof and prior to maturity, unless previously
redeemed or repurchased, into shares of the Company's Common Stock, par value
$.01 per share (the "Common Stock"), at a conversion price of $34.6875 per share
(equivalent to a conversion rate of 28.8288 shares per $1,000 principal amount
of Notes), subject to certain adjustments. The Company's Common Stock is listed
on the New York Stock Exchange and the Pacific Stock Exchange under the symbol
"SFY." On November 19, 1996 the last reported sale price of the Company's Common
Stock on the New York Stock Exchange was $27.750 per share.
The Notes are redeemable at the option of the Company, in whole or in part, at
any time on or after November 15, 1999 at the redemption prices set forth herein
together with accrued and unpaid interest. The Notes do not provide for any
sinking fund. Upon the occurrence of a Designated Event (as defined herein),
each holder of the Notes may require the Company to repurchase all or a portion
of such holder's Notes at 101% of the principal amount thereof, together with
accrued and unpaid interest, if any, to the date of repurchase. See "Description
of Notes."
The Notes will constitute unsecured subordinated obligations of the Company and
will rank pari passu in right of payment to the Company's other subordinated
indebtedness, if any. The Notes and the Company's obligations with respect
thereto (including the Company's obligation to repurchase Notes upon the
occurrence of a Designated Event) will be subordinated in right of payment to
all Senior Debt (as defined herein) of the Company. See "Description of
Notes -- Subordination of Notes" and "Capitalization."
The Notes have been approved for listing on the New York Stock Exchange, subject
to official notice of issuance.
SEE RISK FACTORS COMMENCING ON PAGE 11 OF THIS PROSPECTUS FOR A DESCRIPTION OF
CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN
THE NOTES.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS TO WHICH IT RELATES. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC(1) DISCOUNT COMPANY(1)(2)
<S> <C> <C> <C>
Per Note.............................. 100.000% 3.500% 96.500%
Total(3).............................. $100,000,000 $3,500,000 $96,500,000
- --------------------------------------------------------------------------------------------------------
</TABLE>
(1) Plus accrued interest, if any, from the date of issuance.
(2) Before deducting expenses payable by the Company estimated at $500,000.
(3) The Company has granted the Underwriters an option, exercisable within 30
days from the date of this Prospectus, to purchase up to an additional
$15,000,000 aggregate principal amount of Notes at the Price to Public, less
Underwriting Discount, to cover over-allotments, if any. If the Underwriters
exercise such option in full, the total Price to Public, Underwriting
Discount and Proceeds to Company will be $115,000,000, $4,025,000 and
$110,975,000, respectively. See "Underwriting."
The Notes are offered subject to receipt and acceptance by the Underwriters, to
prior sale and to the Underwriters' right to reject any order in whole or in
part and to withdraw, cancel or modify the offer without notice. It is expected
that delivery of the Notes will be made at the office of Salomon Brothers Inc,
Seven World Trade Center, New York, New York, or through the facilities of The
Depository Trust Company, on or about November 25, 1996.
SALOMON BROTHERS INC
OPPENHEIMER & CO., INC.
PRUDENTIAL SECURITIES INCORPORATED
SOUTHCOAST CAPITAL
CORPORATION
The date of this Prospectus is November 19, 1996.
<PAGE> 2
AVAILABLE INFORMATION
The Company has filed with the Securities and Exchange Commission (the
"Commission") a Registration Statement on Form S-3 (of which this Prospectus is
a part) under the Securities Act of 1933, as amended, with respect to the
securities offered hereby. This Prospectus does not contain all the information
set forth in the Registration Statement or the exhibits thereto, to which
reference is made concerning the contents of such exhibits. Reference to each
such exhibit qualifies all information related thereto.
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended, and accordingly files reports, proxy
statements and other information ("Reports") with the Commission. The
Registration Statement, the exhibits thereto and the Reports, can be inspected
and copied at the public reference facilities maintained by the Commission at
450 5th Street, N.W., Room 1024, Washington, D.C. 20549, and at the following
regional offices of the Commission: 7 World Trade Center, 13th Floor, New York,
New York 10048 and Northwestern Atrium Center, 500 West Madison Street, Suite
1400, Chicago, Illinois 60661, at prescribed rates. Reports concerning the
Company can also be inspected at the offices of the New York Stock Exchange,
Inc., 20 Broad Street, New York, New York 10005 and the Pacific Stock Exchange
Incorporated, 115 Sansome Street, 8th Floor, San Francisco, California 94104. In
addition, such materials filed electronically by the Company with the Commission
are available at the Commission's World Wide Web site at http://www.sec.gov.
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE NOTES OR THE
COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, THE
PACIFIC STOCK EXCHANGE OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE
DISCONTINUED AT ANY TIME.
DEFINED TERMS
The following defined terms have the indicated meanings when used in this
Prospectus: "BCF" means billion cubic feet of natural gas; "BCFE" means billion
cubic feet of natural gas equivalent; see "-- Mcfe;" "BBL" means barrel or
barrels of oil; "MBBL" means thousand barrels of oil; "MCF" means thousand
cubic feet of natural gas; "MCFE" means thousand cubic feet of natural gas
equivalent, which is determined using the ratio of one barrel of oil,
condensate or natural gas liquids to six Mcf of natural gas; "MCFEPD" means
Mcfe per day; "MMCF" means million cubic feet of natural gas; "MMCFE" means
million cubic feet of natural gas equivalent, which is determined using the
ratio of one barrel of oil, condensate or natural gas liquids to six Mcf of
natural gas; "MMBBL" means million barrels of oil; "MMBTU" means million
British Thermal Units, which is a heating equivalent measure for natural gas,
as opposed to Mcf, which is strictly a measure of natural gas volumes;
typically prices quoted for natural gas are designated as prices per MMBtu, the
same basis on which natural gas is contracted for sale; "PV-10 VALUE" means the
estimated future net revenue to be generated from the production of proved
reserves discounted to present value using an annual discount rate of 10%;
these amounts are calculated net of estimated production costs and future
development costs, using prices and costs in effect as of a certain date,
without escalation and without giving effect to non-property related expenses
such as general and administrative expenses, debt service, future income tax
expense or depreciation, depletion and amortization; see "Risk Factors --
Uncertainty of Estimates of Reserves and Future Net Revenues;" and "RESERVE
REPLACEMENT COST" means, with respect to proved reserves, a three-year average
(unless otherwise indicated) calculated by dividing total acquisition,
exploration and development costs incurred during the period (exclusive of
future development costs) by net reserves added during the period (excluding
revisions).
2
<PAGE> 3
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and Consolidated Financial Statements, including the notes thereto,
and other financial information included or incorporated by reference, appearing
elsewhere in this Prospectus. Prospective investors should carefully consider
the factors set forth under "Risk Factors." Unless the context otherwise
requires, references to the "Company" or "Swift" refer to Swift Energy Company
and its consolidated subsidiaries. Unless otherwise indicated, all information
in this Prospectus assumes no exercise of the Underwriters' over-allotment
option. Defined terms used herein to describe quantities of oil and gas and
other matters are explained under "Defined Terms" on page 2 above. The Company's
principal executive offices are located at 16825 Northchase Drive, Suite 400,
Houston, Texas 77060, and its telephone number is (281) 874-2700.
THE COMPANY
Swift Energy Company is engaged in the exploration, development,
acquisition and production of oil and gas properties with a primary focus on
U.S. onshore natural gas reserves. As of December 31, 1995, the Company had
interests in over 4,000 oil and gas wells located in 15 states, with over 85% of
its proved reserve base concentrated in Texas. At the same date, the Company had
estimated proved reserves of 176 Bcfe, approximately 80% of which were natural
gas, and operated 767 wells representing 86% of its proved reserve base.
The Company's primary focus is exploration and development drilling on its
core areas, the AWP Olmos Field located in South Texas and the Texas Austin
Chalk trend. The AWP Olmos Field is characterized by long-lived reserves, while
the Austin Chalk trend is characterized by more short-lived reserves with high
initial production and rapid decline rates. These fields accounted for
approximately 67% and 6%, respectively, of the Company's proved reserves as of
December 31, 1995, and approximately 61% and 16%, respectively, of the Company's
production for the nine months ended September 30, 1996. The Company has
substantially accelerated its drilling activities during the last several years,
drilling 16, 42 and 76 net wells in 1994, 1995 and the first nine months of
1996, respectively, primarily in these areas. The Company has also doubled its
undeveloped acreage position in both the AWP Olmos Field and the Austin Chalk
trend during 1996 and currently has an inventory of over 360 and 65 potential
well locations in these two areas, respectively. The Company has budgeted
capital expenditures of over $134.0 million for the remaining three months of
1996 and for 1997, of which approximately $90.0 million is targeted for these
two fields. The Company is also actively pursuing exploratory and development
drilling opportunities in other basins in Texas, Louisiana and Wyoming. As a
complement to these domestic activities, the Company is participating in several
high potential international projects, with limited capital exposure to the
Company in New Zealand, Russia and Venezuela.
The Company has increased its proved reserves from 41 Bcfe at year-end 1990
to 176 Bcfe at year-end 1995, primarily from additions through the drillbit,
which has resulted in the replacement of 516% of production during the same
five-year period. In 1995, the Company increased its proved reserves by 70%,
resulting in the replacement of 827% of 1995 production. Over the 1991 through
1995 period, reserve replacement costs have averaged $0.63 per Mcfe, a level
which the Company believes is lower than comparable industry averages. As a
result of increased drilling activity, average daily production increased to
57,875 Mcfepd in September 1996, an increase of 98% over average daily
production of 29,300 Mcfepd in September 1995. Due to economies of scale and
geographic concentration, general and administrative expenses and production
costs have fallen from $1.19 and $0.63 per Mcfe in 1990 to $0.34 and $0.42 per
Mcfe, respectively, for the nine months ended September 30, 1996. The
combination of increased production and decreased operating costs per Mcfe has
resulted in average annual growth in net cash provided by operating activities
of 24% per year from year-end 1990 to year-end 1995. For the nine months ended
3
<PAGE> 4
September 30, 1996, net cash provided by operating activities increased by 208%
over the same period in 1995 to $26.4 million due to these same production and
operating cost factors.
BUSINESS STRATEGY
The Company intends to continue to increase its reserves, cash flows and
underlying net asset value through a balanced growth strategy that includes an
aggressive drilling program, exploitation of advanced technologies and strategic
acquisitions.
Key elements of the Company's strategy include the following:
Aggressive Drilling Program. The Company believes that future reserve
growth will result from a combination of drilling wells on proved undeveloped
acreage in its core areas, step-out and exploratory drilling on the Company's
substantial inventory of undeveloped acreage and exploration efforts in selected
areas outside the Company's core fields. In 1995, the Company drilled 39 net
development wells and 4 net exploration wells, including 38 net development
wells in the Company's AWP Olmos Field and Austin Chalk trend core areas. During
this period, the Company had drilling success rates of 96% for development wells
and 50% for exploratory wells. The Company expects to drill a total of 162 gross
(122 net) wells in 1996, 102 which have been drilled as of September 30, 1996
for a capital cost of $42.4 million to the Company. For 1997, the Company plans
to drill approximately 161 gross wells at an expected capital cost of $86
million to the Company. The Company anticipates that drilling activity in the
AWP Olmos Field will represent 85% of the Company's 1996 drilling budget and 75%
of the Company's 1997 drilling budget. Exploratory drilling is based on a
"controlled risk" approach focusing on regions where the exploration objective
would allow the Company to utilize its technological or geological expertise and
which are in close proximity to known producing horizons. The Company also
reduces its overall risk exposure with respect to exploration and development
activities by entering into joint development agreements with industry partners
to share capital exposure for any individual well. As an example of this
strategy, the Company has active joint development projects with Union Pacific
Resources Company ("UPRC"), Chesapeake Energy Corporation ("Chesapeake") and
Snyder Oil Corporation ("Snyder") in the Austin Chalk trend, under which the
Company serves as operator of a majority of the wells on these properties.
Exploitation of advanced technologies. To minimize the risks associated
with exploration and development drilling and to enhance operating efficiency,
the Company has devoted considerable resources to developing advanced
technological expertise. These technologies include 2-D and 3-D seismic
analysis, AVO (amplitude versus offset) studies and detailed formation depletion
studies. The Company has also attained substantial expertise in horizontal well
technology, having participated in 28 such wells in the Austin Chalk trend, 27
of which have been successful. Additionally, the Company uses innovative
fracturing methods, coiled tubing technology and computer telemetry to monitor
well performance in the AWP Olmos Field. As a result of these technologies, the
Company has enhanced its production yields while reducing its costs per Mcfe.
Strategic acquisitions. The Company is continuously reviewing acquisition
opportunities, including opportunities to acquire substantial undeveloped
acreage for future drilling activities. The Company targets properties in close
proximity to the Company's current reserves, where such reserves can be
increased through development drilling and where improved operating efficiencies
can be achieved. Using these criteria, the Company employs a disciplined,
market-driven approach to acquisitions that can result in varying levels of
annual spending on acquisitions. The Company has substantial experience in
making such acquisitions, having purchased approximately $465.0 million of
producing oil and natural gas properties on behalf of itself and its
co-investors in 122 separate transactions since 1979.
4
<PAGE> 5
THE OFFERING
Securities Offered......... $100,000,000 aggregate principal amount of 6 1/4%
Convertible Subordinated Notes due 2006 (the
"Notes"), excluding $15,000,000 aggregate principal
amount of Notes subject to the Underwriters'
over-allotment option.
Maturity................... The Notes will mature on November 15, 2006 unless
earlier redeemed, repurchased or converted.
Payment of Interest........ Interest on the Notes at the rate of 6 1/4% per
annum is payable semi-annually on May 15 and
November 15 of each year com-
mencing May 15, 1997.
Conversion Right........... The Notes are convertible into shares of the
Company's Common Stock at the option of the holder
at any time after 90 days following the date of
original issuance thereof and prior to maturity,
unless previously redeemed or repurchased, at a
conversion price of $34.6875 per share, subject to
certain adjustments. See "Description of
Notes -- Conversion."
Redemption at the Option of
the Company.............. On or after November 15, 1999, the Company may,
upon at least 15 days notice, redeem the Notes in
whole or in part at the redemption prices set forth
herein, together with accrued and unpaid interest
thereon. See "Description of Notes -- Optional
Redemption."
Repurchase Upon Occurrence
of a Designated Event.... The Notes are required to be repurchased at 101% of
their principal amount, together with accrued and
unpaid interest thereon, at the option of the
holder upon the occurrence of a Designated Event
(as defined herein). Any future credit agreements
or other agreements relating to indebtedness
(including Senior Debt) to which the Company
becomes a party may contain restrictions on the
repurchase of Notes. In the event a Designated
Event occurs at a time when the Company is
prohibited from repurchasing Notes, the Company's
failure to repurchase tendered Notes would
constitute an Event of Default under the Indenture
(as defined herein), which may, in turn, constitute
a further default under existing debt instruments
and may constitute a default under the terms of
other indebtedness that the Company may enter into
from time to time. In such circumstances, the
subordination provisions in the Indenture would
likely restrict payments to the holders of Notes.
See "Description of Notes -- Repurchase at the
Option of Holders" and "Risk Factors -- Limitation
on Repurchase of Notes Upon the Occurrence of a
Designated Event."
Ranking.................... The Notes will be unsecured obligations of the
Company, will be subordinated in right of payment
to all existing and future Senior Debt of the
Company and will rank pari passu with all other
subordinated indebtedness of the Company, if any.
See "Description of Notes -- Subordination of
Notes."
5
<PAGE> 6
Use of Proceeds............ From the estimated net proceeds of $96.0 million,
the Company intends to repay in full all of its
outstanding indebtedness under its existing credit
facilities ($17.2 million at September 30, 1996).
The remaining net proceeds will be added to working
capital to fund the Company's development and
exploration drilling projects and possibly to
acquire oil and gas properties, or for other
general corporate purposes. See "Use of Proceeds."
Listing.................... The Notes have been approved for listing on the New
York Stock Exchange, subject to official notice of
issuance.
Common Stock............... 15,091,384 shares of Common Stock were outstanding
on September 30, 1996. The Common Stock is traded
on the New York Stock Exchange and the Pacific
Stock Exchange under the symbol "SFY."
6
<PAGE> 7
SUMMARY CONSOLIDATED FINANCIAL DATA
The following tables, which have been derived from the Company's audited
financial statements, set forth selected historical financial information for
the Company and should be read in conjunction with the Company's Consolidated
Financial Statements and Notes thereto and "Management's Discussion and Analysis
of Financial Condition and Results of Operations" herein. The financial data for
the nine-month periods ended September 30, 1996 and 1995 were derived from the
unaudited financial statements of the Company that, in management's opinion,
include all adjustments (consisting of only normal recurring adjustments, except
as disclosed below) necessary to present fairly the results for such periods.
The operating results for such periods are not necessarily indicative of the
operating results to be expected for a full fiscal year, and none of the data
presented below are necessarily indicative of future results.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- --------------------------------
1996 1995 1995 1994 1993
------- -------- ------- -------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues............................ $39,179 $19,872 $28,931 $ 25,375 $24,133
Costs and expenses:
General and administrative, net
of reimbursement............... 4,601 3,970 5,256 5,198 5,065
Depreciation, depletion, and
amortization................... 11,314 6,138 8,839 7,905 7,301
Oil and gas production........... 5,749 5,101 6,826 5,639 4,540
Interest expense, net............ 294 1,283 1,115 1,795 598
------- ------- ------- -------- -------
Income before income taxes.......... 17,221 3,380 6,895 4,838 6,629
Provision for income taxes.......... 5,818 859 1,982 1,112 1,732
------- ------- ------- -------- -------
Income before cumulative effect of
change in accounting principle... 11,403 2,521 4,913 3,726 4,897
Cumulative effect of change in
accounting principle............. -- -- -- (16,773)(1) --
------- ------- ------- -------- -------
Net income (loss)................... $11,403 $ 2,521 $ 4,913 $(13,047) $ 4,897
======= ======= ======= ======== =======
Per share data:
Income before cumulative effect
of change in accounting
principle...................... $ 0.87 $ 0.32 $ 0.54 $ 0.56 $ 0.74
======= ======= ======= ======== =======
Net income (loss)................ $ 0.87 $ 0.32 $ 0.54 $ (1.96)(1) $ 0.74
======= ======= ======= ======== =======
Weighted average shares
outstanding...................... 13,140 7,995 9,123 6,644 6,588
OTHER FINANCIAL DATA:
EBITDA(2)........................... $28,829 $10,802 $16,849 $ 14,538 $14,527
Net cash provided by operating
activities....................... 26,351 8,547 14,376 10,395 7,238
Capital expenditures................ 55,996 21,076 40,033 34,531 24,229
Ratio of earnings to fixed
charges(3)
Historical....................... 18.0x 2.0x 3.1x 2.6x 6.8x
Pro forma(4)..................... 5.3x -- 2.1x -- --
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
---------------------------
ACTUAL AS ADJUSTED(5)
-------- --------------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Working capital................................................ $ (5,999) $ 72,831
Total assets................................................... 192,861 272,191
Long-term debt:
Bank borrowings............................................. 17,170 --
6 1/4% Convertible Subordinated Notes due 2006.............. -- 100,000
Stockholders' equity........................................... 134,342 134,342
</TABLE>
(See footnotes on following page)
7
<PAGE> 8
- ---------------
(1) Effective January 1, 1994, the Company adopted a new method of accounting
for earned interests with respect to the limited partnerships for which it
serves as general partner, whereby earned interests are no longer recognized
as income. The effect of the change in 1994 was to increase income before
cumulative effect of change in accounting principle by approximately
$1,047,000 or $.16 per share. The cumulative effect of this change in
accounting principle resulted in an adjustment of $16,772,698, or a loss of
$2.52 per share (after reduction for income taxes of $8,640,481), in the
first quarter of 1994, to apply the new method retroactively, thereby
reducing net income in 1994. The Company believes the change in policy
results in financial statements that better reflect its current business
focus and that are more comparable to current practices in the oil and gas
exploration and production business. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- General" and
Note 2 to the Company's Consolidated Financial Statements.
(2) EBITDA is defined for this purpose as income (loss) before taking into
consideration the cumulative effect of change in accounting principle and
net interest expense, income taxes and depreciation, depletion, and
amortization. EBITDA should not be considered as an alternative to earnings
(losses) as an indicator of the Company's financial performance or to cash
flows as a measure of liquidity, but rather to provide additional
information related to debt service capability.
(3) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense 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.
(4) Pro forma for the offering and for the application of a portion of the net
proceeds of the offering to repay $17.2 million of existing indebtedness.
See "Use of Proceeds."
(5) As adjusted to give effect to the sale by the Company of the 6 1/4%
Convertible Subordinated Notes due 2006 offered hereby and the application
of the net proceeds as described under "Use of Proceeds."
8
<PAGE> 9
RESERVE AND PRODUCTION DATA
The following table sets forth certain summary information as of December
31, 1995 with respect to estimates prepared by the Company, and audited by H.J.
Gruy and Associates, Inc., independent petroleum engineers ("Gruy"), of the
Company's proved oil and gas reserves, the future net revenues therefrom and
their PV-10 Value. Estimates are based upon weighted average prices of $18.07
per Bbl of oil and $2.41 per Mcf of natural gas at December 31, 1995, holding
prices constant throughout the life of the properties in accordance with
regulations of the Securities and Exchange Commission. This information is based
upon numerous assumptions and is subject to change due to numerous factors. See
"Business and Properties -- Properties and -- Oil and Gas Reserves" and "Risk
Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues."
<TABLE>
<CAPTION>
DECEMBER 31, 1995
----------------------
PROVED TOTAL
DEVELOPED PROVED
--------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
ESTIMATED NET PROVED RESERVES:
Oil and condensate (MBbl).......................................... 3,313 5,422
Natural gas (MMcf)................................................. 81,532 143,568
Total reserves (MMcfe)............................................. 101,411 176,099
Future net revenues................................................ $ 162,723 $281,647
PV-10 Value........................................................ $ 85,537 $147,038
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
----------------- ----------------------------
1996 1995 1995 1994 1993
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbl)............................... 459 394 545 467 324
Natural gas (MMcf)(1).................... 10,833 5,482 7,914 6,799 5,422
Gas equivalents (MMcfe).................. 13,589 7,846 11,187 9,601 7,369
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)............................ $18.96 $15.61 $15.66 $14.35 $15.10
Natural gas (per Mcf)(2)................. 2.31 1.65 1.77 1.93 1.96
SELECTED DATA PER MCFE:
Production costs......................... $ 0.42 $ 0.65 $ 0.61 $ 0.59 $ 0.62
Depreciation, depletion, and
amortization.......................... 0.83 0.78 0.79 0.82 0.99
General and administrative(3)............ 0.34 0.51 0.47 0.54 0.69
Reserve replacement cost(4).............. N/A N/A 0.61 0.79 0.70
WELLS DRILLED:
Gross.................................... 102 46 76 44 34
Net...................................... 76 24 42 16 9
TOTAL RESERVES (MMCFE) ADDED BY:
Exploration and development.............. N/A N/A 72,425 24,804 13,502
Acquisitions............................. N/A N/A 5,692 12,879 26,469
</TABLE>
- ---------------
(1) Natural gas production for 1995, 1994, 1993, and the nine-month periods
ended September 30, 1996 and 1995 includes 1,211, 1,358, 1,581, 868 and 917
MMcf, respectively, delivered under a volumetric production payment pursuant
to which the Company is obligated to deliver certain monthly quantities of
natural gas. Future volumes associated with the volumetric production
payment are not included in the Company's estimate of net reserves. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- General" and Note 9 to the Consolidated Financial Statements.
(Footnotes continued on following page)
9
<PAGE> 10
(2) The above natural gas prices reflect the high Btu content of the natural gas
produced from the Company's AWP Olmos and Austin Chalk properties. Gas is
sold on the basis of price per MMBtu, which measures the heating equivalent
of such gas. The prices per Mcf above (Mcf being strictly a physical measure
of natural gas volumes) are therefore higher than the prices which would be
paid for natural gas with a lower Btu content.
(3) Net of reimbursements.
(4) Calculated for a three-year period ending with the year presented by
dividing total acquisition, exploration and development costs (excluding
future development costs) incurred during such period by net reserves added
during the period (excluding revisions).
10
<PAGE> 11
RISK FACTORS
In addition to the other information contained in this Prospectus, the
following factors should be considered carefully in evaluating an investment in
the Notes offered hereby. The statements contained herein that are not
historical facts are forward-looking statements as that term is defined in
Section 21E of the Securities Exchange Act of 1934, as amended, and therefore
involve a number of risks and uncertainties. The actual results of the future
events described in such forward-looking statements in this Prospectus,
including those regarding the Company's financial results, levels of oil and gas
production or revenue, capital expenditures and capital resource activities
could differ materially from those estimated, anticipated or projected. Among
the factors that could cause actual results to differ materially are: general
economic conditions, competition and government regulations, fluctuations in oil
and natural gas prices and the factors set forth in "Risk Factors" below, as
well as the risks and uncertainties set forth from time to time in the Company's
other public reports filed with the Commission and incorporated by reference
herein.
SUBORDINATION AND ABSENCE OF FINANCIAL COVENANTS
The Notes are subordinated in right of payment to all existing and future
Senior Debt of the Company. "Senior Debt" is defined under the heading
"Description of Notes -- Subordination of Notes." As a result of such
subordination, in the event of any insolvency, liquidation or reorganization of
the Company or upon acceleration of the Notes due to an Event of Default, the
assets of the Company will be available to pay obligations on the Notes and any
other subordinated indebtedness of the Company only after all Senior Debt has
been paid in full, and there may not be sufficient assets remaining to pay
amounts due on any or all of the Notes or any other subordinated indebtedness of
the Company then outstanding. The Indenture does not prohibit or limit the
incurrence of Senior Debt or the incurrence of other indebtedness and other
liabilities by the Company or its subsidiaries. As of September 30, 1996, the
Company had approximately $17.2 million of indebtedness outstanding that would
have constituted Senior Debt. It is anticipated that, immediately after the
application of the net proceeds from this offering, the Company will have no
Senior Debt outstanding; however, any future borrowings under the Company's
existing credit facilities will constitute Senior Debt, and other indebtedness
incurred by the Company in the future may constitute Senior Debt. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
The Indenture does not contain any financial performance covenants.
Consequently, the Company is not required under the Indenture to meet any
financial tests such as those that measure the Company's working capital,
interest coverage, fixed charge coverage or net worth in order to maintain
compliance with the terms of the Indenture. See "Description of
Notes -- Repurchase at the Option of Holders."
LIMITATION ON REPURCHASE OF NOTES UPON THE OCCURRENCE OF A DESIGNATED EVENT
Upon the occurrence of a Designated Event, each holder of Notes may require
the Company to repurchase all or a portion of such holder's Notes at 101% of
their principal amount. If a Designated Event were to occur, there can be no
assurance that the Company would have sufficient financial resources, or would
be able to arrange financing, to pay the repurchase price for all Notes tendered
by the holders thereof. Any future credit agreements or other agreements
relating to indebtedness (including Senior Debt) to which the Company becomes a
party may contain restrictions on the repurchase of Notes. In the event a
Designated Event occurs at a time when the Company is prohibited from
repurchasing the Notes, the Company could seek the consent of its lenders to
repurchase the Notes or could attempt to refinance the borrowings that contain
such prohibition. If the Company does not obtain such consent or refinance such
borrowings, the Company would remain prohibited from repurchasing Notes. In such
case, the Company's failure to repurchase tendered Notes would constitute an
Event of Default under the Indenture which may, in turn, constitute a further
default under certain of the Company's existing debt instruments and may
11
<PAGE> 12
constitute a default under the terms of other indebtedness that the Company may
incur from time to time. In such circumstances, the subordination provisions in
the Indenture would likely prohibit payments to holders of Notes. See
"Description of Notes -- Repurchase at the Option of Holders."
VOLATILITY OF OIL AND GAS PRICES AND MARKETS
The Company's profitability is substantially dependent on prevailing prices
for oil and natural gas. The amounts of and price obtainable for the Company's
oil and gas production will be affected by market factors beyond the Company's
control. Such factors include the extent of domestic production, the level of
imports of foreign oil and gas, the general level of market demand on a
regional, national and worldwide basis, domestic and foreign economic conditions
that determine levels of industrial production, political events in foreign
oil-producing regions and variations in governmental regulations and tax laws or
the imposition of new governmental requirements upon the oil and gas industry.
Prices for oil and gas are subject to wide fluctuation in response to relatively
minor changes in supply of and demand for oil and gas, market uncertainty and a
variety of additional factors that are beyond the control of the Company. In
addition, the marketability of the Company's production depends in part upon the
availability, proximity and capacity of gathering systems, pipelines and
processing facilities. A substantial and prolonged decline in oil and gas prices
could have a material adverse effect upon the Company.
The Company currently emphasizes the exploration and development of natural
gas reserves. See "Business and Properties -- General." As a result of changes
in recent years in the natural gas market regulatory structure and volatility in
the market price for natural gas, most producers and purchasers are unwilling to
enter into long-term purchase and sale contracts. Accordingly, most of the
Company's gas production is sold on the "spot market," where producers and
purchasers negotiate sales on a short-term (usually a 30-day) basis.
Accordingly, the stability of the Company's future revenues is vulnerable to
short-term fluctuations in the price of natural gas. See "-- Effect of Price
Risk Management."
Under Commission regulations, applicable to entities which account for
their investments in oil and gas properties using the full-cost accounting
rules, on a quarterly basis the Company confirms that the PV-10 Value of its
proved reserves (plus certain amounts for unproved properties) exceeds the
capitalized costs of oil and gas properties carried on its balance sheet. This
test must be performed using oil and gas prices at the end of the applicable
period, rather than historical amounts or averages calculated over longer
periods. Thus, while the Company has never been required to write down its asset
base, and at December 31, 1995 there was a substantial excess of reserves over
capitalized costs under the "ceiling test," declines in oil and gas prices, if
sustained, could require a writedown of the value of the Company's oil and gas
properties unless at the same time the Company had sufficient net additional
reserves to offset the effect of any such decline in oil and gas prices. It is
possible that such a writedown could be required even if there were only a
temporary decline in prices. Although any such writedown would not affect cash
flow from operating activities, it would constitute a charge to earnings.
REPLACEMENT AND EXPANSION OF RESERVES
The Company's success will be largely dependent on its ability to replace
and expand its oil and gas reserves through the acquisition of producing
properties and the exploration for and development of oil and gas reserves, both
of which involve substantial risks. Without successful drilling or acquisition
ventures, the Company will be unable to replace the reserves being depleted by
production, and its assets and revenues including the reserves will decline.
There can be no assurance that the Company's acquisition and exploration and
development activities will result in the replacement of, or additions to, the
Company's reserves. Successful acquisition of producing properties generally
requires accurate assessments of recoverable reserves, future oil and gas prices
and operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact, and as estimates, their
accuracy is inherently uncertain.
12
<PAGE> 13
FUTURE CAPITAL REQUIREMENTS
The Company makes and will continue to make substantial capital
expenditures to further explore and develop its properties and to acquire
additional oil and gas properties. These expenditures are currently anticipated
to be $134.0 million for the remaining three months of 1996 and for 1997.
Proceeds from this offering and, to the extent available, cash flows from
operations will be used to fund these expenditures. The Company may also seek
additional capital from traditional reserve base borrowings, equity and debt
offerings, joint ventures and other sources. Furthermore, the Company may seek
to raise capital through production payment financing and vendor financing. The
Company's ability to access additional capital will depend on its continued
success in exploring for and developing its reserves and the status of the
capital markets at the time such capital is sought. Accordingly, there can be no
assurance that capital will be available to the Company from any source or that,
if available, it will be on terms acceptable to the Company. Should sufficient
capital not be available, the exploration and development of the Company's
properties could be delayed and, accordingly, the implementation of the
Company's business strategy would be adversely affected.
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
Estimates of the Company's proved developed oil and gas reserves and future
net revenues therefrom appearing elsewhere herein are based on reserve reports
audited by independent petroleum engineers. The estimation of reserves requires
substantial judgment on the part of the petroleum engineers, resulting in
imprecise determinations, particularly with respect to new discoveries.
Estimates of proved undeveloped reserves, which comprise a significant portion
of the Company's total reserves, are by their nature less certain. The accuracy
of any reserve estimate depends on the quality of available data as well as
engineering and geological interpretation and judgment. Actual future
production, oil and gas prices, revenues, taxes, capital expenditures, operating
expenses, geologic success and quantities of recoverable oil and gas resources
may vary substantially from those assumed in the estimates, may result in
revisions to such estimates and could materially affect the estimated quantities
and related PV-10 Value of reserves set forth in this Prospectus. The estimates
of future net revenues reflect oil and gas prices as of the date of estimation,
without escalation, except where changes in prices were fixed under existing
contracts. There can be no assurance, however, that such prices will be realized
or that the estimated production volumes will be produced during the periods
indicated. Future performance that deviates significantly from the reserve
reports could have a material adverse effect on the Company. See "Business and
Properties -- Properties and -- Oil and Gas Reserves."
The estimates of future net revenues and their present values assume that
some portion of the limited partnerships in which the Company owns interests
will achieve payout status. At payout, the Company's percentage ownership of the
limited partnerships' reserves increases. The primary assumptions utilized for
purposes of such estimates consist of (i) the continuation of oil and gas prices
realized by the partnerships at year-end 1995 through the life of the properties
owned by the partnerships and (ii) the continued ownership of such properties.
Only three of the limited partnerships in which the Company owns an interest had
achieved payout status at the date of this Prospectus and achievement of payout
status for the remaining partnerships will depend not only upon prices at which
future production is sold, but also upon whether individual properties are sold
prior to depletion and the prices received in such sales. See "-- Volatility of
Oil and Gas Prices and Markets" and "Business and Properties -- Partnerships."
EXPLORATION AND DEVELOPMENT RISKS
Exploration and development of oil and gas reserves involve a high degree
of risk that no commercial production will be obtained or that the production
will be insufficient to recover drilling and completion costs. The cost of
drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous
13
<PAGE> 14
factors, including title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of equipment.
