<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-20257
[LOMAK PETROLEUM LOGO]
PROSPECTUS
4,000,000 Shares
LOMAK PETROLEUM LOGO
COMMON STOCK
------------------------
ALL OF THE SHARES OF COMMON STOCK OFFERED HEREBY (THE "SHARES") ARE BEING SOLD
BY LOMAK PETROLEUM, INC. ("LOMAK" OR THE "COMPANY"). THE COMPANY'S COMMON
STOCK IS LISTED ON THE NEW YORK STOCK EXCHANGE UNDER THE SYMBOL "LOM." ON
MARCH 10, 1997, THE REPORTED LAST SALE PRICE OF THE COMMON STOCK ON THE
NEW YORK STOCK EXCHANGE WAS $17 1/8 PER SHARE. SEE "PRICE RANGE OF
COMMON STOCK AND DIVIDEND POLICY."
THE OFFERING OF THE SHARES (THE "COMMON STOCK OFFERING") IS BEING CONDUCTED
CONCURRENTLY WITH AN OFFERING (THE "NOTES OFFERING") OF $125,000,000 AGGREGATE
PRINCIPAL AMOUNT OF 8.75% SENIOR SUBORDINATED NOTES DUE 2007 (THE "NOTES") OF
THE COMPANY. THE PROCEEDS OF THE COMMON STOCK OFFERING AND THE NOTES
OFFERING (COLLECTIVELY, THE "OFFERINGS") WILL BE USED TO REPAY CERTAIN
INDEBTEDNESS INCURRED TO FUND A PORTION OF THE PURCHASE PRICE OF THE
COMETRA ACQUISITION DESCRIBED HEREIN. THE CLOSINGS OF THE COMMON
STOCK OFFERING AND THE NOTES OFFERING ARE CONTINGENT UPON EACH
OTHER.
------------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 10 HEREOF FOR INFORMATION THAT SHOULD BE
CONSIDERED BY PROSPECTIVE INVESTORS.
------------------------
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. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
------------------------
PRICE $17 A SHARE
------------------------
<TABLE>
<S> <C> <C> <C>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS(1) COMPANY(2)
--------------------- --------------------- ---------------------
Per Share......................... $17.00 $.85 $16.15
Total(3).......................... $68,000,000 $3,400,000 $64,600,000
</TABLE>
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(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."
(2) Before deducting expenses payable by the Company estimated at $500,000.
(3) The Company has granted to the Underwriters an option, exercisable within
30 days of the date hereof, to purchase up to an aggregate of 600,000
additional Shares of Common Stock at the price to public less
underwriting discounts and commissions, for the purpose of covering
over-allotments, if any. If the Underwriters exercise such option in
full, the total price to public, underwriting discounts and commissions
and proceeds to Company will be $78,200,000, $3,910,000 and $74,290,000,
respectively. See "Underwriting."
------------------------
The Shares are offered, subject to prior sale, when, as and if accepted by
the Underwriters named herein and subject to approval of certain legal matters
by Simpson Thacher & Bartlett, counsel for the Underwriters. It is expected that
delivery of the Shares will be made on or about March 14, 1997, at the office of
Morgan Stanley & Co. Incorporated, New York, New York, against payment therefor
in immediately available funds.
------------------------
MORGAN STANLEY & CO.
Incorporated
PAINEWEBBER INCORPORATED
SMITH BARNEY INC.
A.G. EDWARDS & SONS, INC.
MCDONALD & COMPANY
Securities, Inc.
March 10, 1997
<PAGE> 2
[MAP]
------------------------
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK.
SPECIFICALLY, THE UNDERWRITERS MAY OVERALLOT IN CONNECTION WITH THE COMMON STOCK
OFFERING, AND MAY BID FOR AND PURCHASE, SHARES OF THE COMMON STOCK IN THE OPEN
MARKET. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING."
<PAGE> 3
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN THIS PROSPECTUS IN
CONNECTION WITH THE OFFER CONTAINED HEREIN AND, IF GIVEN OR MADE, SUCH OTHER
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 SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION
THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE
HEREOF OR SINCE THE DATES AS OF WHICH INFORMATION IS SET FORTH HEREIN. THIS
PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO
BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO
WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION.
------------------------------------
TABLE OF CONTENTS
<TABLE>
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PAGE
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<S> <C>
Available Information....................................... 4
Incorporation of Certain Information by Reference........... 4
Prospectus Summary.......................................... 5
Risk Factors................................................ 10
Forward-Looking Information................................. 16
Cometra Acquisition......................................... 17
Notes Offering.............................................. 18
Use of Proceeds............................................. 18
Capitalization.............................................. 19
Price Range of Common Stock and Dividend Policy............. 20
Unaudited Pro Forma Consolidated Financial Statements....... 21
Selected Consolidated Financial Data........................ 25
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 26
Business.................................................... 31
Management.................................................. 41
Principal Stockholders and Share Ownership of Management.... 44
Description of Capital Stock and Indebtedness............... 45
Underwriting................................................ 48
Legal Matters............................................... 49
Experts..................................................... 49
Glossary.................................................... 50
Index to Financial Statements............................... F-1
</TABLE>
3
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AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended ("Exchange Act"), and in accordance therewith
files reports, proxy statements and other information with the Securities and
Exchange Commission (the "Commission"). Such reports, proxy statements and other
information filed by the Company can be inspected and copied at the public
reference facilities of the Commission, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington, D.C. 20549, as well as the following regional offices: 7 World Trade
Center, Suite 1300, New York, New York 10048; and Citicorp Center, 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661-2511. Copies can be obtained
by mail at prescribed rates. Requests for copies should be directed to the
Commission's Public Reference Section, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington, D.C. 20549. The Commission also maintains a Website
(http://www.sec.gov) that contains reports, proxy and information statements and
other information regarding registrants that file electronically with the
Commission. In addition, reports, proxy statements and other information
concerning the Company can be inspected and copied at the offices of the New
York Stock Exchange, Inc. (the "NYSE"), 20 Broad Street, New York, New York
10005, on which the Common Stock is listed.