Furthermore, completion of a well does not assure a profit on the investment or
a recovery of drilling, completion and operating costs. See "Business and
Properties -- Exploration and Development Drilling Activities."
OPERATING HAZARDS AND UNINSURED RISKS
In addition to the substantial risk that wells drilled will not be
productive, hazards such as unusual or unexpected geologic formations,
pressures, downhole fires, mechanical failures, blowouts, cratering, explosions,
uncontrollable flow of oil, gas or well fluids, pollution and other
environmental risks are inherent in oil and gas exploration and production.
These hazards could result in substantial losses to the Company due to injury
and loss of life, severe damage to and destruction of property and equipment,
pollution and other environmental damage and suspension of operations. The
Company carries insurance which it believes is in accordance with customary
industry practices, but, as is common in the oil and gas industry, the Company
does not fully insure against all risks associated with its business either
because such insurance is not available or because the cost thereof is
considered prohibitive.
EFFECT OF PRICE RISK MANAGEMENT
To the extent that price floors or caps are purchased for a portion of the
Company's production but are not needed, or to the extent that future sales are
made at prices below ultimate future market prices, funds so spent will have
been lost or income realized from sale of production may be reduced. Therefore,
the Company intends to expend only limited amounts to hedge pricing risks. See
"Business and Properties -- Price Risk Management."
RISKS OF PURCHASING INTERESTS IN OIL AND GAS PROPERTIES
Although the Company emphasizes reserve growth through drilling, it expects
to make acquisitions of oil and gas properties from time to time. The Company
generally focuses most of its title and valuation efforts on the more
significant properties. It is generally not feasible for the Company to review
in-depth every property it purchases and all records with respect to such
properties. However, even an in-depth review of properties and records may not
necessarily reveal existing or potential problems, nor will it permit a buyer to
become familiar enough with the properties to assess fully their deficiencies
and capabilities. Evaluation of future recoverable reserves of oil, gas and
natural gas liquids, which is an integral part of the property selection
process, is a process that depends upon evaluation of existing geological,
engineering and production data, some or all of which may prove to be unreliable
or not indicative of future performance. See "-- Uncertainty of Estimates of
Reserves and Future Net Revenues." To the extent the seller does not operate the
properties, obtaining access to properties and records may be more difficult.
Even when problems are identified, the seller may not be willing or financially
able to give contractual protection against such problems, and the Company may
decide to assume environmental and other liabilities in connection with acquired
properties. See "Business and Properties -- Oil and Gas Acreage."
FOREIGN ACTIVITIES
In the last several years, the Company has undertaken exploration and
development activities in Russia and New Zealand. The Company is also pursuing
development opportunities in Venezuela. In Russia, the Company has entered into
several agreements with a Russian joint stock company to develop and produce
reserves in two fields in Western Siberia under which the Company is entitled to
receive a minimum 5% net profits interest in the properties. In July 1996, the
Company entered into a partnership agreement which provides for the Company to
contribute its rights under these agreements to the partnership and for the
partners to share equally revenues and costs of developing the project, along
with the Russian company. The partnership is to be funded upon
14
<PAGE> 15
fulfillment of certain conditions and completion of certain further arrangements
with the Russian company. The Company is also performing certain seismic work on
136,500 acres in two adjacent onshore areas located in New Zealand pursuant to
Exploration Permits which provide for certain work to be performed in stages
through the year 2001. In addition, the Company is pursuing several cooperative
ventures in Venezuela. The Company's investment in these projects was
approximately $11.2 million at September 30, 1996. Russia has experienced and
continues to experience social, political and economic instability, and all of
the Company's operations overseas are subject to various additional risks. There
can be no assurance that future developments in these regions, over which the
Company has no control, will not impair the Company's operations in these
regions or result in a loss of part or all of the Company's investment.
COMPETITION
The Company operates in a highly competitive environment. The Company
competes with major integrated and independent energy companies for the
acquisition of desirable oil and natural gas properties, as well as for the
equipment and labor required to develop and operate such properties. Many of
these competitors have financial and other resources substantially greater than
those of the Company. See "Business and Properties -- Competition."
GOVERNMENTAL AND ENVIRONMENTAL REGULATION
The production of oil and natural gas is subject to regulation under a wide
range of United States federal and state statutes, rules, orders and
regulations. State and federal statutes and regulations require permits for
drilling, reworking and recompletion operations, drilling bonds and reports
concerning operations. Most states in which the Company owns and operates
properties have regulations governing conservation matters, including provisions
for the unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from oil and natural gas wells and
the regulation of the spacing, plugging and abandonment of wells. Many states
also restrict production to the market demand for oil and natural gas and
several states have indicated interest in revising applicable regulations for
oil and natural gas production. These regulations may limit the rate at which
oil and natural gas could otherwise be produced from the Company's properties.
See "Business and Properties -- Regulations."
Various federal, state and local laws and regulations relating to the
protection of the environment may affect the Company's operations and costs. In
particular, the Company's production operations and its use of facilities for
treating, processing or otherwise handling hydrocarbons and wastes therefrom are
subject to stringent environmental regulation. Although compliance with these
regulations increases the cost of Company operations, such compliance has not
had a material effect on the Company's capital expenditures, earnings or
competitive position. Environmental regulations have historically been subject
to frequent change by regulatory authorities and the Company is unable to
predict the ongoing cost of complying with these laws and regulations or the
future impact of such regulations on its operations. A significant discharge of
hydrocarbons into the environment could, to the extent such event is not
insured, subject the Company to substantial expense. See "Business and
Properties -- Regulations -- Environmental Regulations."
DEPENDENCE ON KEY PERSONNEL
The Company depends, and will continue to depend in the foreseeable future,
on the services of its officers and key employees with extensive experience and
expertise in evaluating and analyzing producing oil and gas properties and
drilling prospects, maximizing production from oil and gas properties and
marketing oil and gas production. The ability of the Company to retain its
officers and key employees is important to the continued success and growth of
the Company. The loss of key personnel could have a material adverse effect on
the Company. See "Management."
15
<PAGE> 16
LIABILITY AS GENERAL PARTNER; CONFLICTS OF INTEREST
The Company serves as the managing general partner of 103 limited
partnerships, which had invested over $478.0 million in oil and gas activities
at September 30, 1996. These limited partnerships had less than $8.0 million of
indebtedness at September 30, 1996, virtually all of which is owed to the
Company. However, the Company remains contingently liable for their obligations
as general partner, including responsibility for their day-to-day operations,
and liabilities which cannot be repaid from partnership assets or insurance
proceeds. In the future, the Company might be exposed to litigation in
connection with partnership activities, or find it necessary to advance funds on
behalf of certain partnerships to protect the value of their oil and gas
properties. Conversely, the Company might be prohibited from acquiring certain
property interests if to do so would conflict with the interests of limited
partnerships which it manages. See "Business and Properties -- Partnerships."
ABSENCE OF PUBLIC MARKET FOR THE NOTES
There is currently no public trading market for the Notes. Although the
Notes have been approved for listing on the New York Stock Exchange, subject to
official notice of issuance , there can be no assurance that an active trading
market will develop for the Notes, or that holders of the Notes will be able to
sell their Notes on acceptable terms. The Underwriters have indicated that they
intend to make a market in the Notes; however, they are not obligated to do so,
and any such market-making may be discontinued at any time without notice. The
Notes may trade at a discount from the initial public offering price, depending
upon prevailing interest rates, the market price for similar securities, the
market price for the Common Stock and other factors. In addition, prices for the
Common Stock will be determined by the market and may be influenced by many
factors, including the financial and operating performance of the Company,
investor perceptions of the Company, the depth and liquidity of the market for
the Company's Common Stock, oil and gas prices and general economic conditions.
Although the Common Stock is currently traded on the New York Stock Exchange and
the Pacific Stock Exchange, there can be no assurance that the Common Stock will
continue to be traded on any active trading market in the future.
16
<PAGE> 17
USE OF PROCEEDS
The net proceeds to the Company from the sale of the Notes offered hereby
will be approximately $96.0 million, ($110.5 million assuming exercise of the
Underwriters' over-allotment option), after deducting estimated underwriting
discount and expenses of the offering payable by the Company. From these
proceeds, the Company intends to repay in full all of its borrowings under the
credit facilities described below, which amount was $17.2 million at September
30, 1996. The remaining net proceeds will be used to fund exploratory and
development drilling projects during the remainder of 1996 and 1997, and
possibly to acquire oil and gas properties, or for other general corporate
purposes. The allocation of the Company's net proceeds from this offering,
together with other available capital, among these categories of anticipated
expenditures is discretionary and will depend upon future events that cannot be
predicted, including the actual results and costs of future exploratory and
development drilling and other activities, the availability and cost of oil and
gas properties meeting the Company's acquisition criteria, the Company's net
cash flows from operating activities and other matters beyond the control of the
Company.
The Company has two credit facilities. The first facility is a $100.0
million revolving line of credit which currently has a borrowing base of $30.0
million. For balances up to $17.5 million, this facility bears interest at
either the lead bank's base rate or at the London Interbank Offered Rate
("LIBOR") plus 1%. For balances between $17.5 million and $26.25 million, the
Company has the option to incur interest at the lead bank's base rate plus 0.25%
or at LIBOR plus 1.25%. For amounts in excess of $26.25 million, the LIBOR
option is set at LIBOR plus 1.5%. The outstanding amount under this facility at
September 30, 1996 was $17.0 million, all of which was bearing interest under
the LIBOR rate option at rates ranging from 6.5620% to 6.8125%. Such funds were
borrowed primarily to finance the Company's working capital and capital
expenditures needs. The Company's other credit facility is a $7.0 million
revolving line of credit bearing interest at the bank's base rate less 0.25%. At
September 30, 1996, $170,000 was outstanding under this facility, bearing
interest at 8%. Both of these credit facilities extend through September 30,
1999. The $7.0 million credit facility is the Company's only secured facility.
Until net proceeds of the offering are utilized for purposes described
above, they will be invested in interest bearing bank accounts, U.S. government
securities, other investment grade debt securities and other short-term
investments.
17
<PAGE> 18
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Common Stock trades on the New York Stock Exchange and the Pacific
Stock Exchange under the symbol "SFY." At September 30, 1996, the Company had
approximately 532 stockholders of record. The following table sets forth the
range of high and low quarterly closing sales prices for the Common Stock of the
Company as reported by the New York Stock Exchange for the periods indicated.
<TABLE>
<CAPTION>
HIGH LOW
------- -------
<S> <C> <C>
1996
Fourth Quarter (Through November 19, 1996)............................ $28.125 $23.750
Third Quarter......................................................... 24.875 17.500
Second Quarter........................................................ 18.125 13.000
First Quarter......................................................... 14.125 10.875
1995
Fourth Quarter........................................................ 12.625 7.750
Third Quarter......................................................... 9.625 8.250
Second Quarter........................................................ 10.125 8.500
First Quarter......................................................... 9.875 8.000
1994
Fourth Quarter........................................................ 11.375 9.500
Third Quarter......................................................... 10.500 9.250
Second Quarter........................................................ 10.125 9.000
First Quarter......................................................... 11.250 8.500
</TABLE>
The above prices for the first three quarters of 1994 have been revised to
reflect a 10% Common Stock dividend declared and paid in September 1994. On
November 19, 1996, the last reported sale price for the Common Stock on the New
York Stock Exchange was $27.750 per share.
Since the Company's inception, no cash dividends have been declared on its
Common Stock, and the Company does not expect to declare cash dividends in the
foreseeable future. The Company currently intends to continue a policy of using
retained earnings for expansion of its business. Under its current credit
arrangements, the Company may not declare cash dividends on its Common Stock
that exceed $2.0 million in any fiscal year.
18
<PAGE> 19
CAPITALIZATION
The following table sets forth the capitalization of the Company at
September 30, 1996, and as adjusted to reflect the sale by the Company of the
Notes offered hereby and the application of the net proceeds as described under
"Use of Proceeds." This information should be read in conjunction with the
Company's Consolidated Financial Statements and the Notes thereto and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" presented elsewhere in this Prospectus.
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
---------------------
AS
ACTUAL ADJUSTED
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents............................................ $ 1,986 $ 80,816
======== ========
Long-term debt, including current portion
Bank borrowings(1)................................................. $ 17,170 $ --
6 1/4% Convertible Subordinated Notes due 2006..................... -- 100,000
Stockholders' equity
Preferred Stock -- $.01 par value; 5,000,000 authorized shares; no
shares issued and outstanding................................... -- --
Common Stock -- $.01 par value; 35,000,000 authorized shares;
15,091,384 issued and outstanding shares(2)..................... 151 151
Additional paid-in capital......................................... 100,702 100,702
Retained earnings.................................................. 33,489 33,489
-------- --------
Total stockholders' equity................................. 134,342 134,342
-------- --------
Total capitalization....................................... $151,512 $234,342
======== ========
</TABLE>
- ---------------
(1) See Note 4 to the Company's Consolidated Financial Statements for additional
information concerning the Company's bank borrowings.
(2) Excludes (a) 1,232,646 shares issuable upon exercise of employee and
director stock options outstanding as of September 30, 1996 and (b) 41,250
shares issuable upon the exercise of stock options granted to other
individuals outstanding as of September 30, 1996.
19
<PAGE> 20
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data of the Company for each
of the five years in the period ended December 31, 1995, are derived from the
Company's Consolidated Financial Statements, which have been audited. The
selected consolidated financial data for the nine-month periods ended September
30, 1996 and 1995 are unaudited, and, in the opinion of management, include all
adjustments (consisting of only normal recurring adjustments, except as
disclosed below) necessary for a fair presentation of the results for such
interim periods. Results for the interim periods are not necessarily indicative
of results to be expected for the entire year. The selected consolidated
financial data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Company's
Consolidated Financial Statements and the Notes thereto included elsewhere
herein.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- ------------------------------------------------------------
1996 1995 1995 1994 1993 1992 1991
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Oil and gas sales........................ $ 33,733 $ 15,208 $ 22,528 $ 19,802 $ 15,536 $ 12,420 $ 8,362
Earned interests and fees(1)............. 616 339 590 702 4,072 2,716 2,232
Supervision fees......................... 3,277 2,838 3,839 3,751 3,719 3,444 3,363
Interest income.......................... 35 132 212 48 202 113 192
Other, net............................... 1,518 1,355 1,762 1,072 604 516 541
-------- -------- -------- -------- -------- -------- --------
Total revenues..................... 39,179 19,872 28,931 25,375 24,133 19,209 14,690
-------- -------- -------- -------- -------- -------- --------
Costs and expenses:
General and administrative, net of
reimbursement.......................... 4,601 3,970 5,256 5,198 5,065 4,977 4,656
Depreciation, depletion, and
amortization........................... 11,314 6,138 8,839 7,905 7,301 4,906 3,843
Oil and gas production................... 5,749 5,101 6,826 5,639 4,540 3,934 2,442
Interest expense, net.................... 294 1,283 1,115 1,795 598 76 --
Other expenses........................... -- -- -- -- -- 628 --
-------- -------- -------- -------- -------- -------- --------
Total costs and expenses........... 21,958 16,492 22,036 20,537 17,504 14,521 10,941
-------- -------- -------- -------- -------- -------- --------
Income before income taxes................. 17,221 3,380 6,895 4,838 6,629 4,688 3,749
Provision for income taxes................. 5,818 859 1,982 1,112 1,732 1,518 1,236
-------- -------- -------- -------- -------- -------- --------
Income before cumulative effect of change
in accounting principle.................. 11,403 2,521 4,913 3,726 4,897 3,170 2,513
Cumulative effect of change in accounting
principle................................ -- -- -- (16,773)(1) -- 915(2) --
-------- -------- -------- -------- -------- -------- --------
Net income (loss).......................... $ 11,403 $ 2,521 $ 4,913 $(13,047) $ 4,897 $ 4,085 $ 2,513
======== ======== ======== ======== ======== ======== ========
Per share data:
Primary:
Income before cumulative effect of
change in accounting principle....... $ 0.87 $ 0.32 $ 0.54 $ 0.56 $ 0.74 $ 0.52 $ 0.47
Cumulative effect of change in
accounting principle................. -- -- -- (2.52)(1) -- 0.15(2) --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)...................... $ 0.87 $ 0.32 $ 0.54 $ (1.96) $ 0.74 $ 0.67 $ 0.47
======== ======== ======== ======== ======== ======== ========
Fully diluted:
Income before cumulative effect of
change in accounting principle....... $ 0.87 $ 0.32 $ 0.54 $ 0.56 $ 0.70 $ 0.52 $ 0.47
Cumulative effect of change in
accounting principle................. -- -- -- (2.52)(1) -- 0.15(2) --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)...................... $ 0.87 $ 0.32 $ 0.54 $ (1.96) $ 0.70 $ 0.67 $ 0.47
======== ======== ======== ======== ======== ======== ========
Weighted average shares outstanding(3)..... 13,140 7,995 9,123 6,644 6,588 6,135 5,363
</TABLE>
(Table continued on following page)
20
<PAGE> 21
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- ------------------------------------------------------------
1996 1995 1995 1994 1993 1992 1991
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
OTHER FINANCIAL DATA:
EBITDA(4).................................. $ 28,829 $ 10,802 $ 16,849 $ 14,538 $ 14,527 $ 10,585 $ 7,592
Net cash provided by operating
activities............................... 26,351 8,547 14,376 10,395 7,238 6,349 5,912
Capital expenditures....................... 55,996 21,076 40,033 34,531 24,229 34,401 7,985
Ratio of earnings to fixed charges(5)
Historical............................... 18.0x 2.0x 3.1x 2.6x 6.8x 7.5x 10.3x
Pro forma(6)............................. 5.3x -- 2.1x -- -- -- --
BALANCE SHEET DATA:
Working capital............................ $ (5,999) $ 19,259 $ 3,247 $(13,137) $ 9,742 $ 2,953 $ (2,992)
Total assets............................... 192,861 156,980 175,253 135,673 160,893 100,243 101,422
Long-term debt:
Bank borrowings.......................... 17,170 -- -- 27,229 2,650 -- 23,380
6 1/2% Convertible Subordinated
Debentures due 2003(7)................. -- 28,750 28,750 28,750 28,750 -- --
Stockholders' equity....................... 134,342 90,960 93,346 42,127 54,466 49,281 38,660
</TABLE>
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(1) Effective January 1, 1994, the Company adopted a new method of accounting
for earned interests with respect to the limited partnerships for which it
serves as general partner, whereby earned interests are no longer recognized
as income. The effect of the change in 1994 was to increase income before
cumulative effect of change in accounting principle by approximately
$1,047,000 or $.16 per share. The cumulative effect of this change in
accounting principle resulted in an adjustment of $16,772,698, or a loss of
$2.52 per share (after reduction for income taxes of $8,640,481), in the
first quarter of 1994, to apply the new method retroactively, thereby
reducing net income in 1994. The Company believes the change in policy
results in financial statements that better reflect its current business
focus and that are more comparable to current practices in the oil and gas
exploration and production business. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- General" and
Note 2 to the Company's Consolidated Financial Statements.
(2) In the fourth quarter of 1992, the Company elected to adopt SFAS No. 109,
effective beginning January 1, 1992. The cumulative effect of this change
resulted in an increase in net income of $915,000 or $.16 per share in 1992.
The effect of this change on income tax expense (exclusive of cumulative
effect adjustment) for the year ended December 31, 1992 was not material.
(3) Amounts have been retroactively restated in all periods presented to give
recognition for an equivalent change in capital structure as a result of a
10% stock dividend in September 1994. See Note 7 to the Company's
Consolidated Financial Statements.
(4) EBITDA is defined for this purpose as income (loss) before taking into
consideration the cumulative effect of change in accounting principle and
net interest expense, income taxes and depreciation, depletion, and
amortization. EBITDA should not be considered as an alternative to earnings
(losses) as an indicator of the Company's financial performance or to cash
flows as a measure of liquidity, but rather to provide additional
information related to debt service capability.
(5) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense 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.
(6) Pro forma for the offering and for the application of a portion of the net
proceeds of the offering to repay $17.2 million of existing indebtedness.
See "Use of Proceeds."
(7) The $28,750,000 principal amount of 6 1/2% Convertible Subordinated
Debentures due 2003 was converted on August 6, 1996 into 2,343,108 shares of
the Company's Common Stock.
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<PAGE> 22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the Company's
Consolidated Financial Statements and Notes thereto and the Selected
Consolidated Financial Data included elsewhere in this Prospectus.
GENERAL
The Company was formed in 1979 and, from 1985 to 1991, grew primarily
through the acquisition of producing properties funded through limited
partnership financing. Commencing in 1991, the Company began to re-emphasize the
addition of reserves through exploration and development drilling activity while
significantly reducing its reliance on limited partnership financing. This
emphasis on exploration and development drilling has led to additions of
increasing quantities of reserves in each of 1994, 1995, and the first nine
months of 1996.
The Company's revenue is primarily comprised of oil and gas sales
attributable to properties in which the Company owns a direct or indirect
interest. Additionally, prior to 1994, the Company recorded earned interests and
fees from limited partnerships and joint ventures. Effective January 1, 1994,
the Company changed its revenue recognition policy for earned interests. The
cumulative effect in 1994 of this change in accounting principle resulted in a
one-time accounting adjustment of $16.8 million, or a loss of $2.52 per share
(after reduction for income taxes of $8.6 million), from applying the new method
retroactively. Earned interests represented revenues in the form of interests in
proved developed oil and gas properties conveyed to limited partnerships and
joint ventures formed in connection with the Company's organization and
management of limited partnerships and joint ventures, representing the
difference between the Company's capital contributions to each limited
partnership or joint venture and its earned revenue interest in the limited
partnership's or venture's properties (based upon the expected levels of cash
distributions to the limited partners or joint venturers). Under the Company's
current method of accounting such amounts will not be recognized as income,
thereby reducing the Company's investment in oil and gas property. The Company
believes the change in policy results in financial statements that better
reflect its business focus and that are more comparable to prevalent practices
in the oil and gas exploration and production industry.
In May 1992, the Company purchased interests in certain wells from the
Manville Corporation for $14.3 million using funds provided by the Company's
sale of a volumetric production payment in these properties to a subsidiary of
Enron Corp. Net proceeds from the sale of the production payment of
approximately $13.8 million were recorded as deferred revenues. Deliveries under
the volumetric production payment are recorded as oil and gas sales revenues
which are offset by a corresponding reduction of deferred revenues. Under this
arrangement, the Company is required to deliver a fixed quantity of hydrocarbons
produced from the properties over specified periods through October 2000.
Volumes remaining to be delivered under the volumetric production payment
(approximately 4.1 Bcf and 3.3 Bcf at December 31, 1995 and September 30, 1996,
respectively) are not included in the Company's proved reserves. Under the
volumetric production payment, hydrocarbons produced in excess of the amount
required to be delivered are sold by the Company for its own account.
RESULTS OF OPERATIONS
Comparison of Nine Months Ended September 30, 1996 and 1995
Revenues. The Company's revenues increased 97% during the first nine months
of 1996 from the comparative period in 1995, due primarily to the increase in
oil and gas sales.
Oil and Gas Sales. Oil and gas sales increased 122% to $33.7 million in the
first three quarters of 1996, compared to $15.2 million for the comparative
period in 1995. The 98% increase in natural
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<PAGE> 23
gas production and the 17% increase in oil production were primarily the result
of production from recent drilling activity, most notably from the Company's two
primary development areas, the AWP Olmos Field and the Austin Chalk trend. The
Company's net sales volume (including the volumetric production payment) in the
first nine months of 1996 increased by 73% or 5.7 Bcf over volumes in the
comparable 1995 period. Oil and gas sales were also aided by a 21% and 40%
increase in prices received for oil and gas, respectively, between the two
periods. Average prices for oil increased from $15.61 per Bbl in the nine-month
period of 1995, to $18.96 per Bbl in the comparable 1996 period, while average
gas prices increased from $1.65 per Mcf in the 1995 period, to $2.31 per Mcf in
the comparable 1996 period.
Revenues from oil and gas sales comprised 86% and 77%, respectively, of
total revenues for the first nine months of 1996 and 1995. The majority of these
revenues were derived from the sale of the Company's gas production. The Company
expects oil and gas sales to continue to increase as a direct consequence of the
addition of oil and gas reserves through the Company's active drilling programs.
Supervision Fees. Supervision fees increased 15%, having grown from $2.8
million in the first nine months of 1995 to $3.3 million in the first nine
months of 1996. This increase is primarily due to the annual escalation in April
in well overhead rates, and the increase in drilling activity by the Company,
which in turn increases the drilling well overhead portion of such fees.
Costs and Expenses. General and administrative expenses for the first nine
months of 1996 increased approximately $630,000 or 16% when compared to the same
period in 1995. However, the Company's general and administrative expenses per
Mcfe produced decreased by 33% from $0.51 per Mcfe produced for the first nine
months of 1995 to $0.34 per Mcfe produced for the comparable period in 1996. A
majority of the companies in the oil and gas industry treat supervision fees as
a reduction of their general and administrative expenses. If the Company were to
follow this practice, these expenses net of supervision fees would have
decreased to $0.14 per Mcfe produced for the first nine months of 1995 and to
$0.10 per Mcfe produced for the same period in 1996.
Depreciation, depletion, and amortization ("DD&A") increased 84%
(approximately $5.2 million) for the first nine months of 1996, primarily due to
the Company's reserve additions and the associated costs thereof and the related
sale of increased quantities of oil and gas therefrom. The Company's DD&A rate
per Mcfe of production has increased from $0.78 per Mcfe produced in the 1995
period to $0.83 per Mcfe produced in the 1996 period, reflecting variations in
the per unit cost of reserve additions.
The Company's production costs per Mcfe decreased from $0.65 per Mcfe
produced in the 1995 period to $0.42 per Mcfe produced in the 1996 period.
However, due to the increase in production volumes, oil and gas production costs
increased 13% (approximately $650,000) in the first nine months of 1996 when
compared to the first nine months of 1995. As discussed above, the Company's
increase in production is primarily through its drilling activities in the AWP
Olmos Field and Austin Chalk trend where the Company already has an established
operating base. The increase in production costs is partially offset by an
exemption in these same fields from the 7.5% Texas severance tax applicable to
gas production from certain natural gas wells certified to be in tight
formations or to be deep wells by the Texas Railroad Commission. Additionally,
commencing September 1, 1996, certain wells certified as "high cost gas" wells
will be entitled to a reduction of severance tax based upon a formula amount.
Therefore, the increase in drilling activity and production has not been
accompanied by a proportionate increase in operating costs. This tax exemption
has had a positive impact on the Company's production costs during 1995 and
1996, although under the new rules, the proportionate amount of the exemption
may be reduced in future periods.
Interest expense in the first nine months of 1996 on the 6 1/2% Convertible
Subordinated Debentures due 2003, including amortization of debt issuance costs,
totaled $994,000 ($1.5 million in the 1995 period), while interest expense on
the credit facilities, including commitment fees,
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<PAGE> 24
totaled $790,000 ($1.6 million in the 1995 period) for a total interest expense
of $1.8 million (of which $1.5 million was capitalized). In the first nine
months of 1995, these costs totaled $3.1 million (of which $1.8 million was
capitalized). The Company capitalizes that portion of interest related to its
exploration, partnership, and foreign business development activities. The
decrease in interest expense in 1996 is attributable to the decrease in the
average balance under the Company's credit lines necessary to finance the
Company's capital expenditures as discussed below, as well as incurring only six
months of interest in 1996, instead of nine months of interest in 1995, on the
6 1/2% Convertible Subordinated Debentures due 2003 which were converted into
Common Stock in the third quarter of 1996.
Net Income. Net income of $11.4 million and earnings per share of $0.87 for
the first nine months of 1996 were 352% and 172% higher, respectively than net
income of $2.5 million and earnings per share of $0.32 in the same period for
1995. This increase in net income primarily reflected the effect of a 122%
increase in oil and gas sales revenues as a result of a 98% increase in natural
gas production, a 17% increase in crude oil production and product price
improvements. The lower percentage increase in earnings per share reflects a 64%
increase in weighted average shares outstanding for the period, as a result of
the sale of 5.75 million shares of Common Stock in the third quarter of 1995,
and the conversion of the 6 1/2% Convertible Subordinated Debentures due 2003
into 2.34 million shares of Common Stock in the third quarter of 1996.
Comparison of Years Ended December 31, 1995, 1994 and 1993
Revenues. The Company's revenues in 1995 increased by 14% over revenues in
1994, and by 5% in 1994 over 1993 revenues, principally due to increases in oil
and gas sales. Revenues for 1993 included recognition of earned interests,
discussed above, amounting to $3.3 million. On a pro forma basis, after
considering the retroactive application of the Company's change in accounting
for earned interests, revenues for 1993 would have been reduced 14% to $20.8
million.
Oil and Gas Sales. The increase in oil and gas sales for 1995 was primarily
the result of production from exploratory and developmental wells drilled in
late 1994 and in 1995. In 1995, the Company's additions to reserves from
drilling were approximately 13 times its additions to reserves from producing
property acquisitions. In 1994, reserves added through drilling were
approximately double the additions to reserves from producing property
acquisitions. As a percentage of total revenues, oil and gas sales have risen
from 64% of total revenues in 1993 to 78% of total revenues in 1995.
The Company's net sales volumes in 1995 (including the volumetric
production payment associated with each year's production) increased by 17% (1.6
Bcfe) over net sales volumes in 1994, while 1994 net sales volumes increased by
30% (2.2 Bcfe) over net sales volumes in 1993. Oil and gas sales in 1995
increased by 14% ($2.7 million) over 1994, while in 1994 oil and gas sales
increased by 27% ($4.3 million) over oil and gas sales in 1993. Average prices
for oil dropped from $15.10 per Bbl in 1993, to $14.35 per Bbl in 1994, but
recovered to $15.66 per Bbl in 1995, while average gas prices decreased from
$1.96 per Mcf in 1993, to $1.93 per Mcf in 1994, and to $1.77 per Mcf in 1995.
Increased 1995 oil and gas sales were attributable to the sale of
production from properties owned by the Company for its own account, which
includes production derived from (i) producing properties acquired for its own
account in 1994 and (ii) wells placed into production in 1994 and 1995 through
exploratory and development drilling (the largest primary contributor to the
Company's increased oil and gas sales in 1995). In 1995, oil and gas sales,
exclusive of both the Company's interests in partnerships and in sales delivered
under the volumetric production payment, were $10.8 million (5.3 Bcfe) compared
to similar oil and gas sales in 1994 of $7.0 million (3.2 Bcfe), an increase
between years of $3.8 million (2.1 Bcfe). These same sales in 1993 were $2.2
million (0.9 Bcfe). These sales have comprised 48%, 35% and 14% of total oil and
gas sales for the respective years 1995, 1994 and 1993.
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<PAGE> 25
The Company's oil and gas sales derived through the Company's interest in
partnerships were $7.6 million (3.8 Bcfe) in 1995, $8.7 million (4.2 Bcfe) in
1994 and $8.8 million (4.0 Bcfe) in 1993. As a percentage of total oil and gas
sales, revenues from these interests have comprised 34%, 44% and 57% of the
total for 1995, 1994 and 1993, respectively.
The final major source of the Company's oil and gas sales is the sale of
production from the properties acquired from Manville Corporation in May 1992.
The Company records the entire amount of hydrocarbons sold as revenue, which was
$4.1 million (18% of total oil and gas sales revenue) from 2.1 Bcfe sold in
1995, of which 44% was a non-cash amortization of deferred revenues associated
with the volumetric production payment, while the remaining 56% equals cash
proceeds from sale of oil and excess gas for the Company's account. For 1994,
the Company recorded $4.1 million of revenue (21% of total oil and gas sales
revenue) from the sale of 2.1 Bcfe, of which 49% was non-cash amortization of
deferred revenues and 51% cash proceeds from the sale of oil and excess gas. For
1993, the Company recorded $4.6 million of revenue (29% of total oil and gas
sales) from the sale of 2.4 Bcfe, of which 51% was non-cash amortization of
deferred revenues and 49% cash proceeds from sale of oil and excess gas.
Supervision Fees. Supervision fees continue to increase slightly, having
grown from $3.72 million in 1993 to $3.75 million in 1994 to $3.84 million in
1995, due to the change in properties operated by the Company, the annual
escalation in well overhead rates and the increase in drilling activity by the
Company, which in turn increases the drilling well overhead portion of such
fees.
Costs and Expenses. General and administrative expenses increased 3% from
1993 to 1994 and 1% from 1994 to 1995. However, the Company's general and
administrative expenses per Mcfe produced decreased from $0.69 per Mcfe in 1993,
to $0.54 per Mcfe produced in 1994 (a 22% decrease), to $0.47 per Mcfe produced
in 1995 (a 13% decrease). Also, if the Company's supervision fees were treated
as a reduction of its general and administrative expenses, these expenses net of
supervision fees would have decreased to $0.18 per Mcfe produced in 1993, $0.15
per Mcfe produced in 1994 and to $0.13 per Mcfe produced in 1995.
Depreciation, depletion, and amortization (DD&A) has steadily increased,
primarily due to the Company's reserve additions and the associated costs
thereof and the related sale of increased quantities of oil and gas therefrom.
The Company's DD&A rate per Mcfe of production has, however, decreased from
$0.99 in 1993, to $0.82 in 1994, to $0.79 in 1995, reflecting variations in the
per unit cost of reserve additions.
The 24% increase in oil and gas production costs from 1993 to 1994 and the
21% increase from 1994 to 1995 also relates to the growth in the Company's
production volumes. The 1995 increase was also affected by certain one-time
remedial well expenses. The Company's production costs were $0.62 per Mcfe
produced in 1993, $0.59 per Mcfe produced in 1994 and $0.61 per Mcfe produced in
1995.