The Company has filed with the Commission a Registration Statement on Form
S-3 (the "Registration Statement") under the Securities Act of 1933, as amended
(the "Securities Act"), with respect to the Common Stock being offered by this
Prospectus and the Notes which are being offered by a separate prospectus. This
Prospectus does not contain all the information set forth in the Registration
Statement and the exhibits thereto. For further information with respect to the
Company and the Common Stock being offered hereby, reference is made to the
Registration Statement and the exhibits thereto. Statements contained in this
Prospectus concerning the provisions of documents filed with the Registration
Statement as exhibits are necessarily summaries of such documents, and each such
statement is qualified in its entirety by reference to the copy of the
applicable document filed with the Commission. All of these documents may be
inspected without charge at the offices of the Commission, the addresses of
which are set forth above, and copies may be obtained therefrom at prescribed
rates.
INCORPORATION OF CERTAIN INFORMATION BY REFERENCE
The following documents and information heretofore filed with the
Commission by the Company are hereby incorporated by reference into this
Prospectus:
1. The Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1995, as amended by Form 10-K/A, dated March 7, 1997.
2. The Company's Quarterly Reports on Form 10-Q for the fiscal quarters
ended March 31, 1996, June 30, 1996 and September 30, 1996.
3. The Company's Current Report on Form 8-K, dated April 19, 1996, as
amended by Form 8-K/A, dated May 31, 1996.
4. The Company's Current Report on Form 8-K dated February 26, 1997.
5. The description of the Common Stock contained in the Registration
Statement on Form 8-A declared effective by the Commission on October 8,
1996.
All documents subsequently filed by the Company pursuant to Sections 13(a),
13(c), 14 or 15(d) of the Exchange Act prior to the termination of the Common
Stock Offering 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 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 provide without charge
to each person, including any beneficial owner, to whom a copy of this
Prospectus is delivered, upon the written or oral request of any such person, a
copy of any document described above (other than exhibits). Requests for such
copies should be directed to Lomak Petroleum, Inc., 500 Throckmorton Street,
Fort Worth, Texas 76102, Attn: Corporate Secretary, Telephone No. (817)
870-2601.
4
<PAGE> 5
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information appearing elsewhere, or incorporated by reference, in this
Prospectus. Unless the context otherwise requires all references herein to
"Lomak" or the "Company" include Lomak Petroleum, Inc. and its consolidated
subsidiaries. Certain industry terms are defined in the Glossary. Pro forma
information gives effect to the Cometra Acquisition (as defined herein) and the
related financings (including the Offerings) and certain other acquisitions and
financings consummated in 1996, as described in the notes to the Unaudited Pro
Forma Consolidated Financial Statements. Unless otherwise indicated, the
information set forth herein assumes the Underwriters' over-allotment option
with respect to the Common Stock Offering will not be exercised.
THE COMPANY
Lomak is an independent energy company engaged in oil and gas development,
exploration and acquisition primarily in three core areas: the Midcontinent,
Appalachia and the Gulf Coast. Over the past five years, the Company has
significantly increased its reserves and production through acquisitions and, to
a growing extent, development and exploration of its properties. On a pro forma
basis as of December 31, 1996, the Company had proved reserves of 644 Bcfe with
a Present Value of $974 million. On an Mcfe basis, the reserves were 63%
developed and 77% natural gas, with a reserve life in excess of 13 years.
Properties operated by the Company accounted for 94% of its pro forma Present
Value. The Company also owns over 2,000 miles of gas gathering systems and a gas
processing plant in proximity to its principal gas properties. On a pro forma
basis in 1996, the Company had revenues of $172 million and EBITDA of $105
million.
From 1991 through 1996, the Company has made 63 acquisitions, including the
Cometra Acquisition, for an aggregate purchase price of approximately $635
million and has spent $39 million on development and exploration activities.
These activities have added approximately 719 Bcfe of reserves at an average
cost of $0.76 per Mcfe. As a result, the Company has achieved substantial growth
since 1991.
THE COMETRA ACQUISITION
The Company recently acquired oil and gas properties located in West Texas,
South Texas and the Gulf of Mexico (the "Cometra Properties") from American
Cometra, Inc. ("Cometra") for a purchase price of $385 million (the "Cometra
Acquisition"). The Cometra Acquisition increased the Company's proved reserves
at December 31, 1996 by 68% to 644 Bcfe and increased its Present Value by 98%
to $974 million. The Cometra Properties, located primarily in the Company's core
operating areas, include 515 producing wells, 401 proven development projects
and substantial additional development and exploration potential on
approximately 150,000 gross acres (90,000 net acres). In addition, the Cometra
Properties include 265 miles of gas pipelines, a 25,000 Mcf/d gas processing
plant and an above-market gas contract with a major Texas gas utility covering
approximately 30% of the December 1996 production from the Cometra Properties.
BUSINESS STRATEGY
The Company's objective is to maximize shareholder value through aggressive
growth in its reserves, production, cash flow and earnings through a balanced
program of development drilling and acquisitions, as well as a growing
exploration effort. Management believes that the Cometra Acquisition has
substantially enhanced the Company's ability to increase its production and
reserves through drilling activities. The Cometra Acquisition substantially
increased the Company's inventory of proven drilling locations and, to an even
greater degree, its exploration and exploitation drilling potential. The Company
has over 1,100 proven recompletion and development drilling projects. As a
result of the Cometra Acquisition, the Company believes that it can achieve
significant growth in reserves, production, cash flow and earnings over the next
several years, even if no future acquisitions are consummated. The Company
currently plans to spend $160 million over the next three years on the further
development and exploration of its properties. Consequently, while acquisitions
are expected to continue to play an important role in the Company's future
growth, the primary emphasis will shift towards exploiting the potential of the
Company's larger property base.
5
<PAGE> 6
In order to most effectively implement its operating strategy, the Company
has concentrated its activities in selected geographic areas. In each core area,
the Company has established separate acquisition, engineering, geological,
operating and other technical expertise. The Company believes that this
geographic focus provides it with a competitive advantage in sourcing and
evaluating new business opportunities within these areas, as well as providing
economies of scale in developing and operating properties.
FINANCING THE COMETRA ACQUISITION
The purchase price for the Cometra Acquisition was approximately $385
million, consisting of $355 million in cash and 1,410,106 shares of Common
Stock. The Company financed the cash portion of the purchase price with $221
million of borrowings under a recently expanded bank credit facility (the
"Credit Agreement") and the issuance to Cometra of a $134 million non-interest
bearing promissory note due March 31, 1997, which is secured by a bank letter of
credit. The promissory note will be repaid at maturity through borrowings under
the Credit Agreement. The Credit Agreement permits the Company to obtain
revolving credit loans and issue letters of credit from time to time in an
aggregate amount not to exceed $400 million initially. Availability under the
Credit Agreement will be reduced to $300 million on the earlier of August 13,
1997 or the consummation of the Offerings, unless otherwise agreed to by the
lenders. Upon consummation of the Offerings, approximately $204.5 million will
be outstanding under the Credit Agreement. In connection with the issuance of
the shares of Common Stock to Cometra, Cometra was granted certain registration
rights.
The Company maintains its corporate headquarters at 500 Throckmorton
Street, Fort Worth, Texas 76102 and its telephone number is (817) 870-2601.
6
<PAGE> 7
THE OFFERING
<TABLE>
<S> <C>
Common Stock Offered by the Company........................ 4,000,000 shares
Common Stock Outstanding prior to the Offering............. 16,244,451 shares(1)(2)
Common Stock to be Outstanding after the Offering.......... 20,244,451 shares(1)(2)
Notes Offering............................................. Concurrently with the Common Stock Offering, the
Company is offering $125 million aggregate
principal amount of Notes to the public in the
Notes Offering. The closings of the Common Stock
Offering and the Notes Offering are contingent upon
each other. See "Notes Offering."
Use of Proceeds............................................ The Company will use the proceeds of the Common
Stock Offering and the Notes Offering to repay a
portion of the indebtedness incurred to fund the
purchase price for the Cometra Properties. See "Use
of Proceeds."
NYSE Symbol................................................ "LOM"
</TABLE>
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(1) As of March 5, 1997. Excludes 1,236,032 shares reserved for issuance upon
the exercise of outstanding options and warrants, of which 523,632 are
currently exercisable; 3,026,316 shares issuable upon conversion of the
$2.03 Convertible Exchangeable Preferred Stock, Series C (the "$2.03
Convertible Preferred Stock"); and 2,857,143 shares issuable upon conversion
of the 6% Convertible Subordinated Debentures Due 2007 ("6% Convertible
Subordinated Debentures"). See "Description of Capital Stock and
Indebtedness."
(2) Includes 1,410,106 shares issued to Cometra as partial consideration for the
Cometra Properties.
RISK FACTORS
Prior to making an investment decision, prospective investors should
carefully consider, together with the other information contained in this
Prospectus, the risk factors discussed under the caption "Risk Factors," which
include risks relating to: (i) the volatility of oil and gas prices; (ii) the
uncertainty of estimates of reserves and future net revenues; (iii) the ability
of the Company to find or acquire additional oil and gas reserves that are
economically recoverable; (iv) the ability of the Company to obtain commercial
production through development and exploration activities; (v) the ability of
the Company to successfully integrate the Cometra Acquisition; (vi) the effects
of leverage on the Company's operating activities and ability to obtain
additional financing in the future; and (vii) the availability of capital for
acquisitions and development projects.
7
<PAGE> 8
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The following tables set forth certain (i) historical and pro forma
financial data and (ii) reserve and operating data. The pro forma financial,
operating and reserve information includes the Cometra Acquisition and the
related financings and certain other acquisitions and financings consummated in
1996, as described in the notes to the Unaudited Pro Forma Consolidated
Financial Statements. The historical data should be read in conjunction with the
historical Consolidated Financial Statements and Notes thereto included herein.