Interest expense in 1995 on the 6 1/2% Convertible Subordinated Debentures
due 2003, including amortization of debt issuance costs, totaled $2.0 million
($2.0 million in 1994 and $984,000 in 1993), while interest expense on the
credit facilities, including commitment fees, totaled $1.7 million ($1.7 million
in 1994 and $599,000 in 1993) for a total interest expense of $3.7 million (of
which $2.5 million was capitalized). The 1994 total was $3.7 million (of which
$1.9 million was capitalized), while the 1993 total was $1.6 million (of which
$986,000 was capitalized). The Company capitalizes that portion of interest
related to its exploration, partnership and foreign business development
activities. The lower amount of interest expense in 1993 was attributable to a
smaller average balance under the Company's credit lines necessary to finance
the Company's capital expenditures, as well as paying only six months of
interest on the 6 1/2% Convertible Subordinated Debentures due 2003.
Net Income (Loss). Net income of $4.9 million and earnings per share of
$0.54 for 1995 were 32% higher and 4% lower, respectively than "Income before
cumulative effect of change in
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<PAGE> 26
accounting principle" of $3.7 million and earnings per share of $0.56 in 1994.
The increase in net income was primarily due to an increase in production
volumes and the related oil and gas sales therefrom. The 1995 decrease in
earnings per share reflects a 37% increase in weighted average shares
outstanding for the period, as a result of the sale of 5,750,000 shares of
Common Stock in the third quarter of 1995. The Company's consolidated effective
tax rate was 26%, 23% and 29% in 1993, 1994 and 1995, respectively.
Net loss for 1994 of $13.0 million included a cumulative effect of a change
in accounting principle (see Note 2 to the Company's Consolidated Financial
Statements) of $16.8 million. Income before cumulative effect of change in
accounting principle for 1994 was 24% less than net income for 1993.
On a pro forma basis, after considering the retroactive application of the
Company's change in accounting for earned interests, net income would have been
$3.7 million and $4.3 million for 1994 and 1993, respectively.
LIQUIDITY AND CAPITAL RESOURCES
In 1991, the Company's strategy shifted toward increased reliance on
exploration and development activities, and the Company has significantly
expanded reserves added through these efforts. Previously, the Company relied on
limited partnership capital as its principal financing vehicle to fund its
acquisitions of producing properties. As a result of this shift in strategy, the
Company has reduced its reliance on cash flows generated from, and capital
raised through, limited partnerships. Supplemental cash and working capital are
provided through internally generated cash flows and debt and equity financing.
During the first half of 1995, the Company used a combination of bank
financing, internally generated cash flows and partnership financing to fund its
operations. In the third quarter of 1995, the Company realized $45.7 million in
net proceeds from an offering of Common Stock that provided sufficient capital
to repay its bank financing and finance its capital expenditures for the second
half of 1995. During the first nine months of 1996, the Company relied upon
internally generated cash flows and bank borrowings to fund its capital
expenditures. Described below are the major elements of the Company's liquidity
and capital resources:
Net Cash Provided by Operating Activities. For the nine-month period ended
September 30, 1996, net cash provided by operating activities increased
significantly (208%) to $26.4 million compared to $8.5 million during the first
nine months of 1995. In 1995, 1994 and 1993, the Company generated net cash from
operating activities of $14.4 million, $10.4 million and $7.2 million,
respectively. These increases were primarily due to increased production volumes
and higher product prices, as discussed above. During 1995, the Company also had
a $689,000 increase in other revenues and a $680,000 decrease in interest
expense, partially offset by a $1.2 million increase in oil and gas production
costs. The 1994 increase of $3.2 million in net cash provided by operating
activities was primarily due to the cash flows from oil and gas sales, which
increased $4.6 million (35%), exclusive of the non-cash amortization of deferred
revenues associated with the Company's volumetric production payment, partially
offset by a $1.1 million increase in oil and gas production costs and a $1.2
million increase in interest expense.
Working Capital. The Company's working capital increased significantly from
a deficit of $13.1 million at December 31, 1994, to $3.2 million at December 31,
1995. This increase is primarily the result of the net proceeds from the 1995
Common Stock offering.
The Company's working capital has decreased over the last nine months, from
$3.2 million at December 31, 1995, to a working capital deficit of $6.0 million
at September 30, 1996. The decrease is primarily the result of the Company's
capital expenditures as described below.
Since year-end 1995, the Company's receivable account from limited
partnerships decreased significantly due to (a) receipt of approximately $7.8
million generated from property sales
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<PAGE> 27
proceeds realized by these partnerships and (b) an increase in oil and gas
prices received by these partnerships. Both increased the cash flows of these
partnerships, thus allowing them to reduce their balances owed to the Company.
Due to the nature of the Company's business highlighted above, the
individual components of working capital fluctuate considerably from period to
period. The Company incurs significant working capital requirements in
connection with its role as operator at September 30, 1996 of approximately 800
wells, its accelerated drilling program and the management of affiliated
partnerships. In this capacity, the Company is responsible for certain
day-to-day cash management, including the collection and disbursement of oil and
gas revenues and related expenses.
Capital Expenditures. Capital expenditures for property, plant and
equipment during the first nine months of 1996 were $56.0 million. These capital
expenditures included: (a) $42.4 million of drilling costs, both exploratory and
developmental; (b) $9.2 million of prospect costs (principally prospect
leasehold, seismic and geological costs of unproved prospects for the Company's
account); (c) $3.0 million invested in foreign business opportunities in Russia
(approximately $2.4 million), in Venezuela (approximately $300,000) and in New
Zealand (approximately $300,000), as described in Note 9 to the Company's
Consolidated Financial Statements included herein; and (d) $1.4 million spent
for computer equipment and furniture and fixtures. In the remaining three months
of 1996, the Company expects capital expenditures to be approximately $25.0
million, including investments in all areas in which investments were made
during the first nine months of the year as described above, with a particular
focus on exploration and development drilling. The Company currently plans to
participate in the drilling of 162 gross wells this year, compared to 76 wells
in 1995. Through September 30, 1996, the Company had participated in drilling 6
exploratory and 96 development wells with 4 exploratory successes and 92
development successes. The steady growth in the Company's unproved property
account which is not being amortized is indicative of the shift to a focus on
drilling activity, as the Company acquires prospect acreage. During the first
nine months of 1996, this account also reflects $3.0 million of capital
expenditures made in relation to the Company's foreign business opportunities,
as described above.
The Company's capital expenditures were approximately $40.0 million, $34.5
million and $24.2 million for 1995, 1994 and 1993, respectively. Including the
Company's general partner capital contribution to drilling partnerships formed
in 1995 ($3.2 million). Approximately $23.6 million (59%) of the 1995 capital
expenditures was spent on developmental drilling (primarily in the AWP Olmos
Field and the Austin Chalk trend) and $2.3 million (6%) was spent on exploratory
drilling. The Company expended approximately $6.4 million (16%) for prospect
costs, principally prospect leasehold, seismic and geological costs of unproven
prospects for the Company's account. The Company funded approximately $2.1
million (5%) for the Company's general partner capital contribution to the
partnerships formed under its SDI offering. The Company also purchased
approximately $500,000 (1%) of limited partner interests in previously formed
partnerships. In its foreign activities, as described in Note 9 to the Company's
Consolidated Financial Statements, the Company invested $2.8 million (7%),
$300,000 (1%), and $200,000 (1%), respectively in its Russia, Venezuela and New
Zealand initiatives. Finally, the Company spent the remaining amounts (4%) on
fixed assets (primarily for computer equipment) and other additions.
The net proceeds of the offering, after repayment of the Company's
outstanding indebtedness, will be added to working capital to fund the Company's
development and exploration drilling projects and possibly to acquire oil and
gas properties, or for other general corporate purposes. The Company believes
that the proceeds of this offering and anticipated internally generated cash
flows (expected to increase as the Company's production base increases as a
result of its accelerated drilling program) will be sufficient to finance the
costs associated with its currently budgeted capital expenditures of over $134.0
million for the remaining three months of 1996 and for 1997. Further liquidity
needs may also be met by its existing credit facilities.
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<PAGE> 28
1995 Stock Offering. During the third quarter of 1995, the Company sold
5.75 million shares of Common Stock in a public offering at $8.50 per share,
with net proceeds of $45.7 million. Net proceeds from the offering were used to
repay outstanding indebtedness, and the remainder of the proceeds have been used
to finance the Company's exploration and development activities and to acquire
producing oil and gas properties, including limited partnership interests.
Other Financing Activities. On June 30, 1993, the Company issued the 6 1/2%
Convertible Subordinated Debentures due 2003 in the amount of $28.8 million in a
public offering. Proceeds of the offering were used primarily to acquire
producing oil and gas properties and to finance the Company's expanding
exploration and development programs. As described in Note 5 to the Company's
Consolidated Financial Statements included herein, in August 1996 the 6 1/2%
Convertible Subordinated Debentures due 2003 were converted by their holders
into 2.34 million shares of the Company's Common Stock following the Company's
July 1996 announcement that the 6 1/2% Convertible Subordinated Debentures due
2003 would be redeemed in August 1996 unless earlier converted. As a result of
this conversion, the Company's stockholders' equity increased approximately
$27.65 million.
Credit Facilities. Recently, the Company's credit facilities have been used
to fund a portion of the Company's exploration and development activities.
Formerly, the Company established credit facilities which were used principally
to finance the Company's purchase of producing oil and gas properties on an
interim basis pending transfer of the properties to newly formed partnerships
and joint ventures and to provide working capital. These credit facilities
consist of a $100.0 million unsecured revolving line of credit with a $30.0
million borrowing base and a $7.0 million secured revolving line of credit. The
principal terms and restrictions of these credit facilities are described in
Note 4 to the Company's Consolidated Financial Statements included herein.
At September 30, 1996, the Company had $17.2 million outstanding under
these borrowing arrangements used, along with internally generated cash flows of
$26.4 million, principally to fund the Company's capital expenditures in the
first nine months of 1996, and to a lesser extent, to provide working capital.
At December 31, 1995, the Company had no outstanding balances under these
borrowing arrangements, as these borrowings were repaid with proceeds from the
Company's 1995 stock offering.
Partnership Programs. Between 1991 and 1995, the Company offered interests
in oil and gas production partnerships under its Swift Depositary Interests
("SDI") offering, and since late 1993 has offered private partnerships formed to
drill for oil and gas. The SDI program concluded at the end of 1995. The Company
anticipates that it will continue to offer the drilling partnerships for the
foreseeable future.
At September 30, 1996, limited partnership formation and marketing costs
(which under the current drilling partnership offerings are borne by the Company
as part of the Company's general partner contribution) amounted to $768,000, a
decrease of $91,000, when compared with the December 31, 1995 balance.
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BUSINESS AND PROPERTIES
GENERAL
The Company is engaged in the exploration, development, acquisition and
production of oil and gas properties with a primary focus on U.S. onshore
natural gas reserves. As of December 31, 1995, the Company had interests in over
4,000 oil and gas wells located in 15 states, with over 85% of its proved
reserve base concentrated in Texas. At the same date, the Company had estimated
proved reserves of 176 Bcfe, approximately 80% of which were natural gas, and
operated 767 wells representing 86% of its proved reserve base.
The Company's primary focus is exploration and development drilling on its
core areas, the AWP Olmos Field located in South Texas and the Texas Austin
Chalk trend. The AWP Olmos Field is characterized by long-lived reserves, while
the Austin Chalk trend is characterized by more short-lived reserves with high
initial production and rapid decline rates. These fields accounted for
approximately 67% and 6%, respectively, of the Company's proved reserves as of
December 31, 1995, and approximately 61% and 16%, respectively, of the Company's
production for the nine months ended September 30, 1996. The Company has
substantially accelerated its drilling activities during the last several years,
drilling 16, 42 and 76 net wells in 1994, 1995 and the first nine months of
1996, respectively, primarily in these areas. The Company has also doubled its
undeveloped acreage position in both the AWP Olmos Field and the Austin Chalk
trend during 1996 and currently has an inventory of over 360 and 65 potential
well locations in these two areas, respectively. The Company has budgeted
capital expenditures of over $134.0 million for the remaining three months of
1996 and for 1997, of which approximately $90.0 million is targeted for these
two fields. The Company is also actively pursuing exploratory and development
drilling opportunities in other basins in Texas, Louisiana and Wyoming. As a
complement to these domestic activities, the Company is participating in several
high potential international projects, with limited capital exposure to the
Company in New Zealand, Russia and Venezuela.
The Company has increased its proved reserves from 41 Bcfe at year-end 1990
to 176 Bcfe at year-end 1995, primarily from additions through the drillbit,
which has resulted in the replacement of 516% of production during the same
five-year period. In 1995, the Company increased its proved reserves by 70%,
resulting in the replacement of 827% of 1995 production. Over the 1991 through
1995 period, reserve replacement costs have averaged $0.63 per Mcfe, a level
which the Company believes is lower than comparable industry averages. As a
result of increased drilling activity, average daily production increased to
57,875 Mcfepd in September 1996, an increase of 98% over average daily
production of 29,300 Mcfepd in September 1995. Due to economies of scale and
geographic concentration, general and administrative expenses and production
costs have fallen from $1.19 and $0.63 per Mcfe in 1990 to $0.34 and $0.42 per
Mcfe, respectively, for the nine months ended September 30, 1996. The
combination of increased production and decreased operating costs per Mcfe has
resulted in average annual growth in net cash provided by operating activities
of 24% per year from year-end 1990 to year-end 1995. For the nine months ended
September 30, 1996, net cash provided by operating activities increased by 208%
over the same period in 1995 to $26.4 million due to these same production and
operating cost factors.
BUSINESS STRATEGY
The Company intends to continue to increase its reserves, cash flows and
underlying net asset value through a balanced growth strategy that includes an
aggressive drilling program, exploitation of advanced technologies and strategic
acquisitions.
Key elements of the Company's strategy include the following:
Aggressive Drilling Program. The Company believes that future reserve
growth will result from a combination of drilling wells on proved undeveloped
acreage in its core areas, step-out and exploratory drilling on the Company's
substantial inventory of undeveloped acreage and exploration
29
<PAGE> 30
efforts in selected areas outside the Company's core fields. In 1995, the
Company drilled 39 net development wells and 4 net exploration wells, including
38 net development wells in the Company's AWP Olmos Field and Austin Chalk trend
core areas. During this period, the Company had drilling success rates of 96%
for development wells and 50% for exploratory wells. The Company expects to
drill a total of 162 gross (122 net) wells in 1996, 102 which have been drilled
as of September 30, 1996 for a capital cost of $42.4 million to the Company. For
1997, the Company plans to drill approximately 161 gross wells at an expected
capital cost of $86 million to the Company. The Company anticipates that
drilling activity in the AWP Olmos Field will represent 85% of the Company's
1996 drilling budget and 75% of the Company's 1997 drilling budget. Exploratory
drilling is based on a "controlled risk" approach focusing on regions where the
exploration objective would allow the Company to utilize its technological or
geological expertise and which are in close proximity to known producing
horizons. The Company also reduces its overall risk exposure with respect to
exploration and development activities by entering into joint development
agreements with industry partners to share capital exposure for any individual
well. As an example of this strategy, the Company has active joint development
projects with UPRC, Chesapeake and Snyder in the Austin Chalk trend, under which
the Company serves as operator of a majority of the wells on these properties.
Exploitation of advanced technologies. To minimize the risks associated
with exploration and development drilling and to enhance operating efficiency,
the Company has devoted considerable resources to developing advanced
technological expertise. These technologies include 2-D and 3-D seismic
analysis, AVO (amplitude versus offset) studies and detailed formation depletion
studies. The Company has also attained substantial expertise in horizontal well
technology, having participated in 28 such wells in the Austin Chalk trend, 27
of which have been successful. Additionally, the Company uses innovative
fracturing methods, coiled tubing technology and computer telemetry to monitor
well performance in the AWP Olmos Field. As a result of these technologies, the
Company has enhanced its production yields while reducing its costs per Mcfe.
Strategic acquisitions. The Company is continuously reviewing acquisition
opportunities, including opportunities to acquire substantial undeveloped
acreage for future drilling activities. The Company targets properties in close
proximity to the Company's current reserves, where such reserves can be
increased through development drilling and where improved operating efficiencies
can be achieved. Using these criteria, the Company employs a disciplined,
market-driven approach to acquisitions that can result in varying levels of
annual spending on acquisitions. The Company has substantial experience in
making such acquisitions, having purchased approximately $465.0 million of
producing oil and natural gas properties on behalf of itself and its
co-investors in 122 separate transactions since 1979.
PROPERTIES
Major Properties
The Company's proved reserves are geographically concentrated, with
approximately 73% of the Company's proved reserves at December 31, 1995,
attributable to its two largest properties, the AWP Olmos Field and the Austin
Chalk trend.
AWP Olmos Field. The Company's most significant property is located in the
AWP Olmos Field in South Texas. The Company has extensive expertise in the AWP
Olmos Field and a long history of experience with low-permeability tight-sand
formations typical of this field. Since acquiring its first AWP Olmos Field
acreage in 1988, the Company has made detailed studies of drainage patterns in
the formation and has introduced innovations in fracture design and
implementation methods and coiled tubing technology that substantially reduce
overall costs and improve recoveries.
The AWP Olmos Field represented approximately 67% of the Company's proved
reserves at December 31, 1995 and approximately 31% of the Company's 1995
production and 61% of production for the first nine months of 1996. At September
30, 1996, the Company owned interests
30
<PAGE> 31
in, and was the operator of approximately 200 wells producing natural gas from
the Olmos Sand Formation at a depth of approximately 10,000 feet. The Company
has engaged in extensive fracturing operations to increase the permeability of
the formation and flow of gas from the wells. In addition, the Company has used
coiled tubing velocity strings in several wells to improve production rates and
a system of BJ Services Inc. by which the Company is capable of monitoring
fracturing operations from its Houston headquarters through direct computer
access to the field.
During 1995 and the first nine months of 1996, the Company drilled 121 (120
successful) development wells in this field. During the latter portion of 1996,
the Company has utilized six drilling rigs in continuous operation in the AWP
Olmos Field area, with each rig drilling approximately two wells per month. The
average working interest owned by the Company or entities managed by the Company
in this field range from 40% to 100%. During 1996, the Company acquired an
additional 18,000 net acres in this area and has drilled 12 wells on the
newly-acquired acreage. These acquisitions have tripled the amount of acreage
that the Company has under lease and quadrupled the amount of developed acreage
on which there is current production. The Company anticipates continuing its
acquisition of acreage in this area in the future. The Company has identified
more than 360 potential drilling locations on its current acreage position, and
the Company anticipates drilling approximately 210 additional wells in this
field through 1998.
Austin Chalk Trend. At September 30, 1996, the Company owned drilling and
production rights to over 58,000 acres in the Austin Chalk trend containing
substantial proved undeveloped reserves. The Giddings Field in the Austin Chalk
trend in Fayette County, Texas, represented approximately 6% of the Company's
proved reserves at December 31, 1995. Production from this field constituted 18%
of oil and gas production in 1995 and 16% of production during the first nine
months of 1996. The wells in the Giddings Field are all horizontally produced
natural gas wells that deliver high initial flow rates and strong initial cash
flows which decline rapidly. The Company believes these reserves complement its
long-lived reserves in the AWP Olmos Field. Since 1992, the Company has
participated in 28 horizontal wells in the Giddings Field with a 96% success
rate, including 9 and 7 successful development wells drilled in 1995 and 1996,
respectively. The Company believes its success is attributable to its ability to
identify hydrocarbon-bearing fractures, relying on its expertise in seismic data
analysis, and its ability to drill and operate horizontal wells.
Substantial portions of its property interests in the Austin Chalk trend
have been acquired through joint development arrangements, including agreements
with Chesapeake and UPRC, two of the most active participants in exploration of
the Austin Chalk trend. The joint development arrangement with Chesapeake began
in 1993 and covers approximately 8,800 acres in which the Company currently has
an average working interest of 25%. In September 1995, the Company entered into
a joint development agreement with UPRC providing for an area of mutual interest
covering 19,500 acres and pursuant to which UPRC and the Company alternate
serving as operator of any wells drilled on the acreage. During 1996, the
Company purchased UPRC's interest in 6,500 acres, and the joint development
arrangement now covers a 10,000 acre block in which the Company expects to have
an average working interest of 30% to 35% based on certain assumptions relating
to elections to participants with respect to the drilling of various wells. The
Company has identified 25 potential drilling locations on the Fayette County
acreage and anticipates drilling 10 to 12 wells on this acreage during 1997.
The most recent joint development arrangement with Snyder covers 29,000 net
acres in Walker County, Texas in which the Company purchased a 56% interest and
will serve as operator. It is anticipated that the first well on this acreage
will commence drilling in December 1996. The Company has identified up to 40
potential well locations on the Walker County property. Future operations will
be defined by the results of the two initial wells drilled.
31
<PAGE> 32
PROVED RESERVE AND PRODUCTION DATA
The following presentation of the Company's proved reserves at December 31,
1995, the percentage of such reserves comprised of natural gas and its 1995
production, is broken down by the Company's two core properties and by state for
the remainder of its properties.
PROVED RESERVES AND PRODUCTION BY REGION
<TABLE>
<CAPTION>
AT AND FOR THE YEAR ENDED DECEMBER 31, 1995
---------------------------------------------------------------------------------
PROVED RESERVES (BCFE) PERCENT OF PERCENT PERCENT OF
------------------------------- COMPANY'S NATURAL PERCENT 1995 TOTAL
REGION DEVELOPED UNDEVELOPED TOTAL RESERVES GAS UNDEVELOPED PRODUCTION
- ----------------------------------- --------- ----------- ----- ---------- ------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
South Texas AWP Olmos.............. 50.3 67.8 118.1 67.1 86.9 57.4 31.0
Texas Austin Chalk................. 6.9 4.0 10.9 6.2 78.3 36.7 18.0
Other Texas(1)..................... 22.2 0.2 22.4 12.7 72.4 0.9 23.1
Louisiana.......................... 6.5 2.0 8.5 4.8 88.0 23.5 8.0
Oklahoma........................... 4.4 0.2 4.6 2.6 81.4 4.3 6.7
Alabama............................ 4.5 -- 4.5 2.6 55.4 -- 1.5
Mississippi........................ 3.4 -- 3.4 1.9 31.1 -- 4.4
Other.............................. 3.2 0.5 3.7 2.1 32.7 13.5 7.3
----- ---- ----- ----- ---- ---- -----
Total...................... 101.4 74.7 176.1 100.0 81.5 42.4 100.0
===== ==== ===== ===== ==== ==== =====
</TABLE>
- ---------------
(1) No single property in this category comprised as much as 2% of reserves or
production for 1995.
EXPLORATION AND DEVELOPMENT DRILLING ACTIVITIES
In 1991, the Company began to increase its inventory of exploration and
development drilling prospects. Drilling locations were selected through
intensive geological and geophysical studies of the Company's undeveloped
acreage and other prospects. During 1994, the Company added 25 Bcfe of proved
reserves through drilling. By 1995, reserves added by drilling had almost
tripled to 72 Bcfe with the Company's success rate 50% for exploratory wells (4
out of 8 drilled) and 96% for development wells (65 out of 68 drilled). These
successful drilling results have led to acquisition of substantial additional
acreage during 1996 in the area of its two core properties, the AWP Olmos Field
in the tight sands formations of southern Texas and the Austin Chalk trend in
Fayette and Walker Counties in central and eastern Texas, respectively.
The Company pursues a "controlled risk" approach to exploratory drilling.
The Company focuses its exploration activities on specific regions in the U.S.
where its technical staff has considerable experience and in close proximity to
known producing horizons where the potential for significant reserves exists.
The Company seeks to minimize its exploration risk by investing in multiple
prospects, farming out interests to industry partners and drilling funds,
utilizing advanced technologies and drilling in different types of geological
formations.
The Company's development strategy is designed to maximize the value and
productivity of its existing properties through development drilling and
recovery methods, enhancing production results through improved field production
techniques, lowering production costs and applying the Company's technical
expertise and resources to exploit producing properties efficiently. The Company
employs various recovery techniques which include water flooding, fracturing
reservoir rock through the injection of high-pressure fluid, inserting coiled
tubing velocity strings to speed gas flow and acid treatments. The Company
believes that the application of fracturing technology and coiled tubing has
resulted in significant increases in production and decreases in drilling and
operating costs in several of its fields, including the Company's largest single
property, the AWP Olmos Field. See "-- Properties -- Major Properties -- AWP
Olmos Field."
The Company's exploration and development activities are conducted by its
in-house exploration staff, assisted by professionals from other departments,
including reservoir engineers, geologists, geophysicists, petrophysicists,
landmen and drilling and operations engineers. The Company
32
<PAGE> 33
believes that one of the keys to its success has been its team approach which
integrates multiple disciplines to maximize utilization of the information
provided by modern seismic techniques.
The Company has increasingly utilized advanced seismic technology to
enhance the quality of its drilling efforts, including 2-D and 3-D seismic
analysis, AVO studies and detailed formation depletion studies. During the
second quarter of 1996, the Company completed two 3-D seismic programs, one in
northern Louisiana and the other in central Texas. The Company has a number of
computer workstations from which seismic data is analyzed and enhanced with
advanced software programs, including its three Landmark Systems(R)
workstations. As a result, the Company has developed a significant internal
seismic expertise and has compiled an extensive library of seismic data.
In addition to exploration and development activities in the AWP Olmos
Field and the Austin Chalk trend, the Company is currently focusing its
exploration activities in three main geographical areas: the Gulf Coast Basin,
the Wyoming Powder River Basin and the North Louisiana Salt Dome Basin.
Gulf Coast Basin. The Company's drilling program in the Gulf Coast Basin in
1995 consisted of one successful exploratory well and two successful development
wells. The locations were selected utilizing traditional geologic studies
combined with analyses of available seismic data. To reduce its exploration and
development risk in the Gulf Coast Basin, the Company conducted a 3-D seismic
survey in Jackson County, Texas, in 1994. The processing and interpretation has
identified a number of potential drilling locations which have been further
refined through AVO analysis. The Company owns interests in the South Louisiana
East Mud Lake and Second Bayou fields with significant drilling potential.
Through the third quarter of 1996, three exploratory wells (one successful) have
been drilled in the Gulf Coast Basin. Two exploratory wells are planned for the
fourth quarter. In 1997, Swift expects to drill five exploratory wells in this
basin.
Wyoming Powder River Basin. Through the third quarter of 1996, the Company
drilled one successful exploratory well in the Wyoming Powder River Basin, and
plans to drill two or three exploratory wells in the fourth quarter of 1996 and
up to four exploratory wells in 1997 in this area. The Minnelusa trend has been
the subject of extensive study by the Company's multidisciplinary teams in order
to identify the location of stratigraphic hydrocarbon traps. The Company's staff
has evaluated over 5,000 wells drilled in the area, utilizing 2-D and 3-D
seismic data, and has conducted petrophysical studies to determine the
hydrocarbon-bearing capacity of the rock. To increase the production in some
areas, the Company has instituted secondary and tertiary recovery through water
or polymer flooding in the Minnelusa fields.
North Louisiana Salt Dome. The North Louisiana Salt Dome covers the
neighboring corners of Arkansas, Louisiana and Texas. In this area, the
Smackover formation is a prolific hydrocarbon producer from multiple levels and
from a variety of structures, including fault traps, salt anticlines, basement
structures and stratigraphic traps. The Company currently has access to a
7,000-mile seismic data base in the area and completed a 3-D seismic survey in
the Smackover formation in early 1996. The Company has drilled five successful
exploratory wells in this area through the third quarter of 1996 and plans to
drill three exploratory wells in the fourth quarter of 1996 and seven
exploratory wells in 1997.
OPERATIONS
The Company generally seeks to be named as operator for wells in which it
or its affiliated limited partnerships and joint ventures have acquired a
significant interest, although this typically occurs only when the Company or
its affiliated limited partnerships and joint ventures own the major portion of
the working interest in a particular well or field. The Company acts as operator
of approximately 770 wells at December 31, 1995, which comprise approximately
86% of the Company's total proved reserves.
33
<PAGE> 34
As operator, the Company is able to exercise substantial influence over
development and enhancement of a well and to supervise operation and maintenance
activities on a day-to-day basis. The Company does not conduct the actual
drilling of wells on properties for which it acts as operator. Drilling
operations are conducted by independent contractors engaged and supervised by
the Company. The Company employs petroleum engineers, geologists, and other
operations and production specialists who strive to improve production rates,
increase reserves and/or lower the cost of operating its oil and gas properties.
Oil and gas properties are customarily operated under the terms of a joint
operating agreement, which provides for reimbursement of the operator's direct
expenses and monthly per-well supervision fees. Per-well supervision fees vary
widely depending on the geographic location and producing formation of the well,
whether the well produces oil or gas, and other factors. Such fees received by
the Company in 1995 ranged from $50 to $1,433 per well per month.
MARKETING OF PRODUCTION
The Company typically sells its gas production at or near the wellhead,
although in some cases it must be gathered by the Company or other operators and
delivered to a central point. Gas production is generally sold in the spot
market at prevailing prices. The Company generally sells its oil production at
prevailing market prices. The Company does not refine any oil it produces. Only
one single oil or gas purchaser accounted for 10% or more of the Company's
consolidated revenues during the year ended December 31, 1995, with that
purchaser accounting for approximately 12%. The Company does not believe that
the loss of any single oil or gas purchaser or contract would materially affect
its sales. The Company recently entered into gas processing and gas
transportation agreements with respect to its natural gas production in the AWP
Olmos Field with Valero Transmission, L.P. and its affiliates ("Valero") for up
to 75,000 Mcf per day. These contracts have initial six-year terms, with
automatic one-year extensions thereof unless earlier terminated. The Company
anticipates that these arrangements will adequately provide for its gas
transportation and processing needs in the AWP Olmos Field for the foreseeable
future. Additionally, at the discretion of the Company and Valero, the gas
processed and transported under these agreements may be sold to Valero at
indexed prices based upon the Inside F.E.R.C. Gas Market Report Houston Ship
Channel Monthly Price.
The following table summarizes sales volume, sales price and production
cost information for the Company's net oil and gas production for the three-year
period ended December 31, 1995 and the nine-month periods ended September 30,
1996 and 1995. "Net" production is production that is owned by the Company
either directly or indirectly through partnerships or joint venture interests
and produced to its interest after deducting royalty, limited partner and other
similar interests.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- --------------------------
1996 1995 1995 1994 1993
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbl).................................... 459 394 545 467 324
Natural gas (MMcf)(1)......................... 10,833 5,482 7,914 6,799 5,422
Gas equivalents (MMcfe)....................... 13,589 7,846 11,187 9,601 7,369
WEIGHTED AVERAGE SALES PRICES:
Oil (per Bbl)................................. $18.96 $15.61 $15.66 $14.35 $15.10
Natural gas (per Mcf)(2)...................... 2.31 1.65 1.77 1.93 1.96
SELECTED DATA PER MCFE:
Production costs.............................. $ 0.42 $ 0.65 $ 0.61 $ 0.59 $ 0.62
</TABLE>
(See footnotes on following page)
34
<PAGE> 35
- ---------------
(1) Natural gas production for 1995, 1994, 1993, and the nine-month periods
ended September 30, 1996 and 1995 includes 1,211, 1,358, 1,581, 868 and 917
MMcf, respectively, delivered under the volumetric production payment
pursuant to which the Company is obligated to deliver certain monthly
quantities of natural gas. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- General" and Note 9 to the
Consolidated Financial Statements.
(2) The above natural gas prices reflect the high Btu content of the natural gas
produced from the Company's AWP Olmos and Austin Chalk properties. Gas is
sold on the basis of price per MMBtu, which measures the heating equivalent
of such gas. The prices per Mcf above (Mcf being strictly a physical measure
of natural gas volumes) are therefore higher than the prices which would be
paid for natural gas with a lower Btu content.
Under the volumetric production payment entered into in 1992, as of
December 31, 1995 and September 30, 1996, the Company has a remaining commitment
to deliver approximately 4.1 Bcf and 3.3 Bcf of gas, respectively, meeting
certain heating equivalent and quality standards through October 2000, when such
agreement expires. Since entering into this agreement, these properties have
produced in excess of the required monthly delivery requirements.
PRICE RISK MANAGEMENT
In recent years the Company has purchased price floors, or "put" options to
provide downside price protection while preserving the benefit of rising prices.
During the first nine months of 1996, the Company spent $784,000 to purchase put
options covering varying amounts of the Company's and its partnerships'
production, ranging between 26% and 56% of such oil production at floor prices
ranging from $16.00 to $17.50 per Bbl and between 36% and 57% of its gas
production at prices ranging from $1.65 to $2.20 per Mcf. The Company's options
currently extend through March 1997. Through the first nine months of 1996, all
such options expired unexercised. The net cost of gas put options was $0.029 and
$0.039 per Mcfe during 1995 and the first nine months of 1996, respectively. The
net cost of oil put options was $0.278 and $0.200 per Bbl during 1995 and the
first nine months of 1996, respectively. For the amounts of oil and natural gas
covered by the options, if the options were exercised, in the aggregate, the
Company would receive the specified option floor prices, irrespective of the
prices actually paid by the purchasers of such products.
ACQUISITION ACTIVITIES
Since 1979, the Company has acquired approximately $465.0 million of
producing oil and natural gas assets on behalf of itself and its co-investors in
122 separate transactions. The Company has acquired for its own account
approximately $111.6 million of producing properties, with original proved
reserves estimated at 145 Bcfe. The Company's acquisition activities have
declined over the past three years, with approximately $21.8 million, $13.1
million and $3.5 million of producing properties acquired in 1993, 1994, and
1995, respectively. For 1996 for its own account, the Company anticipates
spending approximately $1.5 million to purchase limited partner interests from
existing limited partnerships.
The Company uses a disciplined, market-driven approach to acquisitions. The
Company generally seeks acquisition of properties for its own account that are
in close proximity to its current reserves and provide the potential to add
reserves through additional development efforts. As the market for acquisitions
has become more competitive in recent years, the Company has taken the
initiative in creating acquisition opportunities by directly soliciting property
owners who have not placed their properties on the market. Properties are
acquired after the Company has analyzed and evaluated available reservoir
engineering, geological and geophysical data. In evaluating producing properties
prior to purchase, the Company assesses many factors, including estimated
reserves,
35
<PAGE> 36
anticipated cash flows from production, production costs and various factors
affecting the marketing of production.