See also "Selected Consolidated Financial Data" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations." The pro forma
information should be read in conjunction with the Unaudited Pro Forma
Consolidated Financial Statements included herein. Neither the historical nor
the pro forma results are necessarily indicative of future results.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
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PRO FORMA
1994 1995 1996 1996
-------- -------- -------- -----------
(UNAUDITED)
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STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales......................................... $ 24,461 $ 37,417 $ 68,054 $130,508
Field services............................................ 7,667 10,097 14,223 14,223
Gas transportation and marketing.......................... 2,195 3,284 5,575 24,326
Interest and other........................................ 471 1,317 3,386 3,386
-------- -------- -------- --------
34,794 52,115 91,238 172,443
Expenses:
Direct operating.......................................... 10,019 14,930 24,456 39,394
Field services............................................ 5,778 6,469 10,443 10,443
Gas transportation and marketing.......................... 490 849 1,674 13,152
Exploration............................................... 359 512 1,460 1,460
General and administrative................................ 2,478 2,736 3,966 3,966
Interest.................................................. 2,807 5,584 7,487 30,957
Depletion, depreciation and amortization.................. 10,105 14,863 22,303 44,389
-------- -------- -------- --------
32,036 45,943 71,789 143,761
-------- -------- -------- --------
Income before taxes......................................... 2,758 6,172 19,449 28,682
Income taxes................................................ 139 1,782 6,834 10,038
-------- -------- -------- --------
Net income.................................................. $ 2,619 $ 4,390 $ 12,615 $ 18,644
======== ======== ======== ========
Earnings per common share................................... $ 0.25 $ 0.31 $ 0.69 $ 0.80
======== ======== ======== ========
Cash dividends per common share............................. $ 0.00 $ 0.01 $ 0.06 N/A
======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA (a).................................................. $ 16,029 $ 27,131 $ 50,699 $105,488
Net cash provided by operations............................. 11,241 16,561 38,445 N/A
Net cash used in investing.................................. (29,536) (76,113) (69,666) N/A
Net cash provided by financing.............................. 21,173 57,702 36,799 N/A
Capital expenditures........................................ 70,024 88,530 79,390 N/A
Ratios:
EBITDA to interest expense................................ 5.7x 4.9x 6.8x 3.4x
Earnings to fixed charges (b)............................. 2.0x 2.1x 3.6x 1.9x
Total debt to EBITDA...................................... 3.9x 3.1x 2.3x 3.9x
BALANCE SHEET DATA (END OF PERIOD):
Cash and equivalents........................................ $ 4,897 $ 3,047 $ 8,625 $ 8,625
Total assets................................................ 141,768 214,788 282,547 671,597
Long-term debt (c).......................................... 62,592 83,088 116,806 411,756
Stockholders' equity........................................ 43,248 99,367 117,529 211,629
</TABLE>
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(a) EBITDA represents net income plus income taxes, exploration expense,
interest expense and depletion, depreciation and amortization expense.
EBITDA is not presented as an indicator of the Company's operating
performance, an indicator of cash available for discretionary spending or as
a measure of liquidity. EBITDA may not be comparable to other similarly
titled measures of other companies. The Company's Credit Agreement requires
the maintenance of certain EBITDA ratios. See "Description of Capital Stock
and Indebtedness -- Credit Agreement."
(b) For the purpose of determining the ratio of earnings to fixed charges,
earnings are defined as income before taxes plus fixed charges. Fixed
charges consist of interest expense.
(c) Long-term debt includes current portion.
8
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SUMMARY RESERVE AND OPERATING DATA
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------
PRO FORMA
1994 1995 1996 1996
-------- -------- -------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C>
PROVED RESERVES (A):
Natural gas (Mmcf)........................................ 149,370 232,887 295,594 497,600
Oil and NGLs (Mbbls)...................................... 8,449 10,863 14,675 24,405
Natural gas equivalents (Mmcfe)........................... 200,064 298,065 383,644 644,030
Percent natural gas....................................... 75% 78% 77% 77%
Percent proved developed.................................. 68% 77% 71% 63%
PRODUCTION VOLUMES:
Natural gas (Mmcf)........................................ 6,996 12,471 21,231 38,157
Oil and NGLs (Mbbls)...................................... 640 913 1,068 1,890
Natural gas equivalents (Mmcfe)........................... 10,836 17,949 27,641 49,497
RESERVE LIFE INDEX (YEARS) (B).............................. 18.5 16.6 13.9 13.0
PRODUCT PRICES (AT DECEMBER 31) (A):
Natural gas (per Mcf)..................................... $ 2.07 $ 2.28 $ 3.54 $ 3.99
Oil and NGLs (per Bbl).................................... 16.14 18.14 23.58 23.23
FUTURE NET CASH FLOWS (A):
Undiscounted.............................................. $270,974 $412,638 $941,393 $1,790,768
Present Value............................................. 150,536 229,238 492,172 973,663
RESERVE ADDITIONS (MMCFE):
Acquisitions.............................................. 103,292 106,283 109,326 369,710
Extensions, discoveries and revisions..................... 7,415 10,943 16,543 16,543
-------- -------- -------- ----------
Net additions............................................. 110,707 117,226 125,869 386,253
COSTS INCURRED:
Acquisition............................................... $ 59,501 $ 69,244 $ 63,579 $ 316,579
Development and exploration............................... 9,710 10,184 14,561 14,561
-------- -------- -------- ----------
Total costs incurred...................................... $ 69,211 $ 79,428 $ 78,140 $ 331,140
FINDING COSTS (PER MCFE) (C)................................ $ 0.63 $ 0.68 $ 0.62 $ 0.86
RESERVE REPLACEMENT (D)..................................... 1,022% 653% 455% 1,397%
WELLS DRILLED:
Gross..................................................... 71.0 62.0 63.0 N/A
Net....................................................... 58.2 39.6 51.9 N/A
Success rate (net)........................................ 97% 99% 94% N/A
PER MCFE DATA:
Oil and gas sales......................................... $ 2.26 $ 2.08 $ 2.46 $ 2.64
Direct operating expense (e).............................. 0.75 0.63 0.75 0.71
General and administrative expense........................ 0.23 0.15 0.14 0.08
-------- -------- -------- ----------
Operating margin (f)...................................... $ 1.28 $ 1.30 $ 1.57 $ 1.85
======== ======== ======== ==========
</TABLE>
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(a) Proved reserves and future net cash flows were estimated in accordance with
the Commission's guidelines. Prices and costs at December 31 for each of the
years 1994 through 1996 were used in the calculation of proved reserves and
future net cash flows and were held constant through the periods of
estimated production, except as otherwise provided by contract, in
accordance with the Commission's guidelines.
(b) The reserve life index is calculated as proved reserves (on an Mcfe basis)
divided by annual production.
(c) Finding costs are calculated as costs incurred divided by net reserve
additions. The pro forma cost incurred for 1996 excludes $62 million
attributable to unproved reserves ($0.16 per Mcfe impact). However, the pro
forma cost incurred for 1996 includes the value attributable to an
above-market gas contract of $38 million ($0.10 per Mcfe impact).