FOREIGN ACTIVITIES
Russia. On September 3, 1993, the Company signed a Participation Agreement
with Senega, a Russian Federation joint stock company (in which the Company has
an indirect interest of less than 1%), to assist in the development and
production of reserves from two fields in Western Siberia, providing the Company
with a minimum 5% net profits interest from the sale of hydrocarbon products
from the fields for providing managerial, technical and financial support to
Senega. Additionally, the Company purchased a 1% net profits interest from
Senega for $300,000. In May 1995, the Company executed a Management Agreement
with Senega, under which, in return for undertaking to obtain financing for
development of these fields, the Company is entitled to receive a 49% interest
in production income derived by Senega from this project after repayment of
costs. At September 30, 1996, the Company's investment in activities in Russia
was approximately $9.2 million.
On July 12, 1996, the Company entered into a partnership agreement which
provides for the Company to contribute its rights under the Participation and
Management Agreements to the partnership and for the partners to share equally
revenues and costs of developing the Samburg Field and funding and management of
the license areas, all in conjunction with Senega. The partnership is to be
funded by the partners upon fulfillment of certain conditions and completion of
certain further arrangements with Senega. It is currently anticipated that these
activities would be funded principally through project financing.
New Zealand. Since October 1995, the Company has been issued two Petroleum
Exploration Permits by the New Zealand Minister of Energy. The first permit
covers approximately 65,000 acres in the Onshore Taranaki Basin region in the
southwestern area of New Zealand's North Island and the second covers
approximately 71,500 acres adjacent to the acreage covered by the first permit.
Under the terms of the permits, the Company is obligated to analyze and
interpret certain seismic data, acquire certain new seismic data, drill one
exploratory well, and either drill a further development well or perform
additional seismic work, all of which activities are to be performed on a staged
basis in order to maintain the permits, over periods extending through July 2000
in the case of the first permit, and through July 2001 for the second permit. At
September 30, 1996, the Company's investment in New Zealand was approximately
$600,000.
Venezuela. The Company formed a wholly-owned subsidiary, Swift Energy de
Venezuela, C.A., for the purpose of submitting a bid on August 5, 1993, under
the Venezuelan Marginal Oil Field Reactivation Program. Although the Company did
not win the bid, it is continuing to pursue cooperative ventures involving other
fields and opportunities in Venezuela. At September 30, 1996, the Company's
investment in Venezuela was approximately $1.4 million.
OIL AND GAS RESERVES
All information set forth in this Prospectus regarding proved reserves,
related future net revenues and PV-10 Value is taken from reports prepared by
the Company and audited by Gruy. Gruy's estimates were based upon review of
production histories and other geological, economic, ownership and engineering
data provided by the Company, and their report is contained as an exhibit to the
Registration Statement of which this Prospectus is a part. No other reports on
the Company's reserves have been filed with any federal agency. In accordance
with Commission guidelines, the Company's estimates of future net revenues from
the Company's proved reserves and the present value thereof (PV-10 Value) are
made using oil and gas sales prices in effect as of the dates of such estimates
and are held constant throughout the life of the properties, except where such
guidelines permit alternate treatment, including, in the case of gas contracts,
the use of fixed and determinable contractual price escalations. Proved reserves
at December 31, 1995, were
36
<PAGE> 37
estimated based upon weighted average prices of $2.41 per Mcf of natural gas and
$18.07 per Bbl of oil, compared to $1.85 and $2.50 per Mcf of natural gas and
$15.09 and $12.87 per Bbl of oil as of December 31, 1994 and 1993, respectively.
See "Risk Factors -- Uncertainty of Estimates of Reserves and Future Net
Revenues."
The Company's total proved developed and undeveloped reserve volumes have
increased at an annual compound rate of approximately 35% over the last five
years. In 1995, the Company's proved natural gas reserves increased over 1994
year-end amounts by 88% or 67.3 Bcf and its proved oil reserves increased 19% or
868,714 Bbl. The composition of these reserves has shifted substantially, with
proved developed reserves comprising 63% of total proved reserves at year-end
1994, and 58% at December 31, 1995. This shift reflects the recent reserve
additions comprised of proved undeveloped reserves in newly acquired areas of
the AWP Olmos Field. Additional reserves have also been added due to December
31, 1995 prices being higher than those at year-end 1994, which has the effect
of changing quantities estimates and the estimated present value of such proved
reserves.
The table below also sets forth estimates of future net revenues, presented
on the basis of unescalated prices and costs in accordance with criteria
prescribed by the Commission, and the PV-10 Value. Operating costs and
development costs and certain production-related taxes were deducted in arriving
at the estimated future net revenues. No provision was made for income taxes.
The estimates of future net revenues and their present value differ in this
respect from the standardized measure of discounted future net cash flows set
forth in the Notes to the Consolidated Financial Statements of the Company,
which is calculated after provision for future income taxes. In cases where
producing properties are subject to gas purchase contracts and the amount of gas
purchased thereunder was reduced during 1995, gas projections used to estimate
future net revenues were based on the reduced gas purchases for the affected
producing properties. The assumption was made that purchases in 1996 and
thereafter will be made at an unrestricted level. The Company has interests in
certain tracts which are estimated to have additional hydrocarbon reserves which
are not classified as proved and are not reflected in the following table. The
proved reserves presented for all periods also exclude any reserves attributed
to the volumetric production payment. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- General" and Note 9 to the
Company's Consolidated Financial Statements. There can be no assurance that
these estimates are accurate predictions of future net revenues from oil and gas
reserves or their present value.
ESTIMATED PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
AT DECEMBER 31,
----------------------------
1995 1994 1993
------- ------- ------
<S> <C> <C> <C>
NET NATURAL GAS RESERVES (MMCF):
Proved developed..................................... 81,532 46,406 50,937
Proved undeveloped................................... 62,036 29,858 13,526
------- ------- ------
Total proved natural gas reserves............ 143,568 76,264 64,463
------- ------- ------
NET OIL RESERVES (MBBL):
Proved developed..................................... 3,313 3,209 3,110
Proved undeveloped................................... 2,109 1,344 1,161
------- ------- ------
Total proved oil reserves.................... 5,422 4,553 4,271
------- ------- ------
TOTAL PROVED RESERVES (MMCFE).......................... 176,099 103,584 90,089
======= ======= ======
</TABLE>
37
<PAGE> 38
ESTIMATED PRESENT VALUE OF PROVED RESERVES
<TABLE>
<CAPTION>
AT DECEMBER 31,
------------------------------
1995 1994 1993
-------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
ESTIMATED PV-10 VALUE:
Proved developed.................................. $ 85,537 $47,172 $66,310
Proved undeveloped................................ 61,501 22,223 17,451
-------- ------- -------
Total..................................... $147,038 $69,395 $83,761
</TABLE>
Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserves estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered. There can be
no assurance that these estimates are accurate predictions of the present value
of future net cash flows from oil and gas reserves.
A portion of the Company's proved reserves has been accumulated through the
Company's interests in the limited partnerships for which it serves as general
partner. The estimates of future net revenues and their present values assume
that some portion of the limited partnerships in which the Company owns
interests will achieve payout status. At payout, the Company's percentage
ownership of the limited partnerships' reserves increases. The primary
assumptions utilized for purposes of such estimates consist of (i) the
continuation of oil and gas prices realized by the partnerships at year-end 1995
through the life of the properties owned by the partnerships and (ii) the
continued ownership of such properties. Only three of the limited partnerships
in which the Company owns an interest had achieved payout status at the date of
this Prospectus and achievement of payout status for the remaining partnerships
will depend not only upon prices at which future production is sold, but also
upon whether individual properties are sold prior to depletion and the prices
received in such sales. See "Risk Factors -- Volatility of Oil and Gas Prices
and Markets and -- Uncertainty of Estimates of Reserves and Future Net
Revenues."
DRILLING ACTIVITY
The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 1995 and the first
nine months of 1996:
<TABLE>
<CAPTION>
GROSS WELLS NET WELLS(1)
--------------------------------- ---------------------------------
PERIOD TYPE OF WELL(2) TOTAL PRODUCING(3) DRY(4) TOTAL PRODUCING(3) DRY(4)
- -------- --------------- ----- ------------ ------ ----- ------------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
1996 Exploratory 6 4 2 2.8 1.9 0.9
(Through Development 96 92 4 75.8 73.8 2.0
9/30)
1995 Exploratory 8 4 4 3.5 1.5 2.0
Development 68 65 3 38.7 38.0 0.7
1994 Exploratory 14 6 8 9.2 4.7 4.5
Development 30 26 4 6.9 5.0 1.9
1993 Exploratory 12 5 7 5.6 2.5 3.1
Development 22 21 1 3.8 3.4 0.4
</TABLE>
(See footnotes on following page)
38
<PAGE> 39
- ---------------
(1) Represents the aggregate of the Company's direct or indirect fractional
working interests in the gross wells drilled.
(2) An exploratory well is a well drilled either in search of a new, as-yet
undiscovered oil or gas reservoir or to greatly extend the known limits of a
previously discovered reservoir. A development well is a well drilled within
the presently proved productive area of an oil or gas reservoir, as
indicated by reasonable interpretation of available data, with the objective
of completing in that reservoir.
(3) A producing well is an exploratory or development well found to be capable
of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
(4) A dry well is an exploratory or development well that is not a producing
well.
The following table sets forth the gross and net wells in which the Company
owned an interest at the following dates:
<TABLE>
<CAPTION>
OIL WELLS GAS WELLS TOTAL WELLS(1)
--------- --------- --------------
<S> <C> <C> <C>
December 31, 1995
Gross(2)...................................... 3,049 995 4,044
Net(3)........................................ 88.5 121.6 210.1
December 31, 1994
Gross(2)...................................... 3,141 1,000 4,141
Net(3)........................................ 79.3 109.1 188.4
December 31, 1993
Gross(2)...................................... 3,165 872 4,037
Net(3)........................................ 72.5 52.4 124.9
</TABLE>
- ---------------
(1) Excludes 39 service wells in 1995, 31 service wells in 1994, and 165 service
wells in 1993.
(2) A gross well is a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is
owned.
(3) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
fractional working interests owned in gross wells expressed as whole numbers
and fractions thereof.
39
<PAGE> 40
OIL AND GAS ACREAGE
As is customary in the industry, the Company generally acquires oil and gas
acreage without any warranty of title except as to claims made by, through, or
under the transferor. Although the Company has title to developed acreage
examined prior to acquisition in those cases in which the economic significance
of the acreage justifies the cost, there can be no assurance that losses will
not result from title defects or from defects in the assignment of leasehold
rights. In many instances, title opinions may not be obtained if in the
Company's judgment it would be uneconomical or impractical to do so.
The following table sets forth the developed and undeveloped leasehold
acreage held by the Company at December 31, 1995:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------------ ----------------------
GROSS (1) NET (2) GROSS (1) NET (2)
---------- ---------- --------- ---------
<S> <C> <C> <C> <C>
Alabama........................... 7,075.72 820.82 372.00 61.17
Arkansas.......................... 8,960.45 3,271.17 4,754.86 2,978.63
Kansas............................ 1,630.00 571.67 5,450.00 2,268.55
Louisiana......................... 56,766.05 18,620.66 11,985.24 7,222.14
Mississippi....................... 10,680.29 4,211.95 4,965.61 887.68
Nebraska.......................... -- -- 1,707.04 1,029.53
New Mexico........................ 1,854.47 473.61 240.00 28.80
North Dakota...................... 1,276.19 147.25 160.00 17.32
Oklahoma.......................... 54,270.93 21,420.96 4,410.02 2,103.06
Texas............................. 116,635.23 53,438.69 22,897.00 15,938.33
West Virginia..................... 16,048.20 10,484.50 -- --
Wyoming........................... 10,434.00 3,225.25 27,177.72 10,941.82
All other states.................. 477.64 128.66 4,690.44 272.81
---------- ---------- --------- ---------
TOTAL............................. 286,109.17 116,815.19 88,809.93 43,749.84
========== ========== ========= =========
</TABLE>
- ---------------
(1) A gross acre is an acre in which a working interest is owned. The number of
gross acres is the total number of acres in which a working interest is
owned.
(2) A net acre is deemed to exist when the sum of fractional ownership working
interests in gross acres equals one. The number of net acres is the sum of
fractional working interests owned in gross acres expressed as whole numbers
and fractions thereof. A material portion of the Company's acreage is owned
by virtue of its interests derived from limited partnerships. The net
acreage reflected on this table shows the Company's interests assuming that
an after-payout status is achieved in some of these limited partnerships. At
September 30, 1996, three of the limited partnerships had achieved payout
status. See "-- Oil and Gas Reserves" above.
PARTNERSHIPS
Prior to 1993, the Company relied to a large extent on limited partnerships
as a principal financing vehicle to fund its activities. The Company had formed
103 limited partnerships which have raised a total of approximately $478.0
million at September 30, 1996. However, as the Company has increasingly shifted
its emphasis to exploration and development activities and its reserve base has
grown, the Company has significantly reduced its reliance on limited partnership
financing.
More than 21 of the limited partnerships formed and managed by the Company
have been in operation over nine years and have produced a substantial majority
of their reserves. Given the age of these limited partnerships, the limited
partners in 18 of these partnerships have voted to sell their remaining
properties and liquidate the limited partnerships. It is anticipated that these
partnerships will be liquidated in late 1996. The Company intends to make
similar proposals to other partnerships for an orderly sale of their properties
and liquidation of the partnerships over the next several years.
40
<PAGE> 41
The Company may acquire portions of the remaining property interests owned by
these limited partnerships.
From 1991 to 1995 the Company sponsored SDI, a publicly offered partnership
program under which partnerships were formed to acquire interests in producing
oil and gas assets. The Company concluded the SDI Program upon the formation of
its last two partnerships in December 1995. Under the SDI program, partnerships
were formed on a sequential basis and in 1995, the Company raised approximately
$12.4 million under this program. The SDI partnerships acquire, manage and
ultimately sell interests in properties that are producing oil and gas in
commercial quantities. The SDI partnerships seek to profit primarily from the
sale of oil and gas produced from the properties in which they own interests,
and ultimately from the proceeds of the eventual sale of their interests.
In September of 1993, the Company began offering interests in privately
offered partnerships formed to engage in the drilling of development and
exploratory wells. As of September 30, 1996, seven partnerships had been formed
(one in 1993, one in 1994, three in 1995 and two in 1996) with aggregate
investor contributions of approximately $34.8 million. The private drilling
partnerships are offered on a no-load basis under which the Company pays all
selling and offering expenses of the offering. Selling and offering expenses
paid by the Company are treated as a capital contribution to each partnership.
The Company also is entitled to a general and administrative overhead allowance
and an incentive amount. In certain partnerships, the Company does not bear any
of the costs incurred in acquiring or drilling properties. As managing general
partner of certain other partnerships, the Company pays out of its own corporate
funds the capital costs (consisting of all prospect costs and the
non-deductible, tangible portion of drilling and completion costs). The Company
pays between 20% and 40% of all continuing costs (higher amounts after payout)
and is entitled to receive between 20% and 40% of net revenues distributed by
each partnership (and higher amounts after payout). The Company anticipates that
it will continue to offer the drilling partnerships for the foreseeable future.
Under the terms of the Company's limited partnership programs, the Company
generally retains the right to engage in oil and gas exploration and production
through other limited partnerships and joint ventures and for its own account.
The partnership agreement for each limited partnership contains detailed
provisions regarding the terms upon which a variety of transactions between the
Company and the limited partnership may be carried out, including (i) sales of
properties by the Company to the limited partnership, (ii) operation of limited
partnership properties by the Company, (iii) rendering of oil field or drilling
services by the Company to the limited partnership, (iv) handling of limited
partnership funds by the Company and (v) loans between the Company and the
limited partnership. These restrictions, which may limit the ability of the
Company to take certain actions, are intended to ensure that transactions
between the Company and its limited partnerships are fair to such limited
partnerships.
MANAGEMENT OF RISKS OF OPERATION
The Company's operations are subject to all of the risks normally incident
to the exploration for and the production of oil and gas, including blowouts,
cratering, pipe failure, casing collapse, oil spills and fires, each of which
could result in severe damage to or destruction of oil and gas wells, production
facilities or other property, or individual injuries. The oil and gas
exploration business is also subject to environmental hazards, such as oil
spills, gas leaks, and ruptures and discharges of toxic substances or gases that
could expose the Company to substantial liability due to pollution and other
environmental damage. Additionally, as managing general partner of limited
partnerships, the Company is solely responsible for the day-to-day conduct of
the limited partnerships' affairs and accordingly has liability for expenses and
liabilities of the limited partnerships. The Company maintains comprehensive
insurance coverage, including general liability insurance in an amount not less
than $20.0 million, as well as general partner liability insurance. The Company
believes that its insurance is adequate and customary for companies of a similar
size engaged in comparable
41
<PAGE> 42
operations, but losses could occur for uninsurable or uninsured risks or in
amounts in excess of existing insurance coverage.
COMPETITION
The oil and gas industry is highly competitive in all its phases. The
Company encounters strong competition from many other oil and gas producers,
including many that possess substantial financial resources, in acquiring
economically desirable producing properties and exploratory drilling prospects,
and in obtaining equipment and labor to operate and maintain its properties.
REGULATIONS
Environmental Regulations. The federal government and various state and
local governments have adopted laws and regulations regarding the control of
contamination of the environment. These laws and regulations may require the
acquisition of a permit by operators before drilling commences, prohibit
drilling activities on certain lands lying within wilderness areas or where
pollution arises, and impose substantial liabilities for pollution resulting
from drilling operations particularly operations in offshore waters or on
submerged lands. These laws and regulations may also increase the costs of
routine drilling and operation of wells. Because these laws and regulations
change frequently, the costs to the Company of compliance with existing and
future environmental regulations cannot be predicted. See "Risk
Factors -- Effects of Governmental Regulation."
Federal Regulation of Natural Gas. The transportation and sale of natural
gas in interstate commerce is heavily regulated by agencies of the federal
government. The following discussion is intended only as a brief summary of the
principal statutes, regulations and orders that may affect the production and
sale of the Company's natural gas. This summary should not be relied upon as a
complete review of applicable natural gas regulatory provisions.
FERC Orders. Several major regulatory changes have been implemented by the
Federal Energy Regulatory Commission ("FERC") from 1985 to the present that
affect the economics of natural gas production, transportation and sales. In
addition, the FERC continues to promulgate revisions to various aspects of the
rules and regulations affecting those segments of the natural gas industry that
remain subject to the FERC's jurisdiction. In April 1992, the FERC issued Order
No. 636 pertaining to pipeline restructuring. This rule requires interstate
pipelines to unbundle transportation and sales services by separately stating
the price of each service and by providing customers only the particular service
desired, without regard to the source for purchase of the gas. The rule also
requires pipelines to (i) provide nondiscriminatory "no-notice" service allowing
firm commitment shippers to receive delivery of gas on demand up to certain
limits without penalties, (ii) establish a basis for release and reallocation of
firm upstream pipeline capacity and (iii) provide non-discriminatory access to
capacity by firm transportation shippers on a downstream pipeline. The rule
requires interstate pipelines to use a straight fixed variable rate design.
FERC Order No. 500 affects the transportation and marketability of natural
gas. Traditionally, natural gas has been sold by producers to pipeline
companies, which then resold the gas to end-users. FERC Order No. 500 alters
this market structure by requiring interstate pipelines that transport gas for
others to provide transportation service to producers, distributors and all
other shippers of natural gas on a nondiscriminatory, "first-come, first-served"
basis ("open access transportation"), so that producers and other shippers can
sell natural gas directly to end-users. FERC Order No. 500 contains additional
provisions intended to promote greater competition in natural gas markets.
It is not anticipated that the marketability of and price obtainable for
the Company's natural gas production will be significantly affected by FERC
Order No. 500. Gas produced normally will be sold to intermediaries who have
entered into transportation arrangements with pipeline companies.
42
<PAGE> 43
These intermediaries will accumulate gas purchased from a number of producers
and sell the gas to end-users through open access transportation.
State Regulations. Production of any oil and gas by the Company will be
affected to some degree by state regulations. Many states in which the Company
operates have statutory provisions regulating the production and sale of oil and
gas, including provisions regarding deliverability. Such statutes, and the
regulations promulgated in connection therewith, are generally intended to
prevent waste of oil and gas and to protect correlative rights to produce oil
and gas between owners of a common reservoir. Certain state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.
FEDERAL LEASES
Some of the Company's properties are located on federal oil and gas leases
administered by various federal agencies, including the Bureau of Land
Management. Various regulations and orders affect the terms of leases,
exploration and development plans, methods of operation and related matters.
EMPLOYEES
At December 31, 1995, the Company employed 176 persons, including 24
engineers, 12 geologists and geophysicists and 9 landmen. None of the Company's
employees are represented by a union. Relations with employees are considered to
be good.
FACILITIES
The Company and its subsidiaries occupy approximately 75,000 square feet of
office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease
expiring in 2005 which provides for various expansion options. The lease
requires payments of approximately $81,000 per month. A subsidiary of the
Company maintains an office in Denver, Colorado. The Company has field offices
in various locations from which Company employees supervise local oil and gas
operations.
LEGAL PROCEEDINGS
No legal proceedings are pending other than ordinary routine litigation
incidental to the Company's business.
43
<PAGE> 44
MANAGEMENT
DIRECTORS, EXECUTIVE OFFICERS AND CERTAIN OTHER OFFICERS
<TABLE>
<CAPTION>
NAME TITLE
---- -----
<S> <C>
A. Earl Swift................. Chairman of the Board, President and Chief Executive
Officer
Virgil N. Swift............... Vice Chairman of the Board and Executive Vice
President -- Business Development
Terry E. Swift................ Executive Vice President and Chief Operating Officer
John R. Alden................. Senior Vice President -- Finance, Chief Financial
Officer and Secretary
Bruce H. Vincent.............. Senior Vice President -- Funds Management
James M. Kitterman............ Senior Vice President -- Operations
James R. Stewart.............. Vice President -- Drilling and Production
Alton D. Heckaman, Jr......... Vice President and Controller
Joseph A. D'Amico............. Vice President-Exploration and Development
G. Robert Evans............... Director
Raymond O. Loen............... Director
Henry C. Montgomery........... Director
Clyde W. Smith, Jr............ Director
Harold J. Withrow............. Director
</TABLE>
A. Earl Swift, 63, is President, Chief Executive Officer and Chairman of
the Board of Directors of the Company and has served in such capacity since its
founding in 1979. For the 17 years prior to 1979, he was employed by affiliates
of American Natural Resources Company, serving his last three years as Vice
President of Exploration and Production for Michigan-Wisconsin Pipe Line Company
and American Natural Gas Production Company. Mr. Swift is a registered
professional engineer and holds a degree in Petroleum Engineering, a Juris
Doctor degree and a Master's degree in Business Administration. He is the
brother of Virgil N. Swift and the father of Terry E. Swift.
Virgil N. Swift, 67, has been a director of the Company since 1981, and has
acted as Vice Chairman of the Board and Executive Vice President-Business
Development since November 1991. He previously served as Executive Vice
President and Chief Operating Officer from 1982 to November 1991. Mr. Swift
joined the Company in 1981 as Vice President-Drilling and Production. For the
preceding 28 years he held various production, drilling and engineering
positions with Gulf Oil Corporation and its subsidiaries, last serving as
General Manager-Drilling for Gulf Canada Resources, Inc. Mr. Swift is a
registered professional engineer and holds a degree in Petroleum Engineering.
Terry E. Swift, 40, was appointed Executive Vice President and Chief
Operating Officer of the Company in November 1991. He served as Senior Vice
President -- Exploration and Joint Ventures from 1990 to November 1991, as Vice
President -- Exploration and Joint Ventures from 1988 to 1990 and as Assistant
Vice President -- Engineering from 1986 to 1988. Mr. Swift is a registered
professional engineer and holds a degree in Chemical Engineering and a Master's
degree in Business Administration.
John R. Alden, 50, Senior Vice President -- Finance, Chief Financial
Officer and Secretary, joined the Company in 1981. Mr. Alden was appointed to
his current offices in 1990. Prior to that time he served the Company as its
principal financial officer under a variety of titles. Mr. Alden holds a degree
in Accounting and a Master's degree in Business Administration.
Bruce H. Vincent, 49, joined the Company as Senior Vice President -- Funds
Management in 1990. Mr. Vincent acted as Chief Operating Officer of Energy
Assets International Corp. from 1986
44
<PAGE> 45
to 1988, and as President of Vincent & Company, an investment banking firm, from
1988 to 1990. Mr. Vincent holds a degree in Business Administration and a
Master's degree in Finance.
James M. Kitterman, 52, was appointed Senior Vice President -- Operations
in May 1993. He had previously served as Vice President -- Operations since
joining the Company in 1983 with 16 years of prior experience in oil and gas
exploration, drilling and production. Mr. Kitterman holds a degree in Petroleum
Engineering and a Master's degree in Business Administration.
James R. Stewart, 60, was appointed Vice President -- Drilling and
Production in August 1993. He joined the Company as Manager of Operations in
1990. He has 30 years experience in drilling, production, reservoir engineering,
and geology. During his 30 years in the oil and gas industry, Mr. Stewart has
held a variety of management level positions. Mr. Stewart holds a degree in
Petroleum Engineering.
Alton D. Heckaman, Jr., 39, was appointed Vice President and Controller in
May 1993. He had previously served as Assistant Vice President -- Finance and
Controller since 1986. Mr. Heckaman joined the Company in 1982. He is a
Certified Public Accountant and holds a degree in Accounting.
Joseph A. D'Amico, 48, has been Vice President -- Exploration and
Development of the Company since August 1993. He served in the funds management
division and as Director of Exploration and Development of the Company from 1988
to 1993. Mr. D'Amico holds a degree in Petroleum Engineering and Master's
degrees in Petroleum Engineering and Finance.
G. Robert Evans, 65, has been a director of the Company since 1994. Since
1991, he has been Chairman and Chief Executive Officer of Material Sciences
Corporation of Elk Grove Village, a corporation that develops and commercializes
continuously processed, coated materials technologies. He is also currently
serving as a director of three other public companies: Consolidated Freightways,
Inc. (transportation), Fibreboard Corporation (wood products, insulation and
resort operations) and Elco Industries (manufacturing). From 1990 until 1991, he
served as President, Chief Executive Officer and a Director of Corporate Finance
Associates of Illinois, Inc., a financial intermediary and consulting firm. From
1987 until 1990, he served as President, Chief Executive Officer and a Director
of Bemrose Group USA, a British holding company engaged in value-added
manufacturing and sale of products to the advertising specialty industry.
Raymond O. Loen, 72, has served as a director of the Company since its
founding in 1979. Since 1963, he has been President of R.O. Loen Company, a
privately held management consulting firm headquartered in Lake Oswego, Oregon.
Henry C. Montgomery, 60, has served as a director of the Company since
1987. Since 1980, Mr. Montgomery has been the Chairman of the Board of
Montgomery Financial Services Corporation, a management consulting and financial
services firm. Mr. Montgomery previously served, from 1989 until December 1995,
as a director of Catalyst Semiconductor, Inc., a public company engaged in the
design and manufacture of semiconductors. He was also previously a director of
Southwall Technologies, Inc., a company engaged in thin film deposition
technologies, from 1982 until April 1995. Mr. Montgomery previously served as
Chairman of the Board of each of Private Financial Services Corporation, a
management consulting and financial services firm (1986 to 1989), and
Aquanautics Corporation, a public company involved in the extraction of oxygen
from water and air (1986 to 1991).
Clyde W. Smith, Jr., 47, has served as a director of the Company since
1984. He has served as President of Somerset Properties, Inc., a real estate and
investment company, since 1985, as President of AdVision, Inc., which markets
video display merchandising systems, since 1988 and as President of H&R
Precision, Inc., a general contractor, since 1994. Mr. Smith formerly acted as
Chief Executive Officer of California Video Sales, Inc. from 1987 to 1990.
Harold J. Withrow, 69, has been a director of the Company since 1988. Mr.
Withrow is an independent oil and gas consultant. From 1975 until 1988, Mr.
Withrow served as Senior Vice President -- Gas Supply for Michigan Wisconsin
Pipe Line Company and its successor, ANR Pipeline Company.
45
<PAGE> 46
PRINCIPAL SHAREHOLDERS
The following table sets forth information concerning the shareholdings, as
of September 30, 1996, of the seven current members of the board of directors,
each of the Company's five most highly compensated executive officers, all
executive officers and directors as a group, and each person who beneficially
owns more than five percent of the Company's outstanding Common Stock.
<TABLE>
<CAPTION>
SHARES OF COMMON STOCK
BENEFICIALLY OWNED AT
SEPTEMBER 30, 1996(1)
------------------------
PERCENT OF
CLASS
NAME OF PERSON OR GROUP POSITION NUMBER OUTSTANDING
- ----------------------------- -------------------------------------- --------- -----------
<S> <C> <C> <C>
A. Earl Swift................ Chairman of the Board, President,
Chief Executive Officer 282,472(2) 1.9%
Virgil N. Swift.............. Vice Chairman of the Board,
Executive Vice President -- Business
Development 320,280 2.1%
G. Robert Evans.............. Director 6,400 (3)
Raymond O. Loen.............. Director 146,756(4) 1.0%
Henry C. Montgomery.......... Director 33,780 (3)
Clyde W. Smith, Jr........... Director 17,400 (3)
Harold J. Withrow............ Director 17,500 (3)
Terry E. Swift............... Executive Vice President, Chief
Operating Officer 90,636 (3)
John R. Alden................ Senior Vice President -- Finance,
Chief Financial Officer, Secretary 76,101(5) (3)
James M. Kitterman........... Senior Vice President -- Operations 63,370 (3)
All executive officers and directors as a group (12 persons).......... 1,146,996 7.6%
FMR Corp.............................................................. 1,291,458(6) 8.6%(6)
82 Devonshire Street
Boston, Massachusetts 02109
State Street Research & Management Company............................ 1,284,450(7) 8.5%(7)
Metropolitan Life Insurance Company
One Financial Center, 30th Floor
Boston, Massachusetts 02111-2690
Foreign & Colonial Management Limited................................. 935,052(8) 6.2%(8)
Hypo Foreign & Colonial Management (Holdings) Limited
Exchange House, Primrose Street
London EC2A 2NY England
</TABLE>
- ---------------
(1) Unless otherwise indicated below, the persons named have sole voting and
investment power over the number of shares of the Company's Common Stock
shown as being owned by them. The table includes the following shares that
were acquirable within 60 days following September 30, 1996 by exercise of
options granted under the Company's stock option plans: Mr. A. E.
Swift -- 56,648; Mr. V. N. Swift -- 50,424; Mr. Evans -- 4,400; Mr.
Loen -- 27,400; Mr. Smith -- 16,400; Mr. Montgomery -- 30,370; Mr.
Withrow -- 15,300; Mr. T. E. Swift -- 69,004; Mr. Alden -- 57,706; Mr.
Kitterman -- 48,290; and all executive officers and directors as a
group -- 446,562.
(2) Includes 858 shares held by Mr. Swift's wife.
(3) Less than one percent.
(Footnotes continued on following page)
46
<PAGE> 47
(4) Includes 14,300 shares as to which Mr. Loen, as co-trustee for an HR-10
Retirement Plan, shares voting and investment power with his wife; 70,000
shares held by his wife (who holds sole voting and investment power as to
those shares and 3,680 shares held in her IRA), and 4,554 shares held in Mr.
Loen's IRA.
(5) Includes 110 shares held by the estate of Mr. Alden's mother of which he
could be deemed to be the beneficial owner.
(6) Based on a Schedule 13G dated February 8, 1996 filed with the Securities and
Exchange Commission, Fidelity Management & Research Company ("Fidelity"), a
wholly-owned subsidiary of FMR Corp., an Investment Adviser registered under
Section 203 of the Investment Advisers Act of 1940, is deemed to be the
beneficial owner of 1,291,458 shares of the Company's stock as a result of
acting as an investment adviser to several investment companies registered
under Section 8 of the Investment Company Act of 1940 (the "Funds"). Members
of the Edward C. Johnson 3d family, as well as trusts for their benefit, are
the predominant owners of Class B shares of Common Stock of FMR Corp.,
representing approximately 49% of the voting power of FMR Corp. Mr. Johnson
3d owns 12.0% and Abigail P. Johnson owns 24.5% of the aggregate outstanding
voting stock of FMR Corp. The Johnson family group and all other Class B
shareholders have entered into a shareholders' voting agreement under which
all Class B shares will be voted in accordance with the majority vote of
Class B shares. Accordingly, through their ownership of voting Common Stock
and the execution of the shareholder's voting agreement, members of the
Johnson family may be deemed, under the Investment Company Act of 1940, to
form a controlling group with respect to FMR Corp. Neither FMR Corp. nor
Edward C. Johnson 3d, Chairman of FMR Corp., has any power to vote or direct
the voting of the shares directly by the Funds, which power resides with the
Funds' Boards of Trustees.
(7) Based on Schedules 13G dated February 9, 1996 and February 13, 1996 filed
with the Securities and Exchange Commission. State Street Research and
Management Company ("State Street") is deemed to have beneficial ownership
of 1,284,450 shares of the Company's stock and reports sole power to vote
1,238,650 of these shares. State Street is an Investment Adviser registered
under Section 203 of the Investment Advisers Act of 1940 and is a wholly
owned subsidiary of Metropolitan Life Insurance Company. State Street
disclaims beneficial interest in all of the shares held by Metropolitan Life
Insurance Company.
(8) Based on Schedules 13G dated February 1, 1996 and February 8, 1996 filed
with the Securities and Exchange Commission. Of the shares listed, 53,789
were issued on August 6, 1996 upon conversion of the 6 1/2% Convertible
Subordinated Debentures. Foreign & Colonial Management Limited ("F&C") is
deemed to have beneficial ownership of 935,052 shares of the Company's
stock. F&C is an Investment Adviser registered under the Investment Advisers
Act of 1940 and is a wholly owned subsidiary of Hypo Foreign & Colonial
Management (Holdings) Limited. F&C disclaims beneficial interest in all of
the shares.