(d) Reserve replacement is calculated as net reserve additions divided by the
Company's actual production for the period, both on an Mcfe basis.
(e) Direct operating expense per Mcfe is net of the Company's operating margin
realized on its field service activities. The net operating margin realized
on its field services activities is related primarily to reimbursements that
the Company receives as operator of its properties. The Company intends to
conform its financial statements for periods after December 31, 1996 to this
presentation.
(f) Operating margin is calculated as oil and gas sales less direct operating
expense and general and administrative expense.
9
<PAGE> 10
RISK FACTORS
Prior to making an investment decision, prospective investors should
carefully consider, together with the other information contained in this
Prospectus, the following risk factors:
VOLATILITY OF OIL AND GAS PRICES
The Company's financial condition, operating results and future growth and
the carrying value of its oil and gas properties are substantially dependent on
prevailing prices of, and demand for, oil and gas. The Company's ability to
maintain or increase its borrowing capacity and to obtain additional capital on
attractive terms is also substantially dependent upon oil and gas prices.
Historically the markets for oil and gas have been volatile and are likely to
continue to be volatile in the future. Prices for oil and gas are subject to
large fluctuations in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
beyond the control of the Company. These factors include weather conditions in
the United States and elsewhere, the economic conditions in the United States
and elsewhere, the actions of the Organization of Petroleum Exporting Countries
("OPEC"), governmental regulation, political stability in the Middle East and
elsewhere, the supply and demand of oil and gas, the price of foreign imports
and the availability and prices of alternate fuel sources. Any substantial and
extended decline in the price of oil or gas would have an adverse effect on the
Company's carrying value of its proved reserves, borrowing capacity, the
Company's ability to obtain additional capital, and its financial condition,
revenues, profitability and cash flows from operations.
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the market
for oil and gas producing properties, as buyers and sellers have difficulty
agreeing on such value. Price volatility also makes it difficult to budget for
and project the return on acquisitions and development and exploitation
projects.
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
This Prospectus contains estimates of the Company's oil and gas reserves
and the future net revenues from those reserves which have been prepared by the
Company and certain independent petroleum consultants. Reserve engineering is a
subjective process of estimating the recovery from underground accumulations of
oil and gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and gas reserves and of future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies and
assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. Because all
reserve estimates are to some degree speculative, the quantities of oil and gas
that are ultimately recovered, production and operation costs, the amount and
timing of future development expenditures and future oil and gas sales prices
may all vary from those assumed in these estimates and such variances may be
material. In addition, different reserve engineers may make different estimates
of reserve quantities and cash flows based upon the same available data.
The present value of estimated future net cash flows referred to in this
Prospectus should not be construed as the current market value of the estimated
proved oil and gas reserves attributable to the Company's properties. In
accordance with applicable requirements of the Commission, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower. The calculation of the Present
Value of the Company's oil and gas reserves were based on prices on December 31,
1996. Average product prices at December 31, 1996 were $23.58 per barrel of oil
and $3.54 per Mcf of gas and pro forma average product prices at December 31,
1996 were $23.23 per barrel of oil and $3.99 per Mcf of gas, which prices were
substantially higher than historical prices used by the Company to calculate
Present Value in recent years. The closing price on the New York Mercantile
Exchange ("NYMEX") for the prompt month
10
<PAGE> 11
contract delivered at Henry Hub on December 31, 1996 and February 28, 1997 was
$2.76 and $1.83, respectively. The closing price on NYMEX for the prompt month
contract delivered for Light Crude Oil on December 31, 1996 and February 28,
1997 was $25.92 and $20.30, respectively. In addition, the calculation of the
present value of the future net revenues using a 10% discount as required by the
Commission is not necessarily the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with the
Company's reserves or the oil and gas industry in general. Furthermore, the
Company's reserves may be subject to downward or upward revision based upon
actual production, results of future development, supply and demand for oil and
gas, prevailing oil and gas prices and other factors. See "Business -- Oil and
Gas Reserves."
FINDING AND ACQUIRING ADDITIONAL RESERVES
The Company's future success depends upon its ability to find or acquire
additional oil and gas reserves that are economically recoverable. Except to the
extent the Company conducts successful exploration or development activities or
acquires properties containing proved reserves, the proved reserves of the
Company will generally decline as they are produced. There can be no assurance
that the Company's planned development projects and acquisition activities will
result in significant additional reserves or that the Company will have success
drilling productive wells at economic returns. If prevailing oil and gas prices
were to increase significantly, the Company's finding costs to add new reserves
could increase. The drilling of oil and gas wells involves a high degree of
risk, especially the risk of dry holes or of wells that are not sufficiently
productive to provide an economic return on the capital expended to drill the
wells. The cost of drilling, completing and operating wells is uncertain, and
drilling or production may be curtailed or delayed as a result of many factors.
The Company's business is capital intensive. To maintain its base of proved
oil and gas reserves, a significant amount of cash flow from operations must be
reinvested in property acquisitions, development or exploration activities. To
the extent cash flow from operations is reduced and external sources of capital
become limited or unavailable, the Company's ability to make the necessary
capital investments to maintain or expand its asset base would be impaired.
Without such investment, the Company's oil and gas reserves would decline.
DEVELOPMENT AND EXPLORATION RISKS
The Company intends to increase its development and exploration activities.
Exploration drilling, and to a lesser extent development drilling, 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 uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous 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 -- Development Activities" and " -- Exploration Activities."
ACQUISITION RISKS
The Company intends to continue acquiring oil and gas properties. It
generally is not feasible to review in detail every individual property involved
in an acquisition. Ordinarily, review efforts are focused on the higher-valued
properties. However, even a detailed review of all properties and records may
not reveal existing or potential problems nor will it permit the Company to
become sufficiently familiar with the properties to assess fully their
deficiencies and capabilities. Inspections are not always performed on every
well, and environmental problems, such as groundwater contamination, are not
necessarily observable even when an inspection is undertaken. See
"Business -- Acquisition Activities."
The Cometra Acquisition substantially increased the Company's reserves,
cash flow and production. The Company's ability to achieve any advantages from
the Cometra Acquisition will depend in large part on successfully integrating
the Cometra Properties into the operations of the Company. No assurances can be
made that the Company will be able to achieve such integration successfully.
11
<PAGE> 12
EFFECTS OF LEVERAGE
On a pro forma basis giving effect to the Cometra Acquisition and the
related financings, at December 31, 1996, the Company's outstanding indebtedness
would have been $412 million and the Company's ratio of total debt to total
capitalization would have been 66%. In 1994, 1995, 1996 and on a pro forma basis
for 1996, the Company's ratio of earnings to fixed charges was 2.0x, 2.1x, 3.6x
and 1.9x, respectively. The principal payment obligations of the Company's pro
forma debt for 1997, 1998 and 1999 amount to $26,000, $413,000 and $12,000
respectively. The Company's level of indebtedness will have several important
effects on its future operations, including (i) a substantial portion of the
Company's cash flow from operations must be dedicated to the payment of interest
on its indebtedness and will not be available for other purposes, (ii) covenants
contained in the Company's debt obligations will require the Company to meet
certain financial tests, and other restrictions will limit its ability to borrow
additional funds or to dispose of assets and may affect the Company's
flexibility in planning for, and reacting to, changes in its businesses,
including possible acquisition activities and (iii) the Company's ability to
obtain additional financing in the future for working capital, capital
expenditures, acquisitions, general corporate purposes or other purposes may be
impaired. The Company's ability to meet its debt service obligations and to
reduce its total indebtedness will be dependent upon the Company's future
performance, which will be subject to oil and gas prices, the Company's level of
production, general economic conditions and to financial, business and other
factors affecting the operations of the Company, many of which are beyond its
control. There can be no assurance that the Company's future performance will
not be adversely affected by some or all of these factors. In addition, the
Credit Agreement and the Indenture for the Notes contain restrictions on the
Company's ability to pay dividends on capital stock. Under the most restrictive
of these provisions, the Company could have paid $5,000,000 of dividends as of
December 31, 1996. See "Forward-Looking Information."
CAPITAL AVAILABILITY
The Company's strategy of acquiring and developing oil and gas properties
is dependent upon its ability to obtain financing for such acquisitions and
development projects. The Company expects to utilize the Credit Agreement among
the Company and several banks (the "Banks") to borrow a portion of the funds
required for any given transaction or project. If funds under the Credit
Agreement are not available to fund acquisition and development projects, the
Company would seek to obtain such financing from the sale of equity securities
or other debt financing. There can be no assurance that any such other financing
would be available on terms acceptable to the Company. Should sufficient capital
not be available, the Company may not be able to continue to implement its
strategy.
The Credit Agreement limits the amounts the Company may borrow to amounts,
determined by the Banks, in their sole discretion, based upon a variety of
factors including the discounted present value of the Company's estimated future
net cash flow from oil and gas production (the "Borrowing Base"). At March 5,
1997, the Borrowing Base was $400 million, of which the Company had borrowings
of $389.5 million outstanding (including $134 million of then outstanding
letters of credit to secure the promissory note issued to Cometra as part of the
purchase price in the Cometra Acquisition). The Borrowing Base will be reduced
to $300 million on the earlier of August 13, 1997 or upon consummation of the
Offerings, unless otherwise agreed to by the Banks. If oil or gas prices decline
below their current levels, the availability of funds and the ability to pay
outstanding amounts under the Credit Agreement could be materially adversely
affected. The Indenture for the Notes also contains restrictions on the
Company's ability to incur additional indebtedness, and other contractual
arrangements to which the Company may become subject to in the future could
contain similar restrictions. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS
The oil and gas business involves a variety of operating risks, including,
but not limited to, unexpected formations or pressures, uncontrollable flows of
oil, gas, brine or well fluids into the environment (including groundwater
contamination), blowouts, cratering, fires, explosions, pipeline ruptures or
spills, pollution and other risks, any of which could result in personal
injuries, loss of life, damage to properties, environmental pollution,
suspension of operations and substantial losses. Although the Company carries
insurance which it
12
<PAGE> 13
believes is reasonable, it is not fully insured against all risks. The Company
does not carry business interruption insurance. Losses and liabilities arising
from uninsured or under-insured events could have a material adverse effect on
the financial condition and results of operations of the Company.
From time to time, due primarily to contract terms, pipeline interruptions
or weather conditions, the producing wells in which the Company owns an interest
have been subject to production curtailments. The curtailments vary from a few
days to several months. In most cases the Company is provided only limited
notice as to when production will be curtailed and the duration of such
curtailments. The Company is currently not curtailed on any of its production.
Certain of the Cometra Properties are offshore operations in the Gulf of
Mexico which are subject to a variety of operating risks peculiar to the marine
environment, such as hurricanes or other adverse weather conditions, more
extensive governmental regulation, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to interruption
or termination of operations by governmental authorities based on environmental
or other considerations.
HEDGING RISKS
From time to time, the Company hedges a portion of its physical oil and
natural gas production by entering short positions through fixed price swaps or
options. The Company does not generally trade directly utilizing NYMEX futures.
The Company currently has one oil fixed price swap relating to 80,000 Bbls in
each of January, February and March 1997 and 60,000 Bbls in April 1997. The
settlement is determined by the difference between the Company's fixed price and
the average of the daily prompt NYMEX WTI contract during each corresponding
month. The Company had one fixed price natural gas swap during January 1997
relating to 155,000 MmBtu. As of March 5, 1997, there are no other hedge
positions.