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<PAGE> 48
DESCRIPTION OF NOTES
GENERAL
The Notes will be issued under an indenture, to be dated as of November 25,
1996 (the "Indenture"), between the Company and Bank One, Columbus, N.A., as
trustee (the "Trustee"). A form of the Indenture is filed as an exhibit to the
Registration Statement of which this Prospectus is a part. The following
summaries of certain provisions of the Indenture do not purport to be complete
and are subject to and are qualified in their entirety by reference to, all of
the provisions of the Indenture, including the definitions therein of certain
terms. Capitalized terms used but not defined herein have the meanings given to
them in the Indenture.
The Notes are convertible at the option of the holder into Common Stock of
the Company. See "-- Conversion." The Notes are unsecured, will constitute
subordinated obligations of the Company and will rank pari passu in right of
payment to the Company's other subordinated indebtedness, if any. The Notes and
the Company's obligations with respect thereto (including the Company's
obligations to repurchase Notes upon the occurrence of a Designated Event) will
be subordinated in right of payment to all Senior Debt (as defined in the
Indenture) of the Company. As of September 30, 1996, the Company had
approximately $17.2 million of indebtedness outstanding under its existing
credit facilities that would have constituted Senior Debt. The Company intends
to use net proceeds from this offering to repay all of its outstanding
borrowings under its credit facilities, and as a result, the Company will not
have any Senior Debt immediately after such repayment. The Indenture does not
restrict, however, the amount of Senior Debt or other indebtedness of the
Company or any subsidiary of the Company that may be incurred in the future, and
the Company and its subsidiaries anticipate incurring Senior Debt or other
indebtedness in the future.
PRINCIPAL, MATURITY AND INTEREST
The Notes offered by this Prospectus will be limited to $100.0 million
aggregate principal amount, plus such additional amount not in excess of $15.0
million as may be purchased by the Underwriters upon exercise of the
over-allotment option. See "Underwriting." The Notes will mature on November 15,
2006. The Notes will bear interest at the rate per annum set forth on the cover
page of this Prospectus from November 25, 1996 or from the most recent interest
payment date to which interest has been paid or provided for, payable
semiannually on May 15 and November 15 of each year, commencing May 15, 1997, to
the person in whose name such Note is registered at the close of business on the
April 30 or October 31 preceding such interest payment date. Interest will be
computed on the basis of a 360 day year comprised of twelve 30-day months.
The Notes will be issuable and transferable in fully registered form and
will be issued in denominations of $1,000 and integral multiples thereof.
Principal, premium, if any, and interest on the Notes may, at the option of
the Company, be paid either (i) by check mailed to the address of the person
entitled thereto as it appears in the security register or (ii) by transfer to
an account maintained by the payee entitled thereto as specified in the security
register.
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<PAGE> 49
OPTIONAL REDEMPTION
The Notes may be redeemed at the option of the Company, in whole or in
part, at any time on or after November 15, 1999, on not less than 15 nor more
than 60 days' prior notice at the redemption prices (expressed as percentages of
principal amount) set forth below, together with accrued and unpaid interest, if
any, to the date of redemption, if redeemed during the 12-month period beginning
on November 15 of the years indicated below (subject to the right of holders of
record on relevant record dates to receive interest due on an interest payment
date):
<TABLE>
<CAPTION>
REDEMPTION
YEAR PRICE
---- ----------
<S> <C>
1999.................................................... 104.375%
2000.................................................... 103.750%
2001.................................................... 103.125%
2002.................................................... 102.500%
2003.................................................... 101.875%
2004.................................................... 101.250%
2005.................................................... 100.625%
</TABLE>
If less than all of the Notes are to be redeemed, the Trustee shall select
the Notes or portions thereof to be redeemed either in compliance with the
requirements of the principal national securities exchange, if any, on which the
Notes are listed or, if the Notes are not so listed, pro rata or by lot or by
any other method the Trustee deems fair and appropriate.
MANDATORY REDEMPTION
The Company is not required to make mandatory redemption or sinking fund
payments with respect to the Notes.
REPURCHASE AT THE OPTION OF HOLDERS
Upon the occurrence of a Designated Event (as defined below), each holder
of Notes shall have the right to require the Company to repurchase all or any
part (equal to $1,000 or an integral multiple thereof) of such holder's Notes
(the "Designated Event Repurchase") at a purchase price equal to 101% of the
principal amount thereof, together with accrued and unpaid interest thereon to
the Designated Event Payment Date (the "Designated Event Payment"). Within 30
days following any Designated Event, the Company shall mail a notice to each
holder stating: (1) that the Designated Event Repurchase is being made pursuant
to the covenant entitled "Designated Event" and that all Notes tendered will be
accepted for payment; (2) the purchase price and the purchase date, which shall
be no earlier than 30 days nor later than 40 days from the date such notice is
mailed (the "Designated Event Payment Date"); (3) that any Notes not tendered
will continue to accrue interest; (4) that, upon the payment of the Designated
Event Payment, all Notes accepted for payment pursuant to the Designated Event
Repurchase shall cease to accrue interest after the Designated Event Payment
Date; (5) that holders electing to have any Notes purchased pursuant to a
Designated Event Repurchase will be required to surrender the Notes, with the
form entitled "Option of Holder to Elect Purchase" on the reverse of the Notes
completed, to the Trustee at the address specified in the notice prior to the
close of business on the third Business Day preceding the Designated Event
Payment Date; (6) that holders will be entitled to withdraw their election if
the Trustee receives, not later than the close of business on the second
Business Day preceding the Designated Event Payment Date, a telegram, telex,
facsimile transmission or letter setting forth the name of the holder, the
principal amount of Notes delivered for purchase, and a statement that such
holder is withdrawing his election to have such Notes purchased; (7) that
holders whose Notes are being purchased only in part will be issued new Notes
equal in principal amount to the unpurchased portion of the Notes surrendered,
which unpurchased portion must be equal to $1,000 in principal amount or an
integral multiple thereof; (8) the last date on which holders' rights to have
Notes
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<PAGE> 50
repurchased may be exercised; and (9) any other procedures holders must follow
in order to have their Notes repurchased.
At least one Business Day prior to the Designated Event Payment Date, the
Company shall irrevocably deposit with the Trustee or Paying Agent an amount
equal to the principal amount of Notes to be purchased. On the Designated Event
Payment Date, the Company will, to the extent lawful, (1) accept for purchase
Notes or portions thereof tendered pursuant to the Designated Event Repurchase,
(2) deposit with the Trustee the Notes so accepted and (3) deliver or cause to
be delivered to the Trustee an Officers' Certificate stating the Notes or
portions thereof tendered to the Trustee. The Trustee shall promptly mail to
each holder of Notes so accepted payment in an amount equal to the purchase
price for such Notes, and the Trustee shall promptly authenticate and mail to
each holder a new Note equal in principal amount to any unpurchased portion of
the Notes surrendered, if any; provided, that each such new Note shall be in a
principal amount of $1,000 or an integral multiple thereof. The Company will
publicly announce the results of the Designated Event Repurchase on or as soon
as practicable after the Designated Event Payment Date. There can be no
assurance that the Company will have the financial resources necessary to
repurchase the Notes in such circumstances.
The foregoing provisions would not necessarily afford holders of the Notes
protection in the event of a takeover, recapitalization, restructuring or other
transaction involving the Company that may adversely affect holders.
The right to require the Company to repurchase Notes as a result of a
Designated Event could have the effect of delaying, deferring or preventing a
Designated Event or other attempts to acquire control of the Company unless
arrangements have been made to enable the Company to repurchase all the Notes at
the Designated Event Payment Date. Consequently, this right may render more
difficult or discourage a merger, consolidation or tender offer (even if such
transaction is supported by the Company's Board of Directors or is favorable to
the stockholders), the assumption of control by a holder of a large block of the
Company's shares and the removal of incumbent management.
Any future credit agreements or other agreements relating to indebtedness
(including Senior Debt) to which the Company becomes a party may contain
restrictions on the repurchase of Notes. In the event a Designated Event occurs
at a time when the Company is prohibited from repurchasing Notes, the Company
could seek the consent of its lenders to the repurchase of Notes or could
attempt to refinance the borrowings that contain such prohibition. If the
Company does not obtain such a consent or repay such borrowings, the Company
would remain prohibited from repurchasing Notes. In such case, the Company's
failure to repurchase tendered Notes would constitute an Event of Default under
the Indenture, which may, in turn, constitute a further default under certain of
the Company's existing debt instruments and may constitute a default under the
terms of other indebtedness that the Company may enter into from time to time.
As the payment of the Designated Event Payment is subordinated to the prior
payment of Senior Debt as described under "-- Subordination of Notes" below, in
such circumstances, the subordination provisions in the Indenture would likely
prohibit payments to the holders of Notes.
A "Designated Event" will be deemed to have occurred upon a Change of
Control or a Termination of Trading.
A "Change of Control" will be deemed to have occurred when: (i) any
"person" or "group" (as such terms are used in Section 13(d) and 14(d) of the
Exchange Act) is or becomes the "beneficial owner" (as defined in Rules 13d-3
and 13d-5 under the Exchange Act) of shares representing more than 50% of the
combined voting power of the then outstanding securities entitled to vote
generally in elections of directors of the Company ("Voting Stock"), (ii) the
Company consolidates with or merges into any other corporation, or any other
corporation merges into the Company, and, in the case of any such transaction,
the outstanding Common Stock of the Company is reclassified into or exchanged
for any other property or security, unless the
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<PAGE> 51
stockholders of the Company immediately before such transaction own, directly or
indirectly immediately following such transaction, at least a majority of the
combined voting power of the outstanding voting securities of the corporation
resulting from such transaction in substantially the same proportion as their
ownership of the Voting Stock immediately before such transaction, (iii) the
Company conveys, transfers or leases more than 66 2/3% of its assets (other than
to a wholly-owned subsidiary of the Company) or (iv) any time the Continuing
Directors do not constitute a majority of the Board of Directors of the Company
(or, if applicable, a successor corporation to the Company); provided, that a
Change of Control shall not be deemed to have occurred if either (i) the last
sale price of the Common Stock for any five trading days during the ten trading
days immediately preceding the Change of Control is at least equal to 110% of
the Conversion Price in effect on the date of such Change of Control or (ii) at
least 90% of the consideration (excluding cash payments for fractional shares)
in the transaction or transactions constituting the Change of Control consists
of shares of common stock that are, or upon issuance will be, traded on a United
States national securities exchange or approved for trading on an established
automated over-the-counter trading market in the United States.
"Continuing Directors" means, as of any date of determination, any member
of the Board of Directors of the Company who (i) was a member of such Board of
Directors on the date of the Indenture or (ii) was nominated for election or
elected to such Board of Directors with the approval of a majority of the
Continuing Directors who were members of such Board at the time of such
nomination or election.
A "Termination of Trading" will be deemed to have occurred if the Common
Stock (or other common stock into which the Notes are then convertible) is not
listed for trading on a United States national securities exchange or an
established automated over-the-counter trading market in the United States.
The Company will comply with the provisions of Rule 13e-4 and any other
tender offer rules under the Exchange Act which may then be applicable and will
file a Schedule 13E-4 or any other schedule required thereunder in connection
with any offer by the Company to repurchase Notes at the option of holders upon
a Designated Event.
The Company could, in the future, enter into certain transactions,
including certain recapitalization of the Company, that would not constitute a
Change of Control for purposes of the Designated Event repurchase feature of the
Notes, but that would increase the amount of Senior Debt (or other indebtedness)
outstanding at such time. There are no restrictions in the Indenture on the
creation of additional Senior Debt (or any other indebtedness), and under
certain circumstances the incurrence of significant amounts of additional
indebtedness could have an adverse effect on the Company's ability to service
its indebtedness, including the Notes. If a Designated Event were to occur,
there can be no assurance that the Company would have sufficient funds to pay
the Designated Event Payment for all Notes tendered by the holders thereof. A
default by the Company on its obligations to pay the Designated Event Payment
could result in acceleration of the payment of other indebtedness of the Company
at the time outstanding pursuant to cross-default provisions.
CONVERSION
The Notes, or any portion thereof which is an integral multiple of $1,000,
are convertible at any time after 90 days following the date of original
issuance thereof and prior to the close of business on November 15, 2006,
subject to prior redemption at the option of the Company or repurchase at the
option of the holder, into shares of the Company's Common Stock, at the
conversion price set forth on the cover of this Prospectus, subject to
adjustment as set forth below (the "Conversion Price"). The Company will not be
required to issue fractional shares of Common Stock but will pay a cash
adjustment in lieu thereof. In the case of any Note or portion thereof called
for redemption, conversion rights expire at the close of business on the
business day immediately preceding redemption. In the event any holder exercises
its repurchase right upon a Designated Event, such
51
<PAGE> 52
holder's conversion right will terminate. See "-- Repurchase at the Option of
Holders." Except as described below, no adjustment will be made on conversion of
any Notes for interest accrued thereon or for dividends on any Common Stock
issued.
Accrued interest will not be paid on the Notes that are converted. If any
Note is converted between a record date for the payment of interest and the next
succeeding interest payment date, the interest payable on such interest payment
date shall be paid to the holder of such Note on such record date; however, such
Note upon surrender must be accompanied by funds equal to the interest payable
on such interest payment date on the principal amount so converted (unless such
Note shall have been called for redemption, in which case no such payment shall
be required).
The Conversion Price is subject to adjustment in certain events, including
(i) the subdivision, combination or reclassification of the outstanding Common
Stock of the Company; (ii) the issuance by the Company of Common Stock as a
dividend or distribution on the Common Stock; (iii) the issuance of rights and
warrants (expiring within 45 days after the record date for the determination of
stockholders entitled to receive such rights and warrants) to all holders of
Common Stock entitling them to purchase shares of Common Stock or securities
convertible into or exchangeable for Common Stock at a price per share (or
having a conversion or exercise price per share) less than the then current
market price (as defined in the Indenture) of the Common Stock (iv) the
distribution of shares of capital stock of the Company (other than Common
Stock), evidences of indebtedness or other assets (excluding dividends in cash,
except as described in clause (v) below) to all holders of Common Stock; (v) the
distribution, by dividend or otherwise, of cash to all holders of Common Stock
in an aggregate amount that, together with the aggregate of any other
distributions of cash that did not trigger a Conversion Price adjustment to all
holders of its Common Stock within the 12 months preceding the date fixed for
determining the stockholders entitled to such distribution and all Excess
Payments in respect of each tender offer or other negotiated transaction by the
Company or any of its Subsidiaries for Common Stock concluded within the
preceding 12 months not triggering a Conversion Price adjustment, exceeds 5% of
the product of the current market price per share (determined as set forth
below) on the date fixed for the determination of stockholders entitled to
receive such distribution times the number of shares of Common Stock outstanding
on such date; (vi) payment of an Excess Payment in respect of a tender offer or
other negotiated transaction by the Company or any of its Subsidiaries for
Common Stock, if the aggregate amount of such Excess Payment, together with the
aggregate amount of cash distributions made within the preceding 12 months not
triggering a Conversion Price adjustment and all Excess Payments in respect of
each tender offer or other negotiated transaction by the Company or any of its
Subsidiaries for Common Stock concluded within the preceding 12 months not
triggering a Conversion Price adjustment, exceeds 5% of the product of the
current market price per share (determined as set forth below) on the expiration
of such tender offer times the number of shares of Common Stock outstanding on
such date; (vii) the distribution to all holders of Common Stock of rights or
warrants to subscribe for securities (other than those securities referred to in
clause (iii) above); and (viii) the issuance of Common Stock or securities
convertible into, or exchangeable for, Common Stock at a price per share (or
having a conversion or exchange price per share) that is less than the current
market price of the Common Stock (but excluding, among other things, issuances:
(a) pursuant to any bona fide plan for the benefit of employees, directors or
consultants of the Company now or hereafter in effect; (b) to acquire all or any
portion of a business in an arm's-length transaction between the Company and an
unaffiliated third party including, if applicable, issuances upon exercise of
options or warrants assumed in connection with such an acquisition; (c) in a
bona fide public offering pursuant to a firm commitment underwriting or sales at
the market pursuant to a continuous offering stock program; (d) pursuant to the
exercise of warrants, rights (including, without limitation, earnout rights) or
options, or upon the conversion of convertible securities, which are issued and
outstanding on the date hereof, or which may be issued in the future for fair
value and with an exercise price or conversion price at least equal to the
current market price of the Common Stock at the time of such issuance). In the
event of a distribution to substantially all holders of Common Stock of rights
or warrants to subscribe for securities (other
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<PAGE> 53
than those securities referred to in clause (iii) above), the Company may,
instead of making any adjustment in the Conversion Price, make proper provision
so that each holder of a Convertible Note who converts such Convertible Note
after the record date for such distribution and prior to the expiration or
redemption of such rights shall be entitled to receive upon such conversion, in
addition to shares of Common Stock, an appropriate number of such rights. The
Company is not required to make any adjustment in the Conversion Price of less
than 1%, but instead such adjustment will be carried forward and taken into
account in the computation of any subsequent adjustment.
In the Indenture, the "current market price" per share of Common Stock on
any date shall be deemed to be the average of the Daily Market Prices for the
shorter of (i) 30 consecutive business days ending on the last full trading day
on the exchange or market referred to in determining such Daily Market Prices
prior to the time of determination (as defined in the Indenture) or (ii) the
period commencing on the date next succeeding the first public announcement of
the issuance of such rights or warrants or such distribution through such last
full trading day prior to the time of determination.
"Excess Payment" means the excess of (A) the aggregate of the cash and fair
market value of other consideration paid by the Company or any of its
Subsidiaries with respect to the shares acquired in the tender offer or other
negotiated transaction over (B) the market value of such acquired shares after
giving effect to the completion of the tender offer or other negotiated
transaction.
In case of any merger or consolidation of the Company or the sale or
conveyance by the Company of all or substantially all the assets of the Company,
the holder of each outstanding Note shall have the right to convert such Note
into the kind and amount of shares of stock and other securities and property
(including cash) received in such transaction by a holder of the number of
shares of Common Stock into which such Note was convertible immediately prior to
the effective date of such transaction. The meaning of the phrase "sale or
conveyance by the Company of all or substantially all of the assets of the
Company" will be determined under New York law, which governs the Indenture.
Application of the phrase to a particular sale of assets will depend on the
interpretation given to the phrase by courts construing New York law at the
time, and by the specific facts and circumstances of such sale. Although there
is a developing body of case law interpreting the phrase "substantially all,"
there is no precise established definition of the phrase under applicable law.
Accordingly, the applicability of the foregoing provision as a result of a
lease, transfer or conveyance of less than all of the assets of the Company to
another person or group may be uncertain.
The Company may from time to time reduce the Conversion Price by any amount
for any period of at least 20 days, in which case the Company shall give at
least 15 days' notice of such reduction, if the Board of Directors of the
Company has made a determination that such reduction would be in the best
interests of the Company, which determination shall be conclusive. In addition,
and without limiting the foregoing, the Board of Directors may also make such
reductions in the Conversion Price as it deems advisable to avoid or diminish
any income tax to holders of Common Stock resulting from any dividend or
distribution of stock (or rights to acquire stock) or from any event treated as
such for income tax purposes. See "Certain United States Tax Considerations."
Certain adjustments (or the failure to make certain adjustments in certain
cases) in the Conversion Price in accordance with the foregoing provisions
(other than to take account of a dividend of the Company's own stock or a stock
split) could be taxable pursuant to Section 305 of the Internal Revenue Code of
1986, as amended, as a constructive distribution to holders of the Notes at the
time of such adjustments in the Conversion Price.
SUBORDINATION OF NOTES
The payment of the principal of, interest on or any other amounts due on
the Notes will be subordinate in right of payment to all existing and future
Senior Debt. The Indenture does not restrict
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<PAGE> 54
the amount of Senior Debt or other indebtedness that may be incurred in the
future by the Company or any subsidiary of the Company. In addition, the Notes
will be effectively subordinated to claims of holders of any preferred stock and
claims of creditors (other than the Company) of the Company's subsidiaries,
including trade creditors, secured creditors, taxing authorities, creditors
holding guarantees, and tort claimants. In the event of a liquidation,
reorganization, or similar proceeding relating to a subsidiary, these persons
generally would have priority as to the assets of such subsidiary over the
claims and equity interest of the Company and, thereby indirectly, holders of
the Company's indebtedness, including the Notes. As of September 30, 1996, there
were no material outstanding liabilities of subsidiaries of the Company, but
such liabilities may be incurred in the future.
No payment on account of principal of, redemption of, interest on or any
other amounts due on the Notes, including, without limitation, any payments with
respect to a Designated Event, and no redemption, purchase or other acquisition
of the Notes may be made unless (i) full payment of amounts then due on all
Senior Debt have been made or duly provided for pursuant to the terms of the
instrument governing such Senior Debt, and (ii) at the time for, or immediately
after giving effect to, any such payment, redemption, purchase or other
acquisition, there shall not exist under any Senior Debt or any agreement
pursuant to which any Senior Debt has been issued, any default which shall not
have been cured or waived and which shall have resulted in the full amount of
such Senior Debt being declared due and payable. In addition, the Indenture will
provide that if any of the holders of any issue of Designated Senior Debt
notifies (the "Payment Blockage Notice") the Company and the Trustee that a
default has occurred giving the holders of such Designated Senior Debt the right
to accelerate the maturity thereof, no payment on account of principal,
redemption, interest or any other amounts due on the Notes and no purchase,
redemption or other acquisition of the Notes will be made for the period (the
"Payment Blockage Period") commencing on the date the Payment Blockage Notice is
received and ending on the earlier of (A) the date on which such event of
default shall have been cured or waived or (B) 180 days after the date the
Payment Blockage Notice is received. Notwithstanding the foregoing (but subject
to the provisions contained in the first sentence of this paragraph), unless the
holders of such Designated Senior Debt or the representative of such holders
shall have accelerated the maturity of such Designated Senior Debt, the Company
may resume payments on the Notes after the end of such Payment Blockage Period.
Not more than one Payment Blockage Notice will be treated as such in any
consecutive 365-day period, irrespective of the number of defaults with respect
to Senior Debt during such period.
Upon any distribution of its assets in connection with any dissolution,
winding-up, liquidation or reorganization of the Company or acceleration of the
principal amount due on the Notes because of an Event of Default, all Senior
Debt must be paid in full before the holders of the Notes are entitled to any
payments whatsoever.
If payment of the Notes is accelerated because of an Event of Default, the
Company shall promptly notify the holders of Senior Debt or the trustee(s) for
such Senior Debt of the acceleration. The Company may not pay the Notes until
five days after such holders or trustee(s) of Senior Debt receive notice of such
acceleration and, thereafter, may pay the Notes only if the subordination
provisions of the Indenture otherwise permit payment at that time.
As a result of these subordination provisions, in the event of the
Company's insolvency, holders of the Notes may recover ratably less than general
creditors of the Company.
BOOK-ENTRY; DELIVERY AND FORM
The certificates representing the Notes will be issued in fully registered
form, without coupons. The Notes will be deposited with, or on behalf of, The
Depository Trust Company, New York, New York ("DTC"), and registered in the name
of Cede & Co., as DTC's nominee in the form of a global Note certificate (the
"Global Certificate") or will remain in the custody of the Trustee pursuant to a
FAST Balance Certificate Agreement between DTC and the Trustee.
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<PAGE> 55
GLOBAL CERTIFICATES
Upon the issuance of the Global Certificate, DTC or its custodian will
credit, on its internal system, the respective principal amount of Notes of the
individual beneficial interests represented by such Global Certificate to the
respective accounts of persons who have accounts with such depositary. Such
accounts initially will be designated by or on behalf of the Underwriters.
Ownership of beneficial interests in the Global Certificate will be limited to
persons who have accounts with DTC ("participants") or persons who hold
interests through participants. Ownership of beneficial interests in a Global
Certificate will be shown on, and the transfer of that ownership will be
effected only through, records maintained by DTC or its nominee (with respect to
interests of participants) and the records of participants (with respect to
interests of persons other than participants).
Conveyance of notices and other communications by DTC to Direct
Participants (as defined herein), by Direct Participants to Indirect
Participants (as defined herein), and by Direct Participants and Indirect
Participants to beneficial owners, will be governed by arrangements among them,
subject to any statutory or regulatory requirements as may be in effect from
time to time.
Purchases of Notes under the DTC system must be made by or through Direct
Participants, which will receive a credit for the Notes on DTC's records. The
ownership interest of each actual purchaser of each Note ("Beneficial Owner")
will in turn be recorded on the Direct and Indirect Participants' records.
Beneficial Owners will not receive written confirmation from DTC of their
purchase, but Beneficial Owners are expected to receive written confirmations
providing details of the transaction, as well as periodic statements of their
holdings, from the Direct and Indirect Participant through which the Beneficial
Owners entered the transaction. Transfers of ownership interests in the Notes
are to be accomplished by entries made on the books of participants acting on
behalf of Beneficial Owners. Beneficial Owners will not receive certificates
representing their ownership interests in the Notes, except in the event that
use of the book entry system for the Notes is discontinued.
So long as DTC, or its nominee, is the registered owner or holder of the
Global Certificate, DTC or such nominee, as the case may be, will be considered
the sole owner or holder of the Notes represented by such Global Certificate for
all purposes under the Indenture and the Notes. No beneficial owner of an
interest in the Global Certificate will be able to transfer the interest except
in accordance with DTC's applicable procedures, in addition to those provided
for under the Indenture.
Payments of the principal of, and interest on, the Global Certificate will
be made to DTC or its nominee, as the case may be, as the registered owners
thereof. Neither the Company, the Trustee nor any Paying Agent will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of beneficial ownership interests in the Global
Certificate of for maintaining, supervising or reviewing any records relating to
such beneficial ownership interests, subject to any statutory or regulatory
requirements as may be in effect from time to time.
The Company expects that DTC or its nominee, upon receipt of any payment of
principal or interest in respect of the Global Certificate, will credit
participants' accounts with payments in amounts proportionate to their
respective beneficial interests in the principal amount of such Global
Certificate as shown on the records of DTC or its nominee. The Company also
expects that payments by participants to owners of beneficial interests in such
Global Certificate held through such participants will be governed by standing
instructions and customary practices, as is now the case with securities held
for the accounts of customers registered in the names of nominees for such
customers. Such payments will be the responsibility of such participants.
Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules. If a holder requires physical delivery of a
certificated note for any reason, including to sell Notes to persons in
jurisdictions which require such delivery of such Notes or to pledge such Notes,
such holder must transfer its interest in the Global Certificate in accordance
with the normal procedures of DTC and the procedures set forth in the Indenture.
Once an interest in the Global
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Certificate is delivered as a certificated Note, such certificated Note may be
exchanged for an interest in the Global Certificate.
The Company expects that DTC will take any action permitted to be taken by
a holder of Notes (including the presentation of Notes for exchange as described
below) only at the direction of one or more participants to whose account the
DTC interests in a Global Certificate is credited and only in respect of such
portion of the aggregate principal amount of the Notes as to which such
participant or participants has or have given direction. However, if there is an
Event of Default (as defined) under the Notes, DTC may exchange the Global
Certificate for certificated Notes, which it will distribute to its
participants.
DTC has advised the Company as follows: DTC is a limited-purpose trust
company organized under the New York Banking Law, a "banking organization"
within the meaning of the New York Banking Law, a member of the Federal Reserve
System, a "clearing corporation" within the meaning of the New York Uniform
Commercial Code, and a "clearing agency" registered pursuant to the provisions
of Section 17A of the Securities Exchange Act of 1934, as amended. DTC holds
securities that its participants deposit with DTC. DTC also facilitates the
settlement among participants of securities transactions, such as transfers and
pledges, in deposited securities through electronic computerized book-entry
changes in accounts of its participants, thereby eliminating the need for
physical movement of securities certificates. Direct Participants include
securities brokers and dealers, banks, trust companies, clearing corporations,
and certain other organizations. DTC is owned by a number of its Direct
Participants and by the New York Stock Exchange, Inc., the American Stock
Exchange and the National Association of Securities Dealers, Inc. Access to the
DTC system is also available to others such as banks, securities brokers and
dealers and trust companies that clear through or maintain a custodial
relationship with a Direct Participant, either directly or indirectly ("Indirect
Participants").
Although the Company expects that DTC will agree to the foregoing
procedures in order to facilitate transfers of interests in the Global
Certificate among participants of DTC, DTC is under no obligation to perform or
continue to perform such procedures, and such procedures may be discontinued at
any time. Neither the Company nor the Trustee will have any responsibility for
the performance by DTC or its Direct or Indirect Participants of their
respective obligations under the rules and procedures governing their
operations.
If DTC is at any time unwilling or unable to continue as a depositary for a
Global Certificate and a successor depositary is not appointed by the Company
within 90 days, the Company will issue certificated Notes in exchange for the
Global Certificate. The Company also may decide to discontinue use of the system
of book-entry transfers through DTC (or a successor securities depository). In
that event, the Company will issue certificated Notes in exchange for the Global
Certificate.
The information in this section concerning DTC and DTC's book-entry system
has been obtained from sources that the Company believes to be reliable, but the
Company takes no responsibility for the accuracy thereof.
TRANSFER AND EXCHANGE
A holder may transfer or exchange Notes in accordance with the Indenture.
The Registrar and the Trustee may require a holder, among other things, to
furnish appropriate endorsements and transfer documents and the Company may
require a holder to pay any taxes and fees required by law or permitted by the
Indenture. The Company is not required to exchange or register the transfer of
any Note selected for redemption. Also, the Company is not required to exchange
or register the transfer of any Note for a period of 15 days before a selection
of Notes to be redeemed.
The registered holder of a Note will be treated as the owner of it for all
purposes.
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CONSOLIDATION, MERGER AND SALE OF ASSETS
The Indenture provides that the Company will not consolidate with or merge
into any other Person or sell, convey, transfer or lease all or substantially
all of its properties and assets to any Person, or permit any Person to
consolidate with or merge into the Company or sell, convey, transfer or lease
all or substantially all of its properties and assets to the Company, unless (a)
the Company shall be the continuing Person or the Person formed by such
consolidation or into which the Company is merged or the Person or corporation
that acquires all or substantially all of its properties and assets is a
corporation, partnership or trust organized and validly existing under the laws
of the United States or any stated thereof or the District of Columbia and
expressly assumes payment of the principal of and premium, if any, and interest
on the Notes and performance and observance of each obligation of the Company
under the Indenture and the Notes, (b) immediately after giving effect to such
transaction and treating any indebtedness which becomes an obligation of the
Company as a result of such transaction as having been incurred by the Company
at the time of such transaction, no Default or Event of Default exists, (c) such
sale, assignment, transfer, lease, conveyance or other disposition of all or
substantially all of the Company's properties or assets shall be as an entirety
or virtually as an entirety to one Person and such Person shall have assumed all
the Obligations of the Company under the Notes and the Indenture, pursuant to a
supplemental indenture in a form reasonably satisfactory to the Trustee, and (d)
the Company has delivered to the Trustee an Officer's Certificate and an Opinion
of Counsel, each stating that such consolidation, merger, conveyance, transfer
or lease complies with the provisions of the Indenture.
EVENTS OF DEFAULT
The following are Events of Default under the Indenture with respect to the
Notes (even if the event is the failure to do an act which is prohibited by the
subordination provisions of the Indenture): (a) failure to pay interest upon any
Note when it becomes due and payable, and continuance of such default for a
period of 30 days; (b) failure to pay the principal of (or premium, if any, on)
any Note at its maturity; (c) failure to pay the Redemption Price or the
Designated Event Payment when and as due; (d) failure to deposit the Redemption
Price or Designated Event Payment when and as due; (e) failure to perform, or
breach of, any covenant or agreement of the Company in the Indenture continued
for 60 days after written notice as provided in the Indenture; (f) default under
any mortgage, indenture or instrument under which there may be issued or by
which there may be secured or evidenced any Indebtedness for money borrowed by
the Company or any of its Subsidiaries (or the payment of which is guaranteed by
the Company or any of its Subsidiaries), whether such Indebtedness or guarantee
now exists or is created after the date on which the Notes are first
authenticated and issued, which default (a) is caused by a failure to pay
principal or interest due on such Indebtedness within the grace period for
payment provided in such Indebtedness (which failure continues beyond any
applicable grace period) (a "Payment Default") or (b) results in the
acceleration of such Indebtedness prior to its express maturity and, in each
case, the principal amount of any such Indebtedness, together with the principal
amount of any other such Indebtedness under which there has been a Payment
Default or the maturity of which has been so accelerated, aggregates $25 million
or more; (g) one or more judgments or decrees shall be entered against the
Company or any Material Subsidiary involving a liability of more than $25
million in the aggregate and such judgments or decrees shall not have been
vacated, discharged, satisfied or stayed pending appeal within 60 days from the
date of entry thereof; and (h) certain events of bankruptcy, insolvency or
reorganization of the Company or any Material Subsidiary.
If an Event of Default with respect to the Notes shall occur and be
continuing, the Trustee or the holders of not less than 25% in aggregate
principal amount of the Notes then outstanding may declare the principal of all
Notes to be due and payable. The Company is required to furnish to the Trustee
quarterly statements as to any default in the performance by the Company of its
obligations under the Indenture. Under certain circumstances, any declaration of
acceleration with respect to the Notes may be rescinded and past defaults may be
waived by the holders of a majority of the
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aggregate principal amount of the outstanding Notes. The Indenture provides that
the Trustee shall give notice to the holders of the Notes of any default known
to it as provided in the Trust Indenture Act of 1939.
No holder of any Note will have any right individually to pursue any remedy
under the Indenture unless (i) the holder previously has given to the Trustee
written notice of a continuing Event of Default, (ii) holders of not less than
25% of the aggregate principal amount of the outstanding Notes have made written
request to the Trustee to institute a proceeding, (iii) such holder has offered
reasonable indemnity to the Trustee, (iv) the Trustee has not received from the
holders of a majority in aggregate principal amount of the outstanding Notes a
direction inconsistent with the request and (v) the Trustee has failed to
institute such proceeding within 60 days. However, these limitations do not
apply to a suit instituted by a holder of a Note for the enforcement of payment
of the principal of an premium, if any, or interest on such Note on or after the
respective due dates expressed in such Note or of the right to convert the Note
in accordance with the Indenture.