The Company's Vice-President -- Gas Management has the responsibility for
implementing approved hedge strategies. The hedge program provides for oversight
and reporting requirements, hedge goals and how strategies will be developed.
The above described hedges represent approximately 12% of the Company's
combined oil and gas production through April 1997, and there are none
thereafter. The production that is hedged represents 51% of the Company's oil
production and 1% of the Company's gas production through April 1997. None of
the production sold pursuant to fixed price gas sales contracts is hedged.
These hedges have in the past involved fixed price arrangements and other
price arrangements at a variety of prices, floors and caps. The Company may in
the future enter into oil and natural gas futures contracts, options and swaps.
The Company's hedging activities, while intended to reduce the Company's
sensitivity to changes in market prices of oil and gas, are subject to a number
of risks including instances in which (i) production is less than expected, (ii)
there is a widening of price differentials between delivery points required by
fixed price delivery contracts to the extent they differ from those of the
Company's production or (iii) the Company's customers or the counterparties to
its futures contracts fail to purchase or deliver the contracted quantities of
oil or natural gas. Additionally, the fixed price sales and hedging contracts
limit the benefits the Company will realize if actual prices rise above the
contract prices. In the future, the Company may increase the percentage of its
production covered by hedging arrangements.
GAS CONTRACT RISK
A significant portion of the Company's production is subject to fixed price
contracts. On a pro forma basis, approximately 47% of average gas production for
December 1996 was sold subject to fixed price sales contracts (including a
contract relating to the Cometra Properties described below and excluding the
hedging activities described above). These fixed price contracts are at prices
ranging from $2.15 to $3.70 per Mcf. The fixed price contracts with terms of
less than one year, between one and five years and greater than five years
constitute approximately 31%, 65% and 4%, respectively, of the volume sold under
fixed price contracts. The fixed price sales contracts limit the benefits the
Company will realize if actual prices rise above the contract prices.
13
<PAGE> 14
As part of the Cometra Acquisition, the Company acquired a gas sales
contract covering 20,000 acres currently producing approximately 20,000 Mcf/d.
The price paid pursuant to the contract was $3.70 per Mcf at December 31, 1996
(65% higher than average 1996 natural gas prices received by the Company) and
escalates at $0.05 per Mcf per annum. The contract is with a large gas utility
and expires in June 2000. This contract represents 15% of the Company's pro
forma December 1996 production on an Mcfe basis.
The gas contract contains language that requires the purchaser to purchase
all of the gas legally produced on the designated acreage. The contract also
contains language that may be read to provide that the purchaser is not required
to purchase more than 80% of the Company's delivery capacity (up to a delivery
capacity of 20,000 Mcf/d). However, since the commencement of the contract in
1990 through the date hereof, the purchaser has purchased all of the gas
produced on the designated acreage.
The Company believes that these fixed price contracts are enforceable and
it has not received any notice or other indication from any of the
counterparties that they intend to cease performing any of their obligations
under these contracts. However, there can be no assurance that one or more of
these counterparties will not attempt to totally or partially mitigate their
obligations under these contracts. If any of the purchasers under the contracts
should be successful in doing so, then the Company could be required to market
its production on less attractive terms, which could have a material adverse
effect on the Company's financial condition, results of operations and cash
flow.
GAS GATHERING, PROCESSING AND MARKETING
The Company's gas gathering, processing and marketing operations depend in
large part on the ability of the Company to contract with third party producers
to produce their gas, to obtain sufficient volumes of committed natural gas
reserves, to maintain throughput in the Company's processing plant at optimal
levels, to replace production from declining wells, to assess and respond to
changing market conditions in negotiating gas purchase and sale agreements and
to obtain satisfactory margins between the purchase price of its natural gas
supply and the sales price for such residual gas volumes and the natural gas
liquids processed. In addition, the Company's operations are subject to changes
in regulations relating to gathering and marketing of oil and gas. The inability
of the Company to attract new sources of third party natural gas or to promptly
respond to changing market conditions or regulations in connection with its
gathering, processing and marketing operations could materially adversely affect
the Company's financial condition and results of operations.
LAWS AND REGULATIONS
The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering, marketing,
transportation and storage of oil and gas. These regulations, among other
things, control the rate of oil and gas production, and control the amount of
oil that may be imported. The Company's operations are subject to numerous laws
and regulations governing plugging and abandonment, the discharge of materials
into the environment or otherwise relating to environmental protection. These
laws and regulations require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit drilling activities on certain
lands lying within wilderness, wetlands and other protected areas, and impose
substantial liabilities for pollution which might result from the Company's
operations. The Company may also be subject to substantial clean-up costs for
any toxic or hazardous substance that may exist under any of its properties.
Moreover, the recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation has
been proposed in Congress from time to time that would reclassify certain crude
oil and natural gas exploration and production wastes as "hazardous wastes"
which would make the reclassified wastes subject to much more stringent
handling, disposal and clean-up requirements. If such legislation were to be
enacted, it could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. Initiatives to further
regulate the disposal of crude oil and natural gas wastes are also pending in
certain states, and these various initiatives could have a similar impact on the
Company. The Company could incur substantial costs to comply with environmental
laws and regulations.
14
<PAGE> 15
COMPETITION
The Company encounters substantial competition in acquiring properties,
marketing oil and gas, securing equipment and personnel and operating its
properties. The competitors in acquisitions, development, exploration and
production include major oil companies, numerous independent oil and gas
companies, individual proprietors and others. Many of these competitors have
financial and other resources which substantially exceed those of the Company
and have been engaged in the energy business for a much longer time than the
Company. Therefore, competitors may be able to pay more for desirable leases and
to evaluate, bid for and purchase a greater number of properties or prospects
than the financial or personnel resources of the Company will permit.