MODIFICATIONS, AMENDMENT AND WAIVERS
Modifications and amendment of the Indenture may be made by the Company and
the Trustee with the consent of the holders of a majority in aggregate principal
amount of the outstanding Notes; provided, however, that no such modification or
amendment may, without the consent of the holder of each outstanding Note, (a)
change the stated maturity of the principal of, or any installment of interest
on such Note, (b) reduce the principal amount of, or premium payable upon
redemption, or interest on such Note, (c) modify the conversion or subordination
provisions of the Indenture (except to reduce the Conversion Price as permitted)
in a manner that adversely affects the interests of the holders of the Notes,
(d) change the place or currency of payment of, or premium, if any, or interest
to convert such Note, (e) adversely affect the right to require the Company to
repurchase Notes upon a Designated Event, (f) impair the right to institute suit
for the enforcement of any such payment on or with respect to such Note, or (g)
reduce the percentage in principal amount of outstanding Notes, the consent of
whose holders is required for modification or amendment of the Indenture or for
waiver of compliance with certain provisions of the Indenture or for waiver of
certain defaults.
Notwithstanding the foregoing, without the consent of any holder of Notes,
the Company and the Trustee may amend or supplement the Indenture or the Notes
to cure any ambiguity, defect or inconsistency, to provide for uncertificated
Notes in addition to or in place of certificated Notes, to provide for the
assumption of the Company's obligations to holders of the Notes in the case of a
merger or consolidation, to make any change that would provide any additional
rights or benefits to the holders of the Notes or that does not adversely affect
the legal rights under the Indenture of any such holder, or to comply with
requirements of the Commission in order to qualify, or maintain the
qualification of, the Indenture under the Trust Indenture Act.
The holders of a majority in aggregate principal amount of the outstanding
Notes may, on behalf of all holders of Notes, waive compliance by the Company
with certain restrictive provisions of the Indenture. The holders of a majority
in aggregate principal amount of the outstanding Notes may, on behalf of all
holders of Notes, waive any past default under the Indenture with respect to the
Notes, except (a) a default in the payment of principal of, or premium, if any,
or interest on, the Notes, (b) failure to convert the Notes, or (c) in respect
of a provision which under the Indenture cannot be modified or amended without
consent of the holder of each outstanding Note.
PAYMENTS FOR CONSENT
Neither the Company nor any of its Subsidiaries shall, directly or
indirectly, pay or cause to be paid any consideration, whether by way of
interest, fee or otherwise, to any holder of any Notes for or as an inducement
to any consent, waiver or amendment of any of the terms or provisions of the
Indenture or the Notes unless such consideration is offered to be paid or agreed
to be paid to all
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holders of the Notes that consent, waive or agree to amend in the time frame set
forth in the solicitation documents relating to such consent, waiver or
agreement.
CERTAIN DEFINITIONS
Set forth below are certain defined terms used in the Indenture. Reference
is made to the Indenture for a full disclosure of all such terms, as well as any
other capitalized terms used herein for which no definition is provided.
"Capital Stock" means any and all shares, interests, participations, rights
or other equivalents (however designated) of equity interests in any entity,
including, without limitation, corporate stock and partnership interests.
"Designated Senior Debt" means any Senior Debt which, at the date of
determination, has an aggregate principal amount outstanding of, or commitments
to lend up to, at least $25 million and is specifically designated by the
Company in the instrument evidencing or governing such Senior Debt as
"Designated Senior Debt" for purposes of the Indenture.
"GAAP" means generally accepted accounting principles set forth in the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants and statements and pronouncements of
the Financial Accounting Standards Board or in such other statements by such
other entity as may be approved by a significant segment of the accounting
profession of the United States, which are in effect as of the date of
preparation of a financial statement or the date that a particular action is
taken or event occurs, as applicable.
"Indebtedness" means, with respect to any person, all obligations, whether
or not contingent, of such person (i) (a) for borrowed money (including, but not
limited to, any indebtedness secured by a security interest, mortgage or other
lien on the assets of such person which is (1) given to secure all or part of
the purchase price of property subject thereto, whether given to the vendor of
such property or to another, or (2) existing on property at the time of
acquisition thereof), (b) evidenced by a note, debenture, bond or other written
instrument, (c) under a lease required to be capitalized on the balance sheet of
the lessee under GAAP or under any lease or related document (including a
purchase agreement) which provides that such person is contractually obligated
to purchase or to cause a third party to purchase such leased property, (d) in
respect of letters of credit, bank guarantees or bankers' acceptances, (e) with
respect to Indebtedness secured by a mortgage, pledge, lien, encumbrance, charge
or adverse claim affecting title or resulting in an encumbrance to which the
property or assets of such person are subject, whether or not the obligation
secured thereby shall have been assumed or guaranteed by or shall otherwise be
such person's legal liability, (f) in respect of the balance of deferred and
unpaid purchase price of any property or assets, (g) under interest rate or
currency swap agreements, cap, floor and collar agreements, spot and forward
contracts and similar agreements and arrangements; (ii) with respect to any
obligation of others of the type described in the preceding clause (i) or under
clause (iii) below assumed by or guaranteed in any manner by such person or in
effect guaranteed by such person through an agreement to purchase (including,
without limitations "take or pay" and similar arrangements), contingent or
otherwise (and the obligations of such person under any such assumptions,
guarantees or other such arrangements); and (iii) any and all deferrals,
renewals, extensions, refinancings and refundings of, or amendments,
modifications or supplements to, any of the foregoing.
"Material Subsidiary" means any Subsidiary of the Company which is a
"significant subsidiary" as defined in Rule 1-02(w) of Regulation S-X under the
Securities Act and the Exchange Act (as such Regulation is in effect on the date
hereof).
"Senior Debt" means the principal of, interest on and other amounts due on
Indebtedness of the Company, whether outstanding on the date of the Indenture or
thereafter created, incurred, assumed or guaranteed by the Company, unless, in
the instrument creating or evidencing or
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pursuant to which Indebtedness is outstanding, it is expressly provided that
such Indebtedness is not senior in right of payment to the Notes. Senior Debt
includes, with respect to the obligations described above, interest accruing,
pursuant to the terms of such Senior Debt, on or after the filing of any
petition in bankruptcy or for reorganization relating to the Company, whether or
not post-filing interest is allowed in such proceeding, at the rate specified in
the instrument governing the relevant obligation. Notwithstanding anything to
the contrary in the foregoing, Senior Debt shall not include: (a) Indebtedness
of or amounts owed by the Company for compensation to employees, or for goods,
services or materials purchased in the ordinary course of business; (b)
Indebtedness of the Company to a Subsidiary of the Company; or (c) any liability
for Federal, state, local or other taxes owed or owing by the Company.
"Subsidiary" means any corporation, association or other business entity of
which more than 50% of the total voting power of shares of Capital Stock
entitled (without regard to the occurrence of any contingency) to vote in the
election of directors, managers or trustees thereof is at the time owned or
controlled, directly or indirectly, by any person or one or more of the other
Subsidiaries of that person or a combination thereof.
GOVERNING LAW
The Indenture and Notes will be governed and construed in accordance with
the laws of the State of New York without giving effect to such state's
conflicts of laws principles.
INFORMATION CONCERNING THE TRUSTEE
The Indenture contains certain limitations on the rights of the Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases or to realize on certain property received in respect of any such
claim as security or otherwise. Subject to the Trust Indenture Act of 1939, as
amended, the Company and its Subsidiaries may maintain deposit accounts and
conduct other banking transactions with the Trustee in the ordinary course of
business; however, if the Trustee acquires any conflicting interest, as
described in the Trust Indenture Act of 1939, as amended, upon the occurrence of
an Event of Default, it must eliminate such conflict or resign. An affiliate of
the Trustee is currently a lender to the Company under one of its existing
credit facilities, and such affiliate also maintains other customary banking
relationships with the Company for which such affiliate receives fees and
compensation.
DESCRIPTION OF CAPITAL STOCK
PREFERRED STOCK
The Company is authorized to issue 5,000,000 shares of preferred stock, par
value $.01, of which no shares have been issued. Under the Company's Articles of
Incorporation, the Company's Board of Directors is authorized, without
shareholder action, to issue preferred stock in one or more series and to fix
the number of shares and the rights, preferences and limitations of each series.
Among the specific matters that may be determined by the Board of Directors are
the dividend rate, the redemption price, if any, conversion rights, if any, the
amount payable in the event of any voluntary liquidation or dissolution of the
Company and voting rights, if any.
COMMON STOCK
The Company is authorized to issue 35,000,000 shares of Common Stock, par
value $.01, of which 15,091,384 were issued and outstanding at September 30,
1996. Holders of Common Stock are entitled to one vote for each share held.
Shareholders do not have preemptive rights or the right to cumulate votes for
the election of directors. Shares are not subject to redemption nor to any
liability for further calls. All shares of Common Stock issued and outstanding
are, and all the shares issued on conversion of the Notes offered by the Company
hereby when issued will be, validly issued, fully paid and non-assessable.
Holders of the Common Stock are entitled to receive
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dividends as they are declared by the board of directors out of funds legally
available therefor and are entitled to participate in the assets of the Company
available for distribution in the event of liquidation or dissolution. See
"Price Range of Common Stock and Dividend Policy." At September 30, 1996, there
were 2,171,977 shares, in the aggregate, reserved for issuance under the
Company's stock option or employee benefit plans, of which 1,232,646, in the
aggregate, were subject to outstanding options. In addition, 41,250 shares were
reserved for issuance upon the exercise of outstanding options granted outside
the Company's option plans. The Company does not currently have any plans to
issue additional shares of Common Stock other than pursuant to its 1990 Stock
Compensation Plan, its 1990 Nonqualified Plan, its Employee Stock Purchase Plan,
or options outstanding under predecessor plans.
ANTITAKEOVER MEASURES
The board of directors adopted amendments ("Antitakeover Measures") to the
Company's bylaws on August 14, 1995, designed to protect shareholders' rights in
the event of an acquisition of control by an outsider that does not have the
support of the board of directors. The primary amendment classifies the board of
directors. Other Antitakeover Measures adopted by the board of directors include
supermajority approval by the shareholders for (i) sale of substantially all of
the assets of the Company, merger or issuances of stock to certain shareholders
unless approved by Continuing Directors (as defined below); (ii) removal of
directors; and (iii) amendment or repeal of Antitakeover Measures. The
Antitakeover Measures could result in a denial or reduction to shareholders of
potential premiums over market often afforded by tender offers, the ability of
management or less than a majority of shareholders to thwart transactions which
may be desirable or beneficial to shareholders and increased difficulty to alter
management of the Company.
As amended, the bylaws provide that the board of directors shall consist of
seven (7) directors, and the number may be increased or decreased by a majority
of the Continuing Directors, provided that the number of directors shall never
be less than three (3) nor more than nine (9) members. Under the amended bylaws,
at the Annual Meeting held on May 14, 1996, two directors were elected to serve
terms expiring at the 1997 Annual Meeting, three directors were elected to serve
terms expiring at the 1998 Annual Meeting, and two directors were elected to
serve terms expiring at the 1999 Annual Meeting of shareholders. In all cases,
the directors will hold office until their respective successors have been duly
elected and have qualified. Vacancies occurring on the board of directors may be
filled by the board of directors for the unexpired term of the replacement
director's predecessor in office. At future annual meetings, each nominee for
director that is elected will be elected to serve a three year term.
The Antitakeover Measures also provide for the affirmative vote of at least
sixty-six and two thirds percent (66 2/3%) of the outstanding shares of the
capital stock of the Company entitled to vote generally in the election of
directors ("Supermajority Vote") on certain corporate actions. A Supermajority
Vote is required to sell, assign or dispose of all or substantially all of the
Company's assets or to merge with another corporation or entity if such
transaction is not approved by a majority of the directors then in office who
were directors for the two-year period ending on the date notice of the meeting
or written consent is first provided to shareholders (the "Continuing
Directors") or to enter into any transaction, including the issuance or transfer
of securities of the Company, to any holder of twenty percent (20%) of the
outstanding capital stock of the Company. A Supermajority Vote is also required
to remove one or more directors or to amend or repeal the provisions that
contain Antitakeover Measures in the bylaws adopted by the board of directors.
TRANSFER AGENT
American Stock Transfer & Trust Company, New York, New York is the transfer
agent and registrar for the Common Stock.
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CERTAIN UNITED STATES TAX CONSIDERATIONS
The following summary of the United States federal income and estate tax
consequences of investing in the Notes is necessarily general and does not cover
all tax issues. It does not take into account foreign, state or local tax
consequences or the particular circumstances of any investor. The summary is not
intended as a substitute for careful and independent review of the tax
consequences of an investment in the Notes by each investor and its professional
advisors. Before deciding to invest in the Notes, each prospective investor
should consult its own tax advisor concerning the foreign, federal, state, local
and other tax laws that may apply to its investment.
The following summary and opinions of counsel are based upon currently
existing United States federal income and estate tax statutes, regulations,
interpretative rulings and judicial decisions. Legislative, regulatory or
interpretative changes, future court decisions or specific tax treaty provisions
may significantly modify the statements made herein or the opinions expressed.
Any such changes may or may not be retroactively applied to transactions entered
into or completed prior to the change.
The opinions set forth below merely represent counsel's present judgment on
the specific issues addressed based on the assumptions, qualifications and
conditions described herein. The opinions have no binding effect or legal status
of any kind, and the United States Internal Revenue Service ("IRS") or a court
may take a position contrary to counsel's opinion.
As used herein, "United States Holder" means a holder of a Note or Common
Stock acquired upon conversion of a Note that is for United States federal
income tax purposes (i) an individual who is a citizen or resident of the United
States, its territories, possessions or other areas subject to its jurisdiction,
(ii) a corporation, partnership or other entity created or organized in or under
the laws of the United States or of any political subdivision thereof, or (iii)
any estate or trust the income of which is subject to United States federal
income taxation regardless of its source. (Generally, for tax years beginning
after December 31, 1996, a trust will be a United States Holder only if (i) a
court within the United States is able to exercise primary supervision over the
administration of the trust, and (ii) one or more United States fiduciaries have
the authority to control all substantial trust decisions.) "Non-United States
Holder" means a holder of a Note or Common Stock acquired upon conversion of a
Note who is not a United States Holder.
Subject to the foregoing, in the opinion of Jenkens & Gilchrist, A
Professional Corporation, tax counsel to the Company, the following discussion
accurately describes (i) the material United States federal income tax
consequences of the ownership and disposition of Notes and Common Stock acquired
upon conversion of Notes applicable to Non-United States Holders and United
States Holders who will acquire and own such Notes and/or Common Stock as
"capital assets" (generally, property held for investment) within the meaning of
Section 1221 of the Internal Revenue Code of 1986, as amended ("Code"), and (ii)
the United States estate tax consequences of the ownership of Notes and/or
Common Stock for individual Non-United States Holders.
UNITED STATES HOLDERS
Stated Interest
A United States Holder will be required to report as income for federal
income tax purposes interest earned on the Notes in accordance with the holder's
method of tax accounting. A United States Holder using the accrual method of
accounting for tax purposes is, as a general rule, required to include interest
in ordinary income as such interest accrues, while a cash basis United States
Holder must include interest in income when cash payments are received (or made
available for receipt) by such holder.
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Market Discount on Resale of Notes
The resale of Notes may be affected by the market discount provisions of
the Code. These rules generally provide that if a United States Holder purchased
such Notes (other than in an original issue) at a market discount equal to at
least 0.25% of its stated redemption price at maturity (generally its principal
amount) multiplied by the number of complete years from the date of acquisition
to maturity, and thereafter recognizes gain upon a disposition (including a
gift) of the Notes (or the Common Stock into which they were converted), the
lesser of (i) such gain (or appreciation, in the case of a gift), or (ii) the
portion of the market discount that accrued while the Notes were held by such
holder, will be treated as ordinary interest income at the time of the
disposition. For these purposes, (i) market discount means the excess, if any,
of the stated redemption price of the Notes at maturity over the basis of the
Notes in the hands of such holder immediately after its acquisition, and (ii)
market discount accrues ratably from the date of acquisition until the date of
maturity unless the holder makes an irrevocable election to accrue market
discount under a constant interest rate basis similar to the accrual of interest
with respect to original issue discount. The rules also provide that a United
States Holder who acquires Notes at a market discount may be required to defer
the deduction of all or a portion of any interest expense that may otherwise be
deductible on any indebtedness incurred or continued to purchase or carry such
Notes until the holder disposes of such Notes in a taxable transaction.
On or after November 15, 1999, the Company may redeem the Notes, in whole
or in part, prior to maturity. The Code includes a rule for the treatment of
market discount on debt instruments where the principal is paid in more than one
installment. This rule would apply to a United States Holder if such holder's
Notes were redeemed in part. In such an event, the United States Holder would be
required to include in gross income (as ordinary income) the lesser of (i) the
principal payment or (ii) the accrued market discount. The amount of accrued
market discount shall be reduced by such amount included in gross income.
A United States Holder of Notes acquired at a market discount may elect to
include market discount in income as the discount accrues, either on a ratable
basis or on a constant interest rate basis. The current inclusion election, once
made, applies to all market discount obligations acquired on or after the first
day of the first taxable year to which the election applies, and may not be
revoked without the consent of the IRS. If a United States Holder elects to
include market discount in income in accordance with the preceding sentence, the
foregoing rules with respect to (i) the recognition of market discount income on
sales and certain other dispositions of such Notes, (ii) the deferral of
interest deductions on indebtedness related to such Notes, and (iii) the
recognition of market discount income upon the partial redemption of such Notes,
would not apply.
Amortizable Bond Premium
The resale of any Notes may be affected by the bond premium rules of the
Code. Generally, if the tax basis of Notes immediately after their purchase
exceeds the amount payable at maturity of the Notes, such excess may constitute
amortizable bond premium that the United States Holder may elect to amortize
under the constant interest rate method over the period from such holder's
acquisition date to the Notes' maturity date. In the case of convertible debt,
such as the Notes, the amortizable bond premium does not include any premium
that is attributable to the conversion feature. In addition, in the case of
obligations, such as the Notes, which may be called prior to maturity, the
earlier call date is treated as the maturity date, and the amount of bond
premium is determined by treating the amount payable on such call date as the
amount payable at maturity, if such calculation produces a smaller annual
premium deduction than the method described above. If a United States Holder
elects to amortize bond premium, if any, on the Notes and is required under the
rule described in the preceding sentence to amortize and deduct bond premium by
reference to such a call date and the Notes are not redeemed on such date, the
remaining unamortized premium will be amortized to a succeeding call date or to
maturity in accordance with the foregoing rules.
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An election to amortize bond premium applies to all bonds acquired by the
United States Holder at a premium during the year of election and thereafter,
unless the IRS consents to a revocation of the election. Amortizable bond
premium on a Note is treated as an offset to interest income on the Note and not
as a separate deduction, unless otherwise provided in Treasury regulations.
Recently proposed Treasury regulations would continue to treat amortizable bond
premium only as an offset to interest income on the Note. The Notes' basis must
be reduced by any amortizable bond premium applied to reduce interest under this
rule. Amortizable bond premium on a Note held by a United States Holder who does
not elect to amortize bond premium will decrease the gain or increase the loss
otherwise recognized on disposition of a Note or Common Stock into which a Note
is converted.
Conversion of Notes into Common Stock
A United States Holder should not recognize gain or loss on the conversion
of the Notes solely into shares of Common Stock, except with respect to cash
received either in lieu of a fractional share or with respect to any accrued
interest payable on the Notes converted and not subject to a repayment
obligation to the Company (see "-- Description of Notes -- Conversion") and not
previously included in income. Any interest accrued on the Notes converted but
not payable or recoverable by the Company (see "-- Description of
Notes -- Conversion") should not be included in the income of the holder of such
Notes. The holding period of the shares of Common Stock received upon conversion
of the Notes will include the period during which the Notes were held (provided
the Notes were a capital asset in the hands of the holder prior to the
conversion). The holder's aggregate tax basis in the shares of Common Stock
received upon conversion of the Notes will be equal to the holder's aggregate
tax basis in the Notes exchanged therefor (less a portion thereof allocable to
any fractional share). A United States Holder will recognize taxable gain or
loss on cash received in lieu of a fractional share of Common Stock in an amount
equal to the difference between the amount of cash received and the holder's
basis in such fractional share. Such gain or loss should be a capital gain or
loss if the fractional share is a capital asset in the hands of the holder.
If Notes as to which there is accrued market discount are converted into
shares of Common Stock, such accrued market discount will carry over to such
shares of Common Stock (to the extent that such accrued market discount has not
previously been included in the holder's income) and any gain realized upon a
subsequent disposition of such shares of Common Stock, to the extent of such
accrued market discount, may be taxable as ordinary interest income. See
"-- United States Holders -- Market Discount on Resale of Notes."
Certain adjustments (or the failure to make certain adjustments in certain
cases) in the conversion price of the Notes made pursuant to the provisions of
the Indenture may be deemed taxable distributions to United States Holders
pursuant to Section 305 of the Code, whether or not such holders ever exercise
their conversion privilege. In addition, the failure to adjust fully the
conversion price of the Notes to reflect distributions of any stock dividends
with respect to the Common Stock (or rights to acquire Common Stock) may be
deemed taxable distributions to the holders of the Common Stock pursuant to
Section 305 of the Code. Such deemed distributions will be taxable as a
dividend, return of capital or capital gain in accordance with the rules
discussed under "-- United States Holders -- Distributions on Common Stock."
Distributions on Common Stock
Distributions paid on shares of Common Stock or deemed distributions under
Section 305 of the Code (see "-- United States Holders -- Conversion of Notes
Into Common Stock") will constitute dividends for United States federal income
tax purposes to the extent of the Company's current or accumulated earnings and
profits and will be includible in the income of a United States Holder as
ordinary income. Dividends paid or deemed paid to United States Holders that are
United States corporations may qualify for a dividends-received deduction.
64
<PAGE> 65
To the extent, if any, that such distributions exceed current and
accumulated earnings and profits of the Company, such excess will be treated
first as a non-taxable return of capital reducing the holder's basis in the
shares of Common Stock. Any remaining excess of such distribution will be
treated as capital gain.
Disposition of Notes or Common Stock
In general, United States Holders will recognize gain or loss upon the
sale, redemption, retirement or other disposition of the Notes or Common Stock
measured by the difference between the amount of cash and the fair market value
of property received (except to the extent attributable to the payment of
accrued interest which was not previously included in income) and the holder's
tax basis in the Notes or Common Stock. In this regard, a United States Holder's
tax basis in the Notes generally will equal the basis of the Notes upon issuance
to the holder (generally the amount paid for the Notes), increased by the amount
of market discount, if any, previously taken into income by the holder or
decreased by any bond premium theretofore amortized by the holder with respect
to the Notes. The gain on the sale or redemption of the Notes or Common Stock
should be long-term capital gain (except as discussed in the second paragraph of
"-- United States Holders -- Conversion of Notes into Common Stock" and in
"-- United States Holders -- Market Discount on Resale of Notes") provided the
Notes or Common Stock were capital assets in the hands of the holder and had
been held for more than the then applicable period (currently one year).
Backup Withholding
Under the Code, a United States Holder may be subject, under certain
circumstances, to "backup withholding" at a 31% rate with respect to payments in
respect of interest or dividends on the Notes or Common Stock or the gross
proceeds from the disposition thereof. This withholding generally applies only
if the holder (i) fails to furnish its social security or other taxpayer
identification number ("TIN"), (ii) furnishes an incorrect TIN, (iii) fails to
report properly interest or dividends, or (iv) fails, under certain
circumstances, to provide a certified statement, signed under penalty of
perjury, that the TIN provided is its correct number and that it is not subject
to backup withholding. Any amount withheld from a payment to a holder under the
backup withholding rules is allowable as a credit against such holder's federal
income tax liability, provided that the required information is furnished to the
IRS. United States Holder should consult their tax advisors as to their
qualifications for exemption from backup withholding and the procedure for
obtaining such an exemption. Prospective purchasers of Notes will be required to
complete a Form W-9 in order to provide the required information to the Company.
A United States Holder who does not provide the Company with the holder's
correct TIN may be subject to penalties imposed by the IRS.
The Company will report to each United States Holder, and the IRS the
amount of any "reportable payments" for each calendar year and the amount of tax
withheld, if any, with respect to payments on the Notes.
NON-UNITED STATES HOLDERS
Interest
Payments of principal and interest on the Notes to Non-United States
Holders will not be subject to the generally applicable 30% United States
federal withholding tax, provided that, in the case of interest, one of the
following is satisfied:
(1) i. the notes are in registered form within the meaning of Section
(h)(2)(B)(i) of the Code;
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<PAGE> 66
ii. the beneficial owner does not actually or constructively own 10% or
more of the total combined voting power of all classes of stock of the
Company entitled to vote as described in Section 871(h)(3);
iii. the beneficial owner is not a bank receiving interest described in
Section 881(c)(3)(A) of the Code;
iv. the beneficial owner is not a controlled foreign corporation within
the meaning of Section 957(a) of the Code that is related to the Company
through stock ownership; and
v. either:
(A) the beneficial owner of the Notes provides a properly completed
IRS Form W-8 (Certificate of Foreign Status) certifying to the person
otherwise required to withhold United States federal income tax from
such interest, under penalties of perjury, that it is not a United
States person and provides its name and address; or
(B) a securities clearing organization, bank or other financial
institution that holds customers' securities in the ordinary course of
its trade or business (a "financial institution"), and holds the Notes,
provides a properly completed IRS Form W-8 certifying to the person
otherwise required to withhold United States federal income tax, under
penalties of perjury, that a properly completed IRS Form W-8 has been
received from the beneficial owner by it or by a financial institution
between it and the beneficial owner and furnishes the payor with a copy
thereof;
(2) the beneficial owner is entitled to an exemption from or reduction of
the United States federal withholding tax under an income tax treaty to
which the United States is a party and the beneficial owner of the Notes
or such owner's agent provides a properly completed IRS Form 1001
(Ownership, Exemption or Reduced Rate Certificate) claiming such
exemption or reduction; or
(3) the beneficial owner conducts a trade or business in the United States
to which the interest is effectively connected and the beneficial owner
of the Notes or such owner's agent provides a properly completed IRS
Form 4224 (Exemption From Withholding of Tax on Income Effectively
Connected With the Conduct of a Trade or Business in the United States);
provided that in each such case, none of the persons receiving the relevant
certification or IRS Form has actual knowledge that the certification or any
statement on the IRS Form is false.
Assuming that payments of principal and interest on the Global Certificate
will be paid to DTC, Direct Participants, Indirect Participants, and Beneficial
Owners in accordance with the book entry rules and procedures set forth in
"-- Global Certificates," the Notes will be in registered form within the
meaning of Section 871(h)(2)(B)(i).
Interest on Notes that is effectively connected with the conduct of a trade
or business in the United States by a Non-United States Holder, although exempt
from withholding tax, may be subject to United States income tax as if such
interest was earned by a United States Holder.
A beneficial owner of the Notes, or, in certain cases, its agent, is
required to submit the appropriate IRS Forms described above under applicable
procedures to the person through which the owner directly holds the Notes. Each
other person through which Notes are held must submit, on behalf of the
beneficial owner, the IRS Form (or in certain cases a copy thereof) under
applicable procedures to the person through which it holds the Notes, until the
IRS Form is received by the United States person who would otherwise be required
to withhold United States federal income tax from interest on the Notes.
Applicable procedures include additional certification requirements if a
66
<PAGE> 67
beneficial owner provides an IRS Form W-8 to a financial institution that holds
the Notes on its behalf.
EACH NON-UNITED STATES HOLDER SHOULD BE AWARE THAT IF IT DOES NOT PROPERLY
PROVIDE THE REQUIRED IRS FORM, OR IF THE IRS FORM (OR, IF PERMISSIBLE, A COPY OF
SUCH FORM) IS NOT PROPERLY TRANSMITTED TO AND RECEIVED BY THE UNITED STATES
PERSON OTHERWISE REQUIRED TO WITHHOLD UNITED STATES FEDERAL INCOME TAX, INTEREST
ON THE NOTES MAY BE SUBJECT TO UNITED STATES WITHHOLDING TAX AT A 30% RATE. SUCH
TAX, HOWEVER, MAY IN CERTAIN CIRCUMSTANCES BE ALLOWED AS A REFUND OR AS A CREDIT
AGAINST SUCH HOLDER'S UNITED STATES FEDERAL INCOME TAX. THE FOREGOING DOES NOT
DEAL WITH ALL ASPECTS OF FEDERAL INCOME TAX WITHHOLDING THAT MAY BE RELEVANT TO
NON-UNITED STATES HOLDERS. INVESTORS ARE THEREFORE ADVISED TO CONSULT THEIR OWN
TAX ADVISORS FOR SPECIFIC ADVICE CONCERNING THE OWNERSHIP AND DISPOSITION OF
NOTES.
Conversion of Notes into Common Stock
No United States federal income tax will be imposed upon conversion of
Notes into shares of Common Stock by a Non-United States Holder except as
described below in "-- Non-United States Holders -- Disposition of Notes or
Common Stock" with respect to the receipt of cash in lieu of fractional shares
by certain holders upon conversion of Notes. As described in "-- United States
Holders -- Conversion of Notes Into Common Stock," certain adjustments to the
conversion price of the Notes may be a deemed distribution pursuant to Section
305 of the Code regardless of whether or not the holder exercises its conversion
privilege. (See "-- Non-United States Holders -- Distributions on Common
Stock.")
Distributions on Common Stock
The Company has never paid a cash dividend and does not expect to pay
dividends in the foreseeable future with respect to its Common Stock (see
"-- Price Range of Common Stock and Dividend Policy"). In the event that the
Company pays dividends with respect to its Common Stock in the future,
Non-United States Holders should consult with their tax advisors regarding the
tax consequences of receiving a dividend on Common Stock.
Certain adjustments to the conversion price of the Notes may be a deemed
distribution to Non-United States Holders (see "-- Non-United States
Holders -- Conversion of Notes Into Common Stock"). The maximum United States
withholding tax on such deemed distributions would be 30%. Non-United States
Holders should consult with their tax advisors regarding the tax consequences of
such a deemed distribution.
Disposition of Notes or Common Stock
Generally, a Non-United States Holder will not be subject to United States
federal income or withholding tax on any gain realized on the sale, exchange,
redemption or repurchase of Notes or upon the sale, exchange or, generally,
redemption of the Company's Common Stock (including any gain representing
accrued market discount or attributable to the receipt of cash in lieu of
fractional shares upon conversion of the Notes into shares of the Company's
Common Stock), unless:
(1) such gain is effectively connected with the conduct of a trade or
business within the United States by such holder;
(2) such holder is an individual who has been present in the United
States for at least 183 days during the taxable year of the disposition,
the Notes or Common Stock are capital assets and (i) such individual's "tax
home" for federal income tax purposes is in the United States or (ii) the
gain is attributable to an office or other fixed place of business
maintained in the United States by such individual; or
(3) the Company is or has been a "United States real property holding
corporation" for federal income tax purposes and the Non-United States
Holder owned, directly or pursuant to
67
<PAGE> 68
certain attribution rules at any time during the five-year period ending on
the date of disposition, more than 5% of the Company's Common Stock
(assuming the Common Stock continues to be regularly traded on an
established securities market within the meaning of Section 897(c)(3) of
the Code).
The Company believes that it is currently a United States real property holding
corporation.
Estate Tax
Notes owned by an individual who, at the time of death, is neither a
citizen nor domiciliary of the United States will not be subject to United
States federal estate tax as a result of such individual's death if the
individual does not actually or constructively own 10% or more of the total
combined voting power of all classes of stock of the Company entitled to vote
and the income on the Notes would not have been effectively connected with a
United States trade or business of the individual. Shares of Common Stock owned
(or treated as owned) by an individual who, at the time of death, is neither a
citizen nor a domiciliary of the United States, will be includible in his or her
gross estate for United States federal estate tax purposes and thus may be
subject to United States estate tax, unless an applicable estate tax treaty
provides otherwise.
Backup Withholding and Information Reporting
Under the Code, information reporting requirements will apply to payments
of principal and interest on the Notes, payments of dividends on Common Stock,
payments of the proceeds of the sale of a Note, and payments of the proceeds of
the sale of Common Stock to certain noncorporate holders, and a 31% backup
withholding tax may apply to such payments if the holder fails to provide an
accurate taxpayer identification number in the manner required or to report all
interest and dividends required to be shown on its federal tax returns.
Information reporting on IRS Form 1099 and backup withholding will not
apply to principal or interest payments made on the Notes by the Company or a
paying agent to a Non-United States Holder if, in the case of interest, the IRS
Form described above in clauses (2) or (3) under "-- Non-United States
Holders -- Interest" has been provided under applicable procedures, or, in the
case of interest or principal, the certification described above in clause
(1)(iv) under "-- Non-United States Holders -- Interest" and a certification
that the Non-United States Holder satisfies certain other conditions have been
supplied under applicable procedures, provided that the payor does not have
actual knowledge that the certifications are incorrect.
Payments of the proceeds from the sale of the Notes or Common Stock to or
through the United States office of a broker will be subject to information
reporting and backup withholding unless the Non-United States Holder certifies
that it is a Non-United States Holder under penalties of perjury or otherwise
establishes an exemption from information reporting and backup withholding.
Payments of the proceeds from the sale of the Notes or Common Stock made to or
through a foreign office of a broker generally will not be subject to
information reporting or backup withholding; however, if such broker is (1) a
United States person, (2) a controlled foreign corporation, or (3) a foreign
person that derives 50% or more of its gross income from the conduct of a trade
or business in the United States, such payment will be subject to information
reporting (but currently not backup withholding, although the issue of whether
backup withholding should apply is under consideration by the IRS) unless such
broker has documentary evidence in its records that the holder is a Non-United
States Holder under penalties of perjury or the holder otherwise establishes an
exemption.
Backup withholding is not a separate tax, but is allowed as a refund or
credit against the holder's United States federal income tax, provided the
necessary information is furnished to the IRS.
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<PAGE> 69
Interest on the Notes that is beneficially owned by a Non-United States
Holder will be reported annually by the Company on IRS Form 1042S, which must be
filed with the IRS and furnished to such beneficial owner.
Proposed Regulations Relating to Withholding and Information Reporting
On April 15, 1996, the IRS issued proposed revisions (the "Proposed
Regulations") to the Treasury regulations interpreting the withholding tax,
information reporting and backup withholding tax rules described above. The
Proposed Regulations would change in some respects the requirements for
providing the IRS Forms described above, including (i) requiring Non-United
States Holders claiming certain exemptions from or reductions of United States
withholding tax under an income tax treaty to provide their United States TINs,
(ii) requiring partners of a foreign partnership that is a holder of Notes or
Common Stock into which the Notes are converted to provide the required IRS
Forms, and (iii) modifying the procedures by which financial intermediaries
would provide the required certifications and IRS Forms.
The Proposed Regulations are not binding before being adopted either as
temporary or final Treasury regulations and will not be effective until the date
specified in such temporary or final Treasury regulations. The Proposed
Regulations are proposed generally to be effective for payments made after
December 31, 1997. It is not possible to predict whether, or in what form, the
Proposed Regulations ultimately will be adopted.
THE FOREGOING DISCUSSION OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES IS FOR
GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. ACCORDINGLY, EACH PURCHASER OF
NOTES SHOULD CONSULT SUCH PURCHASER'S OWN TAX ADVISOR WITH RESPECT TO THE TAX
CONSEQUENCES TO SUCH PURCHASER, INCLUDING THE TAX CONSEQUENCES UNDER STATE,
LOCAL, FOREIGN AND OTHER TAX LAWS, OF THE OWNERSHIP AND DISPOSITION OF THE NOTES
OR COMMON STOCK.
69
<PAGE> 70
UNDERWRITING
Subject to the terms and conditions set forth in the Underwriting Agreement
among the Company and the Underwriters named below (the "Underwriting
Agreement"), the Company has agreed to sell to the several Underwriters and the
Underwriters have severally agreed to purchase from the Company the principal
amounts of the Notes set forth opposite their names below.
<TABLE>
<CAPTION>
PRINCIPAL
UNDERWRITER AMOUNT
--------------------------------------------------------------------- ------------
<S> <C>
Salomon Brothers Inc ................................................ $ 18,750,000
Oppenheimer & Co., Inc. ............................................. 18,750,000
Prudential Securities Incorporated................................... 18,750,000
Southcoast Capital Corporation....................................... 18,750,000
First Albany Corporation............................................. 6,250,000
Hanifen, Imhoff Inc. ................................................ 6,250,000
Morgan Keegan & Company, Inc. ....................................... 6,250,000
Nesbitt Burns Securities Inc. ....................................... 6,250,000
------------
Total...................................................... $100,000,000
============
</TABLE>
In the Underwriting Agreement, the Underwriters have agreed, subject to the
terms and conditions set forth therein, that the obligations of the Underwriters
are subject to certain conditions precedent and that the Underwriters will be
obligated to purchase the entire principal amount of the Notes offered hereby if
any Notes are purchased.
The Company has been advised by the Underwriters that they propose to offer
the Notes directly to the public initially at the public offering price set
forth on the cover of this Prospectus, and to certain dealers at such price less
a concession not in excess of 2.10% of the principal amount of the Notes. The
Underwriters may allow, and such dealers may reallow, a discount not in excess
of 0.10% of the principal amount of the Notes to certain other dealers. After
the initial public offering of the Notes, the public offering price, concession
and discount may be changed.
The Company, its executive officers and directors have agreed that they
will not, without the prior written consent of Salomon Brothers Inc, which
consent may be given without prior notice, for a period of 90 days after the
date of this Prospectus, directly or indirectly, offer to sell, sell, grant any
option for the sale of or otherwise dispose of any shares of Common Stock or any
securities convertible into or exchangeable or exercisable for any shares of
Common Stock, or any right or option to acquire any such shares or securities,
except for transactions related to the Company's existing option plans and other
employee benefit plans. Sales by the Company to the Underwriters are exempt from
such restriction.
The Company has granted the Underwriters an option, exercisable during the
30-day period after the date of this Prospectus to purchase up to an additional
$15,000,000 principal amount of Notes at the initial public offering price less
the underwriting discount, solely to cover over-allotments.
The Notes have been approved for listing on the New York Stock Exchange,
subject to official notice of issuance. The Company has been advised by the
Underwriters that the Underwriters presently intend to make a market in the
Notes offered hereby; however, they are not obligated to do so. Any market
making may be discontinued at any time, and there can be no assurance that an
active public market for the Notes will develop.
The Company has agreed to indemnify the several Underwriters against
certain liabilities, including civil liabilities under the Securities Act of
1933, as amended.
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<PAGE> 71
LEGAL MATTERS
The validity of the Notes offered hereby and the information contained in
"Certain United States Tax Considerations" will be passed upon for the Company
by Jenkens & Gilchrist, a Professional Corporation, Houston, Texas. Certain
legal matters will be passed upon for the Underwriters by Andrews & Kurth
L.L.P., Houston, Texas.
EXPERTS
The audited Consolidated Financial Statements included in the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1995, which
are included in this Prospectus and elsewhere in the Registration Statement, to
the extent and for the periods indicated in their report, have been audited by
Arthur Andersen LLP, independent public accountants, as indicated in their
report with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in giving said reports. Reference is made to
said report, which includes an explanatory paragraph with respect to the change
in the method of accounting for earned interests in 1994 as discussed in Note 2
to the Company's Consolidated Financial Statements.
The reference to the reports of H.J. Gruy and Associates, Inc. contained
herein with respect to the proved reserves, the estimated future net revenues
from such proved reserves, and the discounted present values of such estimated
future net revenues, is made in reliance upon the authority of such firm as
expert with respect to such matters.
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE
The Company's Form 10-K as of December 31, 1995, its definitive proxy
statement mailed to shareholders in connection with the May 14, 1996, annual
shareholders' meeting and its Forms 10-Q for the quarterly periods ended March
31, June 30, and September 30, 1996, are incorporated herein by reference. All
documents filed by the Company pursuant to Section 13(a), 13(c), 14 or 15(d) of
the Exchange Act subsequent to the date of this Prospectus and prior to the
termination of the offering of the Notes shall be deemed to be incorporated by
reference into this Prospectus and to be a part hereof from the date of filing
of such documents. Any statement contained in a document incorporated or deemed
to be incorporated by reference herein shall be deemed to be modified or
superseded for purposes of this Prospectus to the extent that a statement
contained herein or in any other subsequently filed document which also is or is
deemed to be incorporated by reference herein modifies or supersedes such
statement. Any such statement so modified or superseded shall not be deemed,
except as so modified or superseded, to constitute a part of this Prospectus.
The Company will furnish without charge to each person to whom this Prospectus
is delivered, upon written or oral request of such person, a copy of the
documents referred to above, excluding exhibits thereto. Requests should be made
to: John R. Alden, Secretary, Swift Energy Company, 16825 Northchase Drive,
Suite 400, Houston, Texas 77060-9968.
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<PAGE> 72
SWIFT ENERGY COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Public Accountants.............................................. F-2
Consolidated Balance Sheets........................................................... F-3
Consolidated Statements of Income..................................................... F-4
Consolidated Statements of Stockholders' Equity....................................... F-5
Consolidated Statements of Cash Flows................................................. F-6
Notes to Consolidated Financial Statements............................................ F-7
</TABLE>
F-1
<PAGE> 73
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Swift Energy Company:
We have audited the accompanying consolidated balance sheets of Swift
Energy Company (a Texas corporation) and subsidiaries as of December 31, 1995
and 1994, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 1995. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Swift Energy Company and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 1994, the Company changed its method of accounting for earned
interests.
ARTHUR ANDERSEN LLP
Houston, Texas
February 19, 1996
F-2
<PAGE> 74
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
SEPTEMBER 30, ----------------------------
1996 1995 1994
------------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
Current Assets:
Cash and cash equivalents.............................. $ 1,985,790 $ 7,574,512 $ 985,498
Accounts receivable --
Oil and gas sales.................................... 5,350,643 14,765,336 12,394,636
Associated limited partnerships and joint ventures... 5,666,250 16,108,298 17,899,150
Joint interest owners................................ 4,680,739 4,044,817 4,335,283
Producing oil and gas properties held for transfer..... -- -- 3,525,841
Other current assets................................... 691,858 887,491 68,010
------------- ------------ ------------
Total Current Assets............................ 18,375,280 43,380,454 39,208,418
------------- ------------ ------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized.................... 180,608,559 132,673,707 93,368,795
Unproved properties not being amortized.............. 26,259,045 20,652,151 14,805,479
------------- ------------ ------------
206,867,604 153,325,858 108,174,274
Furniture, fixtures, and other equipment............... 5,763,745 4,367,719 3,476,695
------------- ------------ ------------
212,631,349 157,693,577 111,650,969
Less -- Accumulated depreciation, depletion, and
amortization........................................... (41,397,417) (30,169,303) (21,364,949)
------------- ------------ ------------
171,233,932 127,524,274 90,286,020
------------- ------------ ------------
Other Assets:
Receivables from associated limited partnerships, net
of current portion................................... 1,950,415 2,332,355 1,916,477
Limited partnership formation and marketing costs...... 767,682 858,559 2,991,873
Deferred charges and other............................. 533,203 1,157,065 1,269,955
------------- ------------ ------------
3,251,300 4,347,979 6,178,305
------------- ------------ ------------
$ 192,860,512 $175,252,707 $135,672,743
============= ============ ============
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<S> <C> <C> <C>
Current Liabilities:
Short-term bank borrowings............................. $ -- $ -- $ 27,229,000
Accounts payable and accrued liabilities............... 15,125,829 23,075,982 9,516,005
Payable to associated limited partnerships............. 1,787,718 16,983 637,991
Undistributed oil and gas revenues..................... 7,460,407 17,040,304 14,962,863
------------- ------------ ------------
Total Current Liabilities....................... 24,373,954 40,133,269 52,345,859
------------- ------------ ------------
Long-Term Debt........................................... -- 28,750,000 28,750,000
Bank Borrowings.......................................... 17,170,000 -- --
Deferred Revenues........................................ 4,814,573 6,063,467 7,827,562
Deferred Income Taxes.................................... 12,159,655 6,960,006 4,622,191
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, 15,091,384, 12,509,700, and 6,685,137
shares issued and outstanding, respectively.......... 150,914 125,097 66,851
Additional paid-in capital............................. 100,701,877 71,133,979 24,885,903
Retained earnings...................................... 33,489,539 22,086,889 17,174,377
------------- ------------ ------------
134,342,330 93,345,965 42,127,131
------------- ------------ ------------
$ 192,860,512 $175,252,707 $135,672,743
============= ============ ============
</TABLE>
See accompanying notes to Consolidated Financial Statements.
F-3
<PAGE> 75
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
--------------------------- --------------------------------------------
1996 1995 1995 1994 1993
----------- ----------- ----------- ------------ -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales.................. $33,733,101 $15,208,354 $22,527,892 $ 19,802,188 $15,535,671
Earned interests from limited
partnerships and joint
ventures......................... -- -- -- -- 3,308,623
Fees from limited partnerships and
joint ventures................... 615,698 339,157 590,441 701,528 763,347
Supervision fees................... 3,277,111 2,838,170 3,838,815 3,751,061 3,718,829
Interest income.................... 35,272 132,116 212,329 47,980 201,584
Other, net......................... 1,517,749 1,354,635 1,761,568 1,072,535 604,599
----------- ----------- ----------- ------------ -----------
39,178,931 19,872,432 28,931,045 25,375,292 24,132,653
----------- ----------- ----------- ------------ -----------
Costs and Expenses:
General and administrative, net of
reimbursement.................... 4,600,875 3,969,942 5,256,184 5,197,899 5,065,323
Depreciation, depletion, and
amortization..................... 11,314,174 6,138,496 8,838,657 7,904,801 7,300,967
Oil and gas production............. 5,748,935 5,100,864 6,826,306 5,639,630 4,540,290
Interest expense, net.............. 293,907 1,283,485 1,115,361 1,795,133 597,465
----------- ----------- ----------- ------------ -----------
21,957,891 16,492,787 22,036,508 20,537,463 17,504,045
----------- ----------- ----------- ------------ -----------
Income Before Income Taxes........... 17,221,040 3,379,645 6,894,537 4,837,829 6,628,608
Provision for Income Taxes........... 5,818,390 859,214 1,982,025 1,112,158 1,732,355
----------- ----------- ----------- ------------ -----------
Income Before Cumulative Effect of
Change in Accounting Principle..... 11,402,650 2,520,431 4,912,512 3,725,671 4,896,253
Cumulative Effect of Change in
Accounting Principle............... -- -- -- (16,772,698) --
----------- ----------- ----------- ------------ -----------
Net Income (Loss).................... $11,402,650 $ 2,520,431 $ 4,912,512 $(13,047,027) $ 4,896,253
=========== =========== =========== ============ ===========
Per Share Amounts --
Primary:
Income Before Cumulative Effect of
Change in Accounting Principle... $ 0.87 $ 0.32 $ 0.54 $ 0.56 $ 0.74
Cumulative Effect of Change in
Accounting Principle............. $ -- $ -- $ -- $ (2.52) $ --
----------- ----------- ----------- ------------ -----------
Net Income (Loss).................. $ 0.87 $ 0.32 $ 0.54 $ (1.96) $ 0.74
=========== =========== =========== ============ ===========
Fully Diluted:
Income Before Cumulative Effect of
Change in Accounting Principle... $ 0.87 $ 0.32 $ 0.54 $ 0.56 $ 0.70
Cumulative Effect of Change in
Accounting Principle............. $ -- $ -- $ -- $ (2.52) $ --
----------- ----------- ----------- ------------ -----------
Net Income (Loss).................. $ 0.87 $ .32 $ 0.54 $ (1.96) $ 0.70
=========== =========== =========== ============ ===========
Weighted Average Shares
Outstanding........................ 13,139,558 7,994,703 9,122,857 6,644,248 6,588,076
Pro forma amounts assuming change in
accounting for earned interests is
applied retroactively (see Note
2) --
Net Income......................... $ 3,725,671 $ 4,322,478
Per Share Amounts --
Primary.......................... $ 0.56 $ 0.66
Fully Diluted.................... $ 0.56 $ 0.63
</TABLE>
See accompanying notes to Consolidated Financial Statements.
F-4
<PAGE> 76
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED
STOCK(1) CAPITAL EARNINGS TOTAL
-------- ------------ ------------ ------------
<S> <C> <C> <C> <C>
Balance, December 31, 1992.......... $ 59,686 $ 17,227,567 $ 31,994,033 $ 49,281,286
Stock issued for benefit plans
(19,096 shares)................ 191 170,059 -- 170,250
Stock options exercised
(13,400 shares)................ 134 117,791 -- 117,925
Net income........................ -- -- 4,896,253 4,896,253
-------- ------------ ------------ ------------
Balance, December 31, 1993.......... $ 60,011 $ 17,515,417 $ 36,890,286 $ 54,465,714
Stock issued for benefit plans
(26,488 shares)................ 265 271,176 -- 271,441
Stock options exercised
(21,472 shares)................ 214 176,808 -- 177,022
Employee stock purchase plan
(29,840 shares)................ 298 259,683 -- 259,981
10% stock dividend
(606,262 shares)............... 6,063 6,662,819 (6,668,882) --
Net loss.......................... -- -- (13,047,027) (13,047,027)
-------- ------------ ------------ ------------
Balance, December 31, 1994.......... $ 66,851 $ 24,885,903 $ 17,174,377 $ 42,127,131
Stock issued for benefit plans
(31,113 shares)................ 311 283,463 -- 283,774
Stock options exercised
(5,761 shares)................. 58 33,736 -- 33,794
Employee stock purchase plan
(37,689 shares)................ 377 289,465 -- 289,842
Stock issued in public offering
(5,750,000 shares)............. 57,500 45,641,412 -- 45,698,912
Net income........................ -- -- 4,912,512 4,912,512
-------- ------------ ------------ ------------
Balance, December 31, 1995.......... $125,097 $ 71,133,979 $ 22,086,889 $ 93,345,965
Stock issued for benefit plans
(30,014 shares)(2)............. 300 349,645 -- 349,945
Stock options exercised
(172,175 shares)(2)............ 1,722 1,317,057 -- 1,318,779
Employee stock purchase plan
(36,387 shares)(2)............. 364 272,178 -- 272,542
Debenture conversion
(2,343,108 shares)(2).......... 23,431 27,629,018 -- 27,652,449
Net income(2)..................... -- -- 11,402,650 11,402,650
-------- ------------ ------------ ------------
Balance, September 30, 1996(2)...... $150,914 $100,701,877 $ 33,489,539 $134,342,330
======== ============ ============ ============
</TABLE>
- ---------------
(1) $.01 par value.
(2) Unaudited.
See accompanying notes to Consolidated Financial Statements.
F-5
<PAGE> 77
SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------------------- --------------------------------------------
1996 1995 1995 1994 1993
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
(UNAUDITED)
Cash Flows from Operating Activities:
Net income (loss).................... $ 11,402,650 $ 2,520,431 $ 4,912,512 $(13,047,027) $ 4,896,253
Adjustments to reconcile net income
to net cash provided by
operating activities --
Depreciation, depletion, and
amortization....................... 11,314,174 6,138,496 8,838,657 7,904,801 7,300,967
Deferred income taxes................ 5,153,481 654,975 2,326,162 963,324 1,199,057
Earned interests from limited
partnerships and joint ventures.... -- -- -- -- (3,308,623)
Deferred revenue amortization related
to production payment.............. (1,259,680) (1,349,253) (1,787,974) (1,993,863) (2,304,080)
Cumulative effect of change in
accounting principle............... -- -- -- 16,772,698 --
Other................................ 86,597 84,168 112,890 105,180 49,865
Change in assets and liabilities --
(Increase) decrease in accounts
receivable....................... 365,321 (111,746) (488,599) (762,789) (412,960)
Increase (decrease) in accounts
payable and accrued liabilities,
excluding income taxes payable... (1,289,771) 559,529 1,074,532 142,883 110,324
Increase (decrease) in income taxes
payable.......................... 578,559 50,584 (611,717) 309,307 (292,463)
------------ ------------ ------------ ------------ ------------
Net Cash Provided by Operating
Activities....................... 26,351,331 8,547,184 14,376,463 10,394,514 7,238,340
------------ ------------ ------------ ------------ ------------
Cash Flows from Investing Activities:
Additions to property and
equipment.......................... (55,996,465) (21,076,168) (40,032,944) (34,531,180) (24,229,103)
Proceeds from the sale of property
and equipment...................... 1,149,570 -- 230,242 861,073 157,972
Net cash received (distributed) as
operator of oil and gas
properties......................... (6,056,094) (628,288) 7,662,419 (229,351) (2,556,483)
Property acquisition costs (incurred
on behalf of) reimbursed by
partnerships and joint ventures.... 10,823,988 5,707,418 5,316,693 (1,408,031) (10,252,142)
Limited partnership formation and
marketing costs.................... -- (354,260) -- -- (103,871)
Prepaid drilling costs............... (336,758) (102,088) -- -- (1,100,076)
Other................................ (75,274) 5,573 (41,181) (25,320) (98,437)
------------ ------------ ------------ ------------ ------------
Net Cash Used in Investing
Activities....................... (50,491,033) (16,447,813) (26,864,771) (35,332,809) (38,182,140)
------------ ------------ ------------ ------------ ------------
Cash Flows from Financing Activities:
Proceeds from long-term debt......... -- -- -- -- 28,750,000
Net proceeds from (payments of) bank
borrowings......................... 17,170,000 (27,229,000) (27,229,000) 24,579,000 2,650,000
Net proceeds from issuances of common
stock.............................. 1,949,730 46,312,013 46,306,322 708,444 288,175
Loan to ESOP plan.................... (568,750) -- -- -- --
Payments of debt issuance costs...... -- -- -- -- (1,425,000)
------------ ------------ ------------ ------------ ------------
Net Cash Provided by Financing
Activities................... 18,550,980 19,083,013 19,077,322 25,287,444 30,263,175
------------ ------------ ------------ ------------ ------------
Net Increase (Decrease) in Cash and
Cash Equivalents..................... $ (5,588,722) $ 11,182,384 $ 6,589,014 $ 349,149 $ (680,625)
------------ ------------ ------------ ------------ ------------
Cash and Cash Equivalents at Beginning
of Period............................ 7,574,512 985,498 985,498 636,349 1,316,974
------------ ------------ ------------ ------------ ------------
Cash and Cash Equivalents at End of
Period............................... $ 1,985,790 $ 12,167,882 $ 7,574,512 $ 985,498 $ 636,349
============ ============ ============ ============ ============
Supplemental Disclosures of Cash Flow
Information:
Cash paid during period for interest,
net of amounts capitalized........... $ 1,168,768 $ 732,130 $ 68,097 $ 1,691,400 $ 605,063
Cash paid during period for income
taxes................................ $ 84,992 $ 163,655 $ 277,580 $ 97,200 $ 756,761
</TABLE>
See accompanying notes to Consolidated Financial Statements.
F-6
<PAGE> 78
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
Swift Energy Company (Swift) and its wholly owned subsidiaries (collectively
referred to as the "Company"), which is engaged in the acquisition, development,
operation, and exploration of oil and natural gas properties, with particular
emphasis on U.S. onshore natural gas reserves. The Company also has oil and gas
investments in Russia, Venezuela, and New Zealand. The Company's investments in
associated oil and gas partnerships and its joint ventures are accounted for
using the proportionate consolidation method, whereby the Company's
proportionate share of each entity's assets, liabilities, revenues, and expenses
is included in the appropriate classifications in the consolidated financial
statements. Intercompany balances and transactions have been eliminated in
preparing the consolidated statements. Certain reclassifications have been made
to prior year amounts to conform to the current year presentation.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles 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.
UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
The interim consolidated financial statements as of September 30, 1996 and
for the nine months ended September 30, 1996 and 1995 and notes thereto are
unaudited. In the opinion of management, these interim financial statements
include all adjustments necessary for a fair presentation and all such
adjustments are of a normal recurring nature. Results of the interim periods are
not necessarily indicative of the results for the entire year.
PROPERTY AND EQUIPMENT
The Company follows 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. Such costs include lease
acquisitions, geological and geophysical services, drilling, completion,
equipment, and certain general and administrative costs directly associated with
acquisition, exploration, and development activities. General and administrative
costs related to production and general overhead are expensed as incurred. No
gains or losses are recognized upon the sale or disposition of oil and gas
properties, except in transactions 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 the
Company's capitalized oil and gas property costs are
F-7
<PAGE> 79
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
amortized. The Company's properties are all onshore and historically the salvage
value of the tangible equipment offsets the Company's site restoration and
dismantlement and abandonment costs. The Company expects this relationship will
continue.
The Company computes the provision for depreciation, depletion, and
amortization of oil and gas properties on the unit-of-production method. Under
this method, the Company computes 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. The cost of unproved properties not being amortized
is assessed quarterly to determine whether the value has been impaired below the
capitalized cost. Any impairment assessed is added to the cost of proved
properties being amortized.
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
prices, discounted at 10%, and the lower of cost or fair value of unproved
properties, adjusted for related income tax effects ("Ceiling Limitation").
The calculation of the Ceiling Limitation 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.
All other equipment is depreciated by the straight-line method at rates
based on the estimated useful lives of the property. Repairs and maintenance are
charged to expense as incurred. Renewals and betterments are capitalized.
DEFERRED CHARGES AND OTHER
Legal and accounting fees, underwriting fees, printing costs, and other
direct expenses associated with the issuance of the Company's 6 1/2% Convertible
Subordinated Debentures due 2003 (the "Debentures") in June 1993 have been
capitalized and through June 30, 1996 were being amortized over the life of the
Debentures. Due to the conversion of all outstanding Debentures into Common
Stock in August 1996, as discussed below, related unamortized costs ($1,097,551)
were transferred to the Company's appropriate capital accounts in the third
quarter of 1996.
All of the amounts under deferred charges and other at September 30, 1996
relate to the Company's Employee Stock Ownership Plan ("ESOP"), effective as of
January 1, 1996. All employees over the age of 21 with one year of service are
participants. The Plan has a five year cliff vesting and service is recognized
after the Plan effective date. The ESOP is designed to enable employees of the
Company to accumulate stock ownership. While there will be no employee
contributions, participants will receive an allocation of stock which has been
contributed by the Company. The Plan may also acquire Swift Energy Company
Common Stock purchased at fair market value. The ESOP can borrow money from the
Company to buy Company stock as was done in September 1996 to purchase 25,000
shares from the Company's Chairman. Benefits will be paid
F-8
<PAGE> 80
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
in a lump sum or installments, and the participant generally has the choice of
receiving cash or stock.
LIMITED PARTNERSHIPS AND JOINT VENTURES
Between 1991 and 1995, the Company formed limited partnerships and joint
ventures for the purpose of acquiring interests in producing oil and gas
properties and, since 1993, partnerships engaged in drilling for oil and gas
reserves. The Company serves as managing general partner or manager of these
entities. The Company's investments in associated oil and gas partnerships and
its joint ventures are accounted for using the proportionate consolidation
method, whereby the Company's proportionate share of each entity's assets,
liabilities, revenues, and expenses is included in the appropriate
classifications in the consolidated financial statements. Because the Company
serves as the general partner of these entities, under state partnership law it
is contingently liable for the liabilities of these partnerships, virtually all
of which is owed to the Company and are not material for any of the periods
presented in relation to the partnerships' respective assets.
Under the Swift Depositary Interests limited partnership offering ("SDI
Offering"), which commenced in March 1991 and concluded in December 1995, the
Company received a reimbursement of certain costs and a fee, both payable out of
revenues. The Company bore all front-end costs of the offering and partnership
formations for which it received an interest in the partnerships. Upon the
Company's decision to conclude the SDI offering at the end of 1995, the
remaining limited partnership formation and marketing costs related to the SDI
offering (approximately $1,750,000) were accordingly transferred to the oil and
gas properties account.
Commencing September 15, 1993, the Company began offering, on a private
placement basis, general and limited partnership interests in limited
partnerships to be formed to drill for oil and gas. As managing general partner,
the Company pays for all front-end costs incurred in connection with these
offerings, for which the Company receives an interest in the partnerships.
Through September 30, 1996, approximately $34,800,000 had been raised in seven
partnerships, one closed in each of 1993 and 1994, three in 1995, and two in
1996. In July and September 1996, the Company closed the sixth and seventh
partnerships with total subscriptions of approximately $4,900,000 and
$10,000,000, respectively. Costs of syndication, registration, and qualification
of these limited partnerships incurred by the Company have been deferred. Under
the current private limited partnership offerings, selling and formation costs
borne by the Company serve as the Company's general partner contribution to such
partnerships. The Company anticipates formation of one additional partnership in
1996.
HEDGING ACTIVITIES
The Company's revenues are primarily the result of sales of its 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, the Company
does engage periodically in certain limited hedging activities, but only to the
extent of buying protection price floors for portions of its and the limited
partnerships' oil and gas production. Costs and/or benefits derived from these
price floors are accordingly recorded as a reduction or increase in oil and gas
sales revenue and was not significant for any period presented.
F-9
<PAGE> 81
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
INCOME (LOSS) PER SHARE
Primary income (loss) per share has been computed using the weighted
average number of common shares outstanding during the respective periods. Stock
options and warrants outstanding do not have a dilutive effect on primary income
(loss) per share. The Company's Debentures are not common stock equivalents for
the purpose of computing primary income (loss) per share.
Primary income (loss) per share has been retroactively restated in all
periods presented to give recognition to an equivalent change in capital
structure as a result of a 10% stock dividend. On September 6, 1994, the Company
declared a 10% stock dividend to shareholders of record on September 19, 1994,
which was distributed on September 29, 1994, resulting in an additional 606,262
shares being issued.
The calculation of fully diluted income (loss) per share assumes conversion
of the Debentures as of the beginning of the period and the elimination of the
related after-tax interest expense and assumes, as of the beginning of the
period, exercise (using the treasury stock method) of stock options and
warrants. The conversion price of the Debentures was revised to reflect the 10%
stock dividend declared September 6, 1994. The original conversion price was
$13.50 per common share and the revised conversion price per common share is
$12.27. Fully diluted income (loss) per share has also been retroactively
restated for all periods presented to give effect to the resulting conversion
price revision stemming from the 10% stock dividend. The weighted average number
of shares used in the computation of fully diluted per share amounts were
11,671,243, 9,053,736, and 7,797,660 for the respective years ended December 31,
1995, 1994, and 1993, and 13,647,445 for the respective nine-month period ended
September 30, 1996. During the nine-month period ended September 30, 1995, such
amount was antidilutive.
INCOME TAXES
The Company accounts for Income Taxes using Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." SFAS No. 109
utilizes the liability method and deferred taxes are determined based on the
estimated future tax effects of differences between the financial statement and
tax bases of assets and liabilities given the provisions of the enacted tax
laws.
DEFERRED REVENUES
In May 1992, as discussed in Note 9 "Oil and Gas Producing Activities," the
Company purchased interests in certain wells using funds provided by the
Company's sale of a volumetric production payment in these properties. Under the
terms of the production payment agreement, the Company continues to own the
properties purchased but is required to deliver a minimum quantity of
hydrocarbons produced from the properties (meeting certain quality and heating
equivalent requirements) over a specified period. Since entering into this
agreement, the Company has met all scheduled deliveries. Net proceeds from the
sale of the production payment were recorded as deferred revenues. Deliveries
under the production payment agreement are recorded as oil and gas sales
revenues and a corresponding reduction of deferred revenues.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid debt instruments with an initial
maturity of three months or less to be cash equivalents.
F-10
<PAGE> 82
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
VULNERABILITY DUE TO CERTAIN CONCENTRATIONS
The Company extends credit to various companies in the oil and gas industry
which results in a concentration of credit risk. The concentration of credit
risk may be affected by changes in economic or other conditions and may
accordingly impact the Company's overall credit risk. However, the Company
believes that the risk is mitigated by the size, reputation, and nature of the
companies to which the Company extends credit.
Only one single oil or gas purchaser accounted for 10% or more of the
Company's consolidated revenues during the year ended December 31, 1995, with
that purchaser accounting for approximately 12%. The Company does not believe
that the loss of any single oil and gas purchaser or contract would materially
affect its sales.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash equivalents,
accounts receivable, accounts payable, and long-term debt. The carrying amounts
of cash and cash equivalents, accounts receivable, and accounts payable
approximate fair value due to the highly liquid nature of these short-term
instruments. The fair value of long-term debt was determined based upon interest
rates currently available to the Company for borrowings with similar terms. The
fair value of long-term debt approximates the carrying amount as of December 31,
1995.
2. CHANGE IN ACCOUNTING PRINCIPLE
In the fourth quarter of 1994, the Company changed its revenue recognition
policy for earned interests, effective January 1, 1994. Under the Company's
current method of accounting for earned interests, such amounts will not be
recognized as income, thereby reducing the Company's investment in oil and gas
property. This change was made as the result of a transition in the Company's
current business activities and changes in the oil and gas limited partnership
syndication markets. The Company feels the change in policy results in more
comparable financial statements in relation to its current business focus and in
comparison to its current peers and competitors in the oil and gas exploration
and production industry.
The effect of the change was to increase 1994 income before cumulative
effect of change in accounting principle by approximately $1,047,000 or $.16 per
share. This increase was a result of the decrease in current year depletion
expense more than offsetting the decrease in revenues as a result of not
recognizing earned interests. The cumulative effect of this change in accounting
principle resulted in a downward adjustment to earnings of $16,772,698 or $2.52
per share (after reduction for income taxes of $8,640,481), to retroactively
apply the new method, thereby reducing net income in 1994. See Note 9 to the
Company's financial statements for the effect this change had on oil and gas
properties and accumulated depreciation, depletion, and amortization. The pro
forma amounts shown on the income statement have been adjusted for the effect of
retroactive application, had the new method been in effect during the periods
presented.
F-11
<PAGE> 83
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
3. PROVISION FOR INCOME TAXES
The Omnibus Budget Reconciliation Act of 1993 (the "Act") was enacted on
August 10, 1993. The Act contains several changes to federal income tax
provisions, including an increase in the highest corporate tax rate from 34% to
35%, for companies with taxable income in excess of $10,000,000. The effect of
the Act on income tax expense for the year ended December 31, 1993, and the
Company's net deferred tax liability was not material.
The following is an analysis of the consolidated income tax provision:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Current....................................... $ (344,137) $ 148,834 $ 533,298
Deferred...................................... 2,326,162 963,324 1,199,057
---------- ---------- ----------
Total......................................... $1,982,025 $1,112,158 $1,732,355
========== ========== ==========
</TABLE>
There are differences between income taxes computed using the statutory
rate (34% for 1995, 1994, and 1993) and the Company's effective income tax rates
(28.7%, 23.0%, and 26.1% for 1995, 1994, and 1993, respectively), primarily as
the result of certain tax credits available to the Company. Reconciliations of
income taxes computed using the statutory rate to the effective income tax rates
are as follows:
<TABLE>
<CAPTION>
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Income taxes computed at federal statutory
rate....................................... $2,344,143 $1,644,862 $2,253,727
State tax provisions, net of federal
benefits................................... 84,202 46,525 149,002
Nonconventional fuel source credit........... (370,000) (435,016) (553,651)
Depletion deductions in excess of basis...... (34,000) (30,895) (98,596)
Other, net................................... (42,320) (113,318) (18,127)
---------- ---------- ----------
Provision for income taxes................... $1,982,025 $1,112,158 $1,732,355
========== ========== ==========
</TABLE>
The tax effects of significant temporary differences representing the net
deferred tax liability at December 31, 1995, 1994, and 1993 were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
---------- ---------- -----------
<S> <C> <C> <C>
Deferred tax assets:
Alternative minimum tax credits........... $1,372,978 $ 900,562 $ 786,774
Other..................................... 115,332 7,112 231,292
---------- ---------- -----------
Total deferred tax assets......... $1,488,310 $ 907,674 $ 1,018,066
Deferred tax liabilities:
Oil and gas properties.................... $7,682,701 $4,811,886 $12,576,208
Other..................................... 650,283 614,300 637,527
---------- ---------- -----------
Total deferred tax liabilities.... $8,332,984 $5,426,186 $13,213,735
---------- ---------- -----------
Net deferred tax liability(1)............... $6,844,674 $4,518,512 $12,195,669
========== ========== ===========
</TABLE>
- ---------------
(1) This amount includes a current deferred tax asset amounts of $115,332,
$103,679, and $96,567 for 1995, 1994, and 1993, respectively.
The Company did not record any valuation allowances against deferred tax
assets at December 31, 1995, 1994, and 1993.
F-12
<PAGE> 84
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
At December 31, 1995, the Company had an alternative minimum tax
carryforward of $1,372,978 indefinitely available to reduce future regular tax
liability to the extent it exceeds the related tentative minimum tax otherwise
due.
4. BANK BORROWINGS
The Company had available, through a two-bank group, a revolving line of
credit of $35,000,000 at the end of 1995 and $29,000,000 at the end of 1994
bearing interest at the bank's base rate plus 0.5% (9% at both December 31,
1995, and at December 31, 1994), secured by the Company's interests in certain
oil and gas properties and general partner interests. This facility also allows,
at the Company's option, draws which bear interest for specific periods at the
London Interbank Offered Rate ("LIBOR") plus 2.25%. There was no outstanding
balance under this line of credit at December 31, 1995. At December 31, 1994,
$14,000,000 of the $18,600,000 outstanding was at the LIBOR plus 2.25% rates
(7.875% on $3,000,000, 8.1875% on $6,000,000, and 8.5% on $5,000,000). The
outstanding amount under this facility at December 31, 1994 ($18,600,000) was
borrowed primarily to fund the advance purchase of producing properties on
behalf of affiliated partnerships and/or joint ventures to be subsequently
reimbursed and to fund the Company's working capital and capital expenditures
needs.
Effective April 30, 1996, this credit agreement was restated. The facility
was increased to $100,000,000 and is now unsecured. The available borrowing base
currently is $30,000,000 at September 30, 1996 and will be redetermined
periodically. Depending on the level of outstanding debt, the interest rate
currently will be either the bank's base rate or the bank's base rate plus 0.25%
(8.25% at September 30, 1996). This facility also allows, at the Company's
option, draws which bear interest for specific periods at the London Interbank
Offered Rate ("LIBOR"). The LIBOR option will now vary from plus 1% to plus
1.5%. At September 30, 1996, $17,000,000 was outstanding under this line, all
bearing interest under the LIBOR rate option at rates ranging from 6.562% to
6.8125%. The outstanding amount under this facility at September 30, 1996 was
borrowed primarily to fund the Company's working capital needs and capital
expenditures. The restated revolving line of credit extends through September
30, 1999, and accordingly is classified on the balance sheet as a long-term
liability.
The terms of the revolving line of credit include, among other
restrictions, a limitation on the level of cash dividends (not to exceed
$2,000,000 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 the Company's common stock. The Company
presently intends to continue a policy of using retained earnings for expansion
of its business. For all periods presented, the Company was in compliance with
the provisions of these agreements.
The Company's second credit line was an Acquisition Advance Agreement with
the same two-bank group, bearing interest at the greater of (a) the bank's base
rate plus 1% or (b) the Federal Funds rate plus 1.5%, to be secured by producing
oil and gas properties acquired and held for transfer. At December 31, 1994,
$3,629,000 had been borrowed under this agreement to fund the advance purchase
of producing properties on behalf of affiliated partnerships and/or joint
ventures to be subsequently reimbursed. This credit agreement expired June 15,
1995.
The Company's third credit facility is an amended and restated revolving
line of credit with the lead bank for $5,000,000, bearing interest at the bank's
base rate (8.5% at both December 31, 1995, and at December 31, 1994), secured by
certain Company receivables. There were no outstanding amounts under this
facility at December 31, 1995. At December 31, 1994, $5,000,000 was
F-13
<PAGE> 85
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
outstanding under this facility. This facility, effective April 30, 1996, was
amended to $7,000,000 (from $5,000,000), with interest at the bank's base rate
less 0.25% (8% at September 30, 1996). At September 30, 1996, $170,000 was
outstanding under this facility. This restated credit facility extends through
September 30, 1999, and is also recorded as a long-term liability.
In addition to interest on these credit facilities, the Company pays a
commitment fee to compensate the banks for making funds available. The fee on
the revolving line of credit is calculated on the average daily remainder, if
any, of the commitment amount less the aggregate principal amounts outstanding,
plus the amount of all letters of credit outstanding during the period. The fee
on the Acquisition Advance Agreement was 0.5% of the amount of the advance. The
aggregate amounts of commitment fees paid by the Company were $140,000 for the
first nine months of 1996, $154,000 in 1995, and $150,000 in 1994.
5. LONG-TERM DEBT
The Company's long-term debt previously consisted of $28,750,000 of 6.5%
Convertible Subordinated Debentures due 2003. The Debentures were issued on June
30, 1993 under terms making them convertible into common stock of the Company by
the holders at any time prior to maturity at a conversion price of $12.27.
Interest on the Debentures has been payable semiannually on June 30 and December
31, commencing with the payment made at December 31, 1993. The Debentures became
redeemable for cash at the option of the Company after June 30, 1996 at 104.55%
of principal.
On July 1, 1996, the Company called all of the Debentures for redemption on
August 5, 1996 at 104.55% of their face amount, plus accrued interest since June
30, 1996. The Debentures continued to be convertible into shares of Common Stock
at $12.27 per share through August 5, 1996. Prior to the redemption date, the
holders of all of the outstanding Debentures elected to convert their Debentures
into shares of Common Stock, resulting in the issuance of 2.34 million shares of
Common Stock in August 1996.
Upon conversion of the Debentures into Common Stock, the approximate
$27,650,000 net carrying amount of the debt (the face amount less unamortized
deferred charges) was transferred to the Company's appropriate capital accounts
during the third quarter of 1996.
Interest expense on the Debentures, including amortization of debt issuance
costs, totaled $993,890 for the nine-month period ending September 30, 1996,
$1,981,639 for 1995, $1,973,931 for 1994, and $984,239 for 1993.
6. COMMITMENTS AND CONTINGENCIES
Total rental and lease expenses charged to earnings before reimbursements
were $998,714 in 1995, $1,159,673 in 1994, and $1,155,564 in 1993. The Company's
remaining minimum annual obligations under non-cancelable operating lease
commitments are $1,016,616 for 1996, $1,083,830 for 1997, $1,159,185 for 1998,
$1,207,707 for 1999, and $1,201,448 for 2000.
As of September 30, 1996, the Company is the managing general partner of
103 limited partnerships. Because the Company serves as the general partner of
these entities, under state partnership law it is contingently liable for the
liabilities of these partnerships, which liabilities are not material for any of
the periods presented in relation to the partnerships' respective assets. These
partnership liabilities generally consist of third party borrowings from time to
time to fund capital expenditures for development of oil and gas properties, and
will be repaid from oil and gas sales proceeds of the partnerships in future
periods.
F-14
<PAGE> 86
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
In the ordinary course of business, the Company has been party to various
legal actions, which arise primarily from its activities as operator of oil and
gas wells. In management's opinion, the outcome of any such currently pending
actions will not have a material adverse effect on the financial position or
results of operations of the Company.
7. STOCKHOLDERS' EQUITY
COMMON STOCK
On September 6, 1994, the Company declared a 10% stock dividend to
shareholders of record on September 19, 1994, which was distributed on September
29, 1994. The transaction was valued based on the closing price ($11.00) of the
Company's common stock on the New York Stock Exchange on September 6, 1994. As a
result of the issuance of 606,262 shares of the Company's common stock as a
dividend, retained earnings were reduced by $6,668,882, with the common stock
and additional paid-in capital accounts increased by the same amount. Primary
and fully diluted income (loss) per share was restated for all periods presented
to reflect the effect of the stock dividend.
During the third quarter of 1995, the Company closed the sale to the public
of 5,750,000 shares of common stock at a price of $8.50 per share. Net proceeds
from this offering were $45,698,912 and were used to repay outstanding
indebtedness, with the remaining proceeds being used to finance the Company's
exploration and development activities, and to acquire producing oil and gas
properties, including limited partnership interests.
In August 1996, the holders of the Company's Debentures converted such
Debentures into 2.34 million shares of the Company's Common Stock, which
resulted in a third quarter 1996 increase in the Company's capital accounts of
approximately $27,650,000.
STOCK OPTIONS AND WARRANTS
The Company has an employee option plan under which incentive stock options
and other options and awards may be granted to employees to purchase shares of
common stock and a nonqualified stock option plan under which non-employee
members of the Company's Board of Directors may be granted options to purchase
shares of common stock. The plans provide that the exercise prices equal 100% of
the fair value of the common stock on the date of grant. Options become
exercisable for 20% of the shares on the first anniversary of the grant of the
option and are exercisable for an additional 20% per year thereafter. Options
granted expire 10 years after the date of grant or earlier in the event of the
optionee's separation from employment. No accounting entries are required until
the stock options are exercised, at which time the option price is credited to
the common stock and additional paid-in capital accounts. The effect of the 10%
stock dividend increased the number of shares and decreased the price according
to the respective agreements.
F-15
<PAGE> 87
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
The following is a summary of stock options under these plans:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1995 1994
-------------- --------------
<S> <C> <C>
Options outstanding, beginning of period......... 1,166,920 899,650
Options granted.................................. 227,502 202,760
Options terminated............................... (80,270) (20,658)
Options exercised................................ (5,761) (21,472)
Options adjusted for stock dividend.............. -- 106,640
-------------- --------------
Options outstanding, end of period............... 1,308,391 1,166,920
============== ==============
Options exercisable, end of period............... 722,627 546,172
============== ==============
Options available for future grant, end of
period......................................... 343,344 498,909
============== ==============
Option price range:
Options granted................................ $7.045-$10.114 $9.091-$10.25
Options terminated............................. $7.045-$10.114 $7.045-$12.386
Options exercised.............................. $7.045-$10.114 $7.045-$ 9.773
Options outstanding, end of period............. $5.455-$12.386 $5.455-$12.386
</TABLE>
The Company also has granted certain stock options to individuals who are
neither employees, officers, nor directors, for specific services rendered to
the Company. At December 31, 1995, the only outstanding options under this plan
were granted in 1991 covering 68,750 shares at $9.773 (after adjustment for the
September 1994 stock dividend). During the three years ended December 31, 1995,
the only other activity has been the cancellation of 5,350 option shares in
1993.
The Company also has a plan which provides eligible employees the
opportunity to acquire shares of Company common stock at a discount through
payroll deductions. This plan was approved at the May 11, 1993, shareholders
meeting. The plan year is from June 1 to the following May 31. The first year of
the plan commenced June 1, 1993. Employees may authorize payroll deductions of
up to 10% of their base salary during the plan year by making an election to
participate prior to the start of a plan year. The purchase price for stock
acquired under the plan will be 85% of the lower of the closing price of the
Company's common stock as quoted on the New York Stock Exchange at the beginning
or end of the plan year or a date during the year chosen by the participant. The
Company issued 37,689 and 29,840 shares under this plan at a range of prices of
$6.80 to $7.92 and a price of $8.71 during 1995 and 1994, respectively. As of
December 31, 1995, there were 479,487 shares available for issuance under this
plan. There are no charges or credits to income in connection with this plan.
In October 1995 the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which establishes accounting and reporting standards for
stock-based employee compensation plans. SFAS No. 123 defines a fair value-based
method of accounting for stock options or similar equity instruments, but allows
companies to continue to measure compensation cost using the intrinsic
value-based method prescribed by Accounting Principles Board Opinion ("APB") No.
25, "Accounting for Stock Issued to Employees." Under the fair value-based
method, compensation cost is measured at the grant date based on the value of
the award and is recognized over the service period (generally, the vesting
period). Under the intrinsic value-based method, compensation cost is the
excess, if any, of the quoted market price of the stock at the date of grant
over the exercise price.
F-16
<PAGE> 88
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
Under the provisions of SFAS No. 123, a company may elect to measure
compensation cost associated with its stock option and similar plans as a
component of compensation expense in its statement of operations. Companies may
also elect to continue to measure compensation cost under the provisions of APB
No. 25. Companies which elect to continue measurement under APB No. 25 are
required to provide pro forma disclosure in the notes to financial statements
reflecting the difference, if any, between compensation cost included in net
income and the cost if the fair value-based method were used including effects
on earnings per share. Since the inception of the Option Plan, the Company has
not recognized any compensation cost related to grants of stock options. The
disclosure requirements of this statement are effective for financial statements
for fiscal years beginning after December 15, 1995. At this time, the Company
does not expect to adopt the fair value-based method of accounting for its stock
option plans and, accordingly, adoption of this statement will have no impact on
the Company's results of operations.
8. RELATED-PARTY TRANSACTIONS
The Company is the operator of a substantial number of properties owned by
its affiliated limited partnerships and joint ventures and accordingly charges
these entities and third party joint interest owners operating fees. The Company
is also reimbursed for direct, administrative, and overhead costs incurred in
conducting the business of the limited partnerships, which totaled approximately
$4,800,000, $4,400,000, and $4,200,000, in 1995, 1994, and 1993, respectively.
The Company was also reimbursed by the limited partnerships and joint ventures
for costs incurred in the screening, evaluation, and acquisition of producing
oil and gas properties on their behalf. Such costs totaled approximately
$600,000, $1,400,000, and $2,500,000 in 1995, 1994, and 1993, respectively.
9. OIL AND GAS PRODUCING ACTIVITIES
CAPITALIZED COSTS
The following table presents the Company's aggregate capitalized costs
relating to oil and gas producing activities and the related depreciation,
depletion, and amortization:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
Oil and Gas Properties:
Proved............................................. $132,673,707 $ 93,368,795(1)
Unproved (not being amortized)..................... 20,652,151 14,805,479
------------ ------------
153,325,858 108,174,274
Accumulated Depreciation, Depletion, and
Amortization....................................... (28,107,986) (19,758,662)(1)
------------ ------------
$125,217,872 $ 88,415,612
============ ============
</TABLE>
- ---------------
(1) The effect of the 1994 change in accounting principle (see Note 2) was to
decrease proved property costs by $37,773,087 and accumulated depreciation,
depletion, and amortization by $12,359,908.
Of the $20,652,151 of net unproved property costs (primarily seismic and
lease acquisition costs) at December 31, 1995, being excluded from the
amortizable base, $8,825,568 was incurred in 1995, $6,977,963 was incurred in
1994, $2,018,174 was incurred in 1993, and $2,830,446 was incurred in prior
years. The Company expects it will complete its evaluation of the properties
representing the majority of these costs within the next two to three years.
F-17
<PAGE> 89
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
CAPITAL EXPENDITURES
The following table sets forth capital expenditures related to the
Company's oil and gas operations:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition of proved properties,
including earned interests in limited
partnerships and joint ventures(1)...... $ 3,461,091 $13,078,242 $21,832,157
Lease acquisitions(2)(3)................ 9,742,543 9,905,237 5,388,243
Exploration............................. 2,289,814 4,003,400 2,195,473
Development............................. 23,555,988 5,637,285 3,164,803
----------- ----------- -----------
Total(4)........................ $39,049,436 $32,624,164 $32,580,676
=========== =========== ===========
</TABLE>
- ---------------
(1) There are no earned interests in 1995 or in 1994. Earned interests amounts
included in 1993 are $3,308,623.
(2) Lease acquisitions for 1995, 1994, and 1993 include expenditures of
$2,814,395, $2,973,971, and $1,032,656, respectively, relating to the
Company's initiatives in Russia; 1995, 1994, and 1993 expenditures of
$304,610, $356,136, and $456,681, respectively, relating to initiatives in
Venezuela; and include 1995 expenditures of $202,206 relating to initiatives
in New Zealand.
(3) These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved
oil and gas properties (being amortized) for 1995, 1994, and 1993,
respectively, were $3,895,871, $3,032,315, and $4,198,429.
(4) Includes capitalized general and administrative costs directly associated
with the acquisition, development, and exploration efforts of approximately
$7,100,000, $5,800,000, and $8,300,000 in 1995, 1994, and 1993. In addition,
total includes $1,442,022, $766,572, and $389,352 in 1995, 1994, and 1993,
respectively, of capitalized interest on unproved properties.
RESULTS OF OPERATIONS
The following table sets forth results of the Company's oil and gas
operations:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Oil and gas sales......................... $22,527,892 $19,802,188 $15,535,671
Production costs.......................... (6,826,306) (5,639,630) (4,540,290)
Depreciation, depletion, and
amortization............................ (8,349,324) (7,590,877) (7,067,636)
----------- ----------- -----------
7,352,262 6,571,681 3,927,745
Income taxes.............................. (2,110,099) (1,511,487) (1,025,141)
----------- ----------- -----------
Results of producing activities........... $ 5,242,163 $ 5,060,194 $ 2,902,604
=========== =========== ===========
Amortization per physical unit of
production (equivalent Mcf of gas)...... $ 0.75 $ 0.79 $ 0.96
=========== =========== ===========
</TABLE>
PROPERTY PURCHASE AND PRODUCTION PAYMENT AGREEMENT
In May 1992, the Company purchased from a subsidiary of Manville
Corporation ("Manville") additional interests in certain wells in McMullen
County, Texas, in which the Company had owned
F-18
<PAGE> 90
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
interests for over three years. The funds for this purchase were provided by the
Company's sale of a volumetric production payment in the Manville properties to
Enron Reserve Acquisition Corp. ("Enron") for net proceeds of $13,790,000. These
proceeds were recorded as deferred revenues and are amortized as the required
deliveries are made. Under the production payment agreement, the Company
continues to own the properties purchased from Manville, but is required to
deliver to Enron approximately 9.5 Bcf over an eight-year period, or for such
longer period as is necessary to deliver a specified heating equivalent quantity
at an average price of $1.115 per MMBtu. The Company is responsible for all
production related costs associated with operating these properties. The amount
to be delivered varies from month to month in generally decreasing quantities.
To the extent monthly gas production from the properties exceeds the agreed upon
deliverable quantities (as it has in every year since the purchase date), the
Company receives all proceeds from sale of such excess gas at current market
prices, plus the proceeds from sale of oil or condensate. Since entering into
the volumetric production payment, the Company has met all scheduled deliveries
to Enron under this agreement.
FOREIGN ACTIVITIES
Russia
On September 3, 1993, the Company signed a Participation Agreement with
Senega, a Russian Federation joint stock company (in which the Company has an
indirect interest of less than 1%), to assist in the development and production
of reserves from two fields in Western Siberia, providing the Company with a
minimum 5% net profits interest from the sale of hydrocarbon products from the
fields for providing managerial, technical, and financial support to Senega.
Additionally, the Company purchased a 1% net profits interest from Senega for
$300,000. In May 1995, the Company executed a Management Agreement with Senega,
under which, in return for undertaking to obtain financing for development of
these fields, Swift is entitled to receive a 49% interest in production income
derived by Senega from this project after repayment of costs. At December 31,
1995 and September 30, 1996, respectively, the Company's investment in Russia
was approximately $6,820,000 and $9,220,000 and is included in the unproved
properties portion of oil and gas properties.
On July 12, 1996, the Company entered into a partnership agreement which
provides for the Company to contribute its rights under the Participation and
Management Agreement to the partnership and for the partners to share equally
revenues and costs of developing the Samburg Field and funding and management of
the license areas, all in conjunction with Senega. The partnership is to be
funded by the partners upon fulfillment of certain conditions and completion of
certain further arrangements with Senega. It is currently anticipated that these
activities would be funded principally through project financing.
Venezuela
The Company formed a wholly-owned subsidiary, Swift Energy de Venezuela,
C.A., for the purpose of submitting a bid on August 5, 1993, under the
Venezuelan Marginal Oil Field Reactivation Program. The Company did not win the
bid; however, other fields and opportunities are continuing to be evaluated in
Venezuela. At December 31, 1995 and September 30, 1996, respectively, the
Company's investment in Venezuela was approximately $1,120,000 and $1,390,000
and is included in the unproved properties portion of oil and gas properties net
of impairments of $45,668.
F-19
<PAGE> 91
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
New Zealand
Since October 1995, the Company has been issued two Petroleum Exploration
Permits by the New Zealand Minister of Energy. The first permit covers
approximately 65,000 acres in the Onshore Taranaki Basin region in the
Southwestern area of New Zealand's North Island, and the second covers
approximately 71,500 adjacent acres. Under the terms of the permits, the Company
is obligated to analyze and interpret certain seismic data, acquire certain new
seismic data, drill one exploratory well, followed by a further development well
or perform additional seismic work, all of which is to be performed on a staged
basis in order to maintain the permits, over periods extending through July 2000
in the case of the first permit, and July 2001 for the second permit. At
December 31, 1995 and September 30, 1996, the Company's investment in New
Zealand was approximately $200,000 and $565,000, respectively, and is included
in the unproved properties portion of oil and gas properties.
ACQUISITION OF PROPERTIES BY SWIFT
During the second quarter of 1994, the Company acquired approximately
$18,100,000 of producing oil and gas properties in a single acquisition
transaction. Approximately $3,500,000 and $12,700,000 of the properties were
transferred to affiliated partnerships formed under the Company's SDI offering
in 1995 and 1994, respectively. Approximately $1,900,000 of the properties were
retained by the Company for its own account.
SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The following information presents estimates of the Company's proved oil
and gas reserves, which are all located onshore in the United States. All of the
Company's reserves were determined by company personnel and audited by H. J.
Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy's
summary report dated February 19, 1996, is set forth as an exhibit to the Form
10-K Report for the year ended December 31, 1995, and includes definitions and
assumptions that served as the basis for the estimates of proved reserves and
future net cash
F-20
<PAGE> 92
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
flows. Such definitions and assumptions should be referred to in connection with
the following information:
ESTIMATES OF PROVED RESERVES
<TABLE>
<CAPTION>
OIL AND
NATURAL GAS CONDENSATE
(MCF) (BBLS)
----------- ----------
<S> <C> <C>
Proved reserves as of December 31, 1992(1)............... 41,638,100 2,901,621
Revisions of previous estimates(2)..................... (1,800,178) (200,906)
Purchases of minerals in place......................... 17,892,709 1,429,463
Sales of minerals in place............................. (61,996) (12,555)
Extensions, discoveries, and other additions........... 10,634,805 477,932
Production(3).......................................... (3,840,635) (324,486)
----------- ---------
Proved reserves as of December 31, 1993(1)............... 64,462,805 4,271,069
Revisions of previous estimates(2)..................... (10,570,138) (714,246)
Purchases of minerals in place......................... 8,136,270 790,523
Sales of minerals in place............................. (881,770) (34,834)
Extensions, discoveries, and other additions........... 20,556,953 707,811
Production(3).......................................... (5,440,156) (467,056)
----------- ---------
Proved reserves as of December 31, 1994(1)............... 76,263,964 4,553,267
Revisions of previous estimates(2)..................... 6,982,317 (421,901)
Purchases of minerals in place......................... 4,166,922 254,211
Sales of minerals in place............................. (13,215) (10,617)
Extensions, discoveries, and other additions........... 62,870,240 1,592,456
Production(3).......................................... (6,702,708) (545,435)
----------- ---------
Proved reserves as of December 31, 1995(1)............... 143,567,520 5,421,981
=========== =========
Proved developed reserves,
December 31, 1992...................................... 32,955,080 2,082,885
December 31, 1993...................................... 50,936,942 3,110,505
December 31, 1994...................................... 46,406,448 3,209,387
December 31, 1995...................................... 81,532,025 3,313,226
</TABLE>
- ---------------
(1) Proved reserves for these periods exclude quantities subject to the
Company's volumetric production payment agreement.
(2) Revisions of previous quantity estimates are related to upward or downward
variations based on current engineering information for production rates,
volumetrics, and reservoir pressure. Additionally, changes in quantity
estimates are affected by the increase or decrease in crude oil and natural
gas prices at each year end. Proved reserves as of December 31, 1995, were
based upon prices of $2.41 per Mcf of natural gas and $18.07 per barrel of
oil, compared to $1.85 per Mcf and $15.09 per barrel as of December 31,
1994.
(3) Natural gas production for 1993, 1994, and 1995 excludes 1,581,206,
1,358,375, and 1,211,255 Mcf, respectively, delivered under the Company's
volumetric production payment agreement.
F-21
<PAGE> 93
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1995 1994 1993
------------- ------------ ------------
<S> <C> <C> <C>
Future gross revenues................... $ 445,572,715 $211,210,430 $218,321,639
Future production and development
costs................................. (163,925,771) (92,053,163) (75,769,590)
------------- ------------ ------------
Future net cash flows before income
taxes................................. 281,646,944 119,157,267 142,552,049
Future income taxes..................... (55,469,213) (14,143,796) (26,303,502)
------------- ------------ ------------
Future net cash flows after income
taxes................................. 226,177,731 105,013,471 116,248,547
Discount at 10% per annum............... (97,273,647) (38,541,504) (41,280,376)
------------- ------------ ------------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves........... $ 128,904,084 $ 66,471,967 $ 74,968,171
============= ============ ============
</TABLE>
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end
economic conditions.
2. The estimated future gross revenues of proved reserves are priced
on the basis of year-end prices, except in those instances where fixed and
determinable gas price escalations are covered by contracts, limited to the
price the Company reasonably expects to receive.
3. The future gross revenue streams are reduced by estimated future
costs to develop and to produce the proved reserves, as well as certain
abandonment costs based on year-end cost estimates and the estimated effect
of future income taxes.
4. Future income taxes are computed by applying the statutory tax rate
to future net cash flows reduced by the tax basis of the properties, the
estimated permanent differences applicable to future oil and gas producing
activities and tax carryforwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices. Under Securities and Exchange Commission rules,
companies that follow the full-cost accounting method are required to make
quarterly Ceiling Limitation calculations, using prices in effect as of the
period end date presented (see Note 1). Application of these rules during
periods of relatively low oil and gas prices, even if of short-term seasonal
duration, may result in write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of the Company's oil and gas property
reserves. An estimate of fair value would also take into account, among other
things, the recovery of reserves in excess of proved reserves, anticipated
future changes in prices and costs, an allowance for return on investment, and
the risks inherent in reserve estimates.
F-22
<PAGE> 94
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1995 1994 1993
------------ ------------ -----------
<S> <C> <C> <C>
Beginning balance....................... $ 66,471,967 $ 74,968,171 $46,582,994
------------- ------------ ------------
Revisions to reserves proved in prior
years --
Net changes in prices, production
costs, and future development
costs.............................. 25,415,116 (21,326,677) (4,140,177)
Net changes due to revisions in
quantity estimates................. 4,735,186 (11,644,586) (2,860,642)
Accretion of discount................. 6,939,460 8,376,078 5,543,984
Other................................. (10,981,721) (5,631,646) (4,485,723)
------------- ------------ ------------
Total revisions......................... 26,108,041 (30,226,831) (5,942,558)
New field discoveries and extensions,
net of future production and
development costs..................... 44,292,042 15,585,767 13,972,435
Purchases of minerals in place.......... 4,928,563 7,964,821 27,074,564
Sales of minerals in place.............. (74,858) (574,651) (85,174)
Sales of oil and gas produced, net of
production costs...................... (13,913,612) (12,168,695) (8,691,301)
Previously estimated development costs
incurred.............................. 16,303,629 5,053,417 1,992,967
Net change in income taxes.............. (15,211,688) 5,869,968 64,244
------------- ------------ ------------
Net change in standardized measure of
discounted future net cash flows...... 62,432,117 (8,496,204) 28,385,177
------------- ------------ ------------
Ending balance.......................... $128,904,084 $ 66,471,967 $74,968,171
============= ============ ============
</TABLE>
F-23
<PAGE> 95
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
10. QUARTERLY RESULTS (UNAUDITED)
The following table presents summarized quarterly financial information for
the years ended December 31, 1993, 1994, and 1995, and the nine months ended
September 30, 1996:
<TABLE>
<CAPTION>
FULLY
INCOME PRIMARY DILUTED
BEFORE NET INCOME INCOME INCOME
INCOME (LOSS) (LOSS) PER (LOSS) PER
REVENUES TAXES (AS RESTATED) SHARE(2) SHARE(2)
----------- ----------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
1993
First Quarter.................... $ 5,325,054 $ 1,411,809 $ 988,266 $ 0.15 $ 0.15
Second Quarter................... 6,012,174 1,743,606 1,220,524 0.19 0.19
Third Quarter.................... 6,603,605 1,905,880 1,441,549 0.22 0.19
Fourth Quarter................... 6,191,820 1,567,313 1,245,914 0.19 0.17
----------- ----------- ------------ ------ ------
Total.................... $24,132,653 $ 6,628,608 $ 4,896,253 $ 0.74 $ 0.70
=========== =========== ============ ====== ======
1994
First Quarter.................... $ 6,138,535 $ 1,753,003(1) $(15,561,976)(1) $(2.36)(1) $(2.36)(1)
Second Quarter................... 6,106,954(1) 1,462,980(1) 1,076,077 (1) 0.16 (1) 0.15 (1)
Third Quarter.................... 6,962,612 1,439,620(1) 1,130,398 (1) 0.17 (1) 0.16 (1)
Fourth Quarter................... 6,167,191 182,226 308,474 0.05 0.05
----------- ----------- ------------ ------ ------
Total.................... $25,375,292 $ 4,837,829 $(13,047,027) $(1.96) $(1.96)
=========== =========== ============ ====== ======
1995
First Quarter.................... $ 6,258,588 $ 676,434 $ 524,600 (2) $ 0.08 $ 0.08
Second Quarter................... 6,564,910 965,448 731,275 0.11 0.11
Third Quarter.................... 7,048,934 1,737,763 1,264,556 0.12 0.12
Fourth Quarter................... 9,058,613 3,514,892 2,392,081 0.19 0.16
----------- ----------- ------------ ------ ------
Total.................... $28,931,045 $ 6,894,537 $ 4,912,512 $ 0.54 $ 0.54
=========== =========== ============ ====== ======
1996 (unaudited)
First Quarter.................... $11,188,847 $ 4,561,523 $ 3,082,381 $ 0.25 $ 0.22
Second Quarter................... 12,557,891 5,480,944 3,678,316 0.29 0.25
Third Quarter.................... 15,432,193 7,178,573 4,641,953 0.33 0.31
----------- ----------- ------------ ------ ------
Total.................... $39,178,931 $17,221,040 $ 11,402,650 $ 0.87 $ 0.87
=========== =========== ============ ====== ======
</TABLE>
- ---------------
(1) In the fourth quarter of 1994, the Company changed its revenue recognition
policy for earned interests. See Note 2 "Change in Accounting Principle" for
further discussion. This change was effective beginning January 1, 1994,
and, accordingly, the cumulative effect of this change ($(16,772,698) or
$(2.52) per share) has been reflected in the first quarter of 1994, and the
first three quarters have been restated to reflect the basis of the newly
adopted accounting principle. Net Income, Primary Income Per Share, and
Fully Diluted Income Per Share were previously reported as $814,325, $0.14,
and $0.14, respectively, for the first quarter of 1994; $1,140,197, $0.19,
and $0.17, respectively, for the second quarter of 1994; and $768,161,
$0.12, and $0.12, respectively, for the third quarter of 1994.
(2) Amounts prior to the fourth quarter of 1994 have been retroactively restated
to give recognition to an equivalent change in capital structure as a result
of the 10% stock dividend. See Note 1 "Summary of Significant Accounting
Policies -- Income (Loss) Per Share" for further discussion.
F-24
<PAGE> 96
SWIFT ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
Pro forma amounts assuming the new earned interest recognition policy is
applied retroactively:
<TABLE>
<CAPTION>
FULLY DILUTED
PRIMARY INCOME INCOME
NET INCOME PER SHARE PER SHARE
---------- -------------- -------------
<S> <C> <C> <C>
1993
First Quarter............................. $ 917,895 $0.14 $0.14
Second Quarter............................ 1,247,263 0.19 0.19
Third Quarter............................. 1,113,049 0.17 0.15
Fourth Quarter............................ 1,044,271 0.16 0.15
---------- ----- -----
Total........................... $4,322,478 $0.66 $0.63
========== ===== =====
1994
First Quarter............................. $1,210,722 $0.18 $0.17
Second Quarter............................ 1,076,077 0.16 0.15
Third Quarter............................. 1,130,398 0.17 0.16
Fourth Quarter............................ 308,474 0.05 0.05
---------- ----- -----
Total........................... $3,725,671 $0.56 $0.56
========== ===== =====
</TABLE>
F-25
<PAGE> 97
NO DEALER, SALESPERSON, OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS, OTHER THAN THOSE CONTAINED OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS, IN CONJUNCTION WITH THE OFFER
CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR
REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY
OR ANY UNDERWRITERS. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER AND THEREUNDER SHALL UNDER ANY CIRCUMSTANCES CREATE AN IMPLICATION
THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE
HEREOF. THIS PROSPECTUS IS NOT AN OFFER TO SELL OR A SOLICITATION OF AN OFFER
TO BUY ANY SECURITY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO
MAKE SUCH OFFER OR SOLICITATION.
------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Available Information.................. 2
Defined Terms.......................... 2
Prospectus Summary..................... 3
Risk Factors........................... 11
Use of Proceeds........................ 17
Price Range of Common Stock and
Dividend Policy...................... 18
Capitalization......................... 19
Selected Consolidated Financial Data... 20
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... 22
Business and Properties................ 29
Management............................. 44
Principal Shareholders................. 46
Description of Notes................... 48
Description of Capital Stock........... 60
Certain United States Tax
Considerations....................... 62
Underwriting........................... 70
Legal Matters.......................... 71
Experts................................ 71
Incorporation of Certain Information by
Reference............................ 71
Index to Consolidated Financial
Statements........................... F-1
</TABLE>
$100,000,000
SWIFT
ENERGY
COMPANY
6 1/4% CONVERTIBLE SUBORDINATED
NOTES DUE 2006
[SWIFT ENERGY LOGO]
SALOMON BROTHERS INC
OPPENHEIMER & CO., INC.
PRUDENTIAL SECURITIES INCORPORATED
SOUTHCOAST CAPITAL
CORPORATION
PROSPECTUS
DATED NOVEMBER 19, 1996