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, including John H. Pinkerton, the Company's
President and Chief Executive Officer. However, the Company does not have
employment contracts with any of its officers or key employees. 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. The Company does not maintain key
man life insurance on any of its officers or key employees. See "Management."
CERTAIN BUSINESS INTERESTS OF CHAIRMAN
Thomas J. Edelman, Chairman of the Company, is also the Chairman, President
and Chief Executive Officer of Patina Oil & Gas Company ("Patina"), a publicly
traded oil and gas company. The Company currently has no existing business
relationships with Patina, and Patina does not own any of the Company's
securities. However, as a result of Mr. Edelman's position in Patina, conflicts
of interests may arise between them. The Company has board policies that require
Mr. Edelman to give notification of any potential conflicts that may arise
between the Company and Patina. There can be no assurance, however, that the
Company will not compete with Patina for the same acquisition or encounter other
conflicts of interest. See "Management."
DILUTION
Upon consummation of the Common Stock Offering, holders of shares of Common
Stock will experience dilution in the Company's earnings per share on a pro
forma basis. As a result of the Offerings, the Company's pro forma earnings per
share will decrease to $0.80 for 1996 after giving effect to the Cometra
Acquisition and the Offerings, as compared to $0.97 for 1996 after giving effect
to the Cometra Acquisition but not the Offerings. See Unaudited Pro Forma
Consolidated Financial Statements.
SHARES ELIGIBLE FOR FUTURE SALE
Sales of substantial amounts of Common Stock in the public market
subsequent to the Common Stock Offering could adversely affect the market price
of the Common Stock. Upon consummation of the Offerings, the Company will have
20,244,451 shares of Common Stock outstanding (20,844,451 shares if the
Underwriters overallotment option is exercised in full). Of these shares,
20,034,951 shares will be eligible for immediate sale without restriction under
the Securities Act (except for shares held by affiliates of the Company whose
shares may be sold subject to volume limitations and certain other requirements
of Rule 144 under the Securities Act), and 209,500 are restricted securities
that may not be resold unless such resale is registered under the Securities Act
or is made under Rule 144 or another exemption from registration under the
Securities Act. The holders of 1,703,617 shares of Common Stock have agreed not
to sell such shares for a period of 90 days after the date of this Prospectus
without the prior written consent of Morgan Stanley & Co. Incorporated. Cometra
has agreed not to sell the 1,410,106 shares it received pursuant to the Cometra
Acquisition until 45 days after the date of this Prospectus. In addition to the
shares currently outstanding,
15
<PAGE> 16
1,236,032 shares are reserved for issuance upon exercise of outstanding options
and warrants, 3,026,316 shares are issuable upon conversion of the $2.03
Convertible Preferred Stock and 2,857,143 shares are issuable upon conversion of
the 6% Convertible Subordinated Debentures.
FORWARD-LOOKING INFORMATION
Information included in this Prospectus, including information incorporated
by reference herein, contains forward-looking statements within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act, including
projections, estimates and expectations. Those statements by their nature are
subject to certain risks, uncertainties and assumptions and will be influenced
by various factors. Should one or more of these statements or their underlying
assumptions prove to be incorrect, actual results could vary materially.
Although the Company believes that such projections, estimates and expectations
are based on reasonable assumptions, it can give no assurance that such
projections, estimates and expectations will be achieved. Important factors that
could cause actual results to differ materially from those in the
forward-looking statements herein include political and economic developments in
the United States and foreign countries, federal and state regulatory
developments, the timing and extent of changes in commodity prices, the extent
of success in acquiring oil and gas properties and in discovering, developing
and producing reserves and conditions of the capital markets and equity markets
during the periods covered by the forward-looking statements. See "Risk Factors"
for further information with respect to certain of such factors. In addition,
certain of such projections and expectations are based on historical results,
which may not be indicative of future performance. See "Unaudited Pro Forma
Consolidated Financial Statements."
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<PAGE> 17
COMETRA ACQUISITION
GENERAL
The Company recently acquired the Cometra Properties for a purchase price
of $385 million, consisting of $355 million in cash and 1,410,106 shares of
Common Stock. The Company financed the cash portion of the purchase price with
$221 million of borrowings under the Credit Agreement and the issuance to
Cometra of a $134 million non-interest bearing promissory note due March 31,
1997, which is secured by a bank letter of credit. As a result of the Cometra
Acquisition, the Company has significantly expanded its inventory of both
development and exploration projects, increased its proved reserves at December
31, 1996 by 68% to 644 Bcfe and increased the Company's Present Value at
December 31, 1996 by 98% to $974 million.
COMETRA PROPERTIES
The Cometra Properties include 150,000 gross acres (90,000 net) located
within the Company's core operating areas in West Texas, South Texas and the
Gulf of Mexico. Netherland, Sewell & Associates, Inc., independent petroleum
consultants, estimated that at December 31, 1996, the Cometra Properties had
proved reserves of 202 Bcf of gas and 9.7 Mmbbls of oil with a Present Value of
$481 million. In December 1996, the Cometra Properties produced at a rate of 66
Mmcfe/d through 515 wells. The Cometra Properties include 265 miles of gas
pipelines and a 25,000 Mcf/d capacity gas processing plant.
The West Texas properties are located in the Val Verde and Permian Basins
and account for 81% of the acquired reserves on a Present Value basis. The South
Texas/Gulf of Mexico properties account for 19% of the acquired reserves on a
Present Value basis. All of the Cometra Properties, except for the Gulf of
Mexico properties, are within the Company's existing core operating areas. As a
result, the Company expects to be able to quickly integrate the properties and
begin exploitation activities. To facilitate the integration, the Company plans
to offer positions to substantially all of Cometra's field and technical staff
associated with these properties.
On a Present Value basis, 95% and 70%, respectively, of the West Texas and
South Texas/Gulf of Mexico properties are operated by the Company. The offshore
properties are operated by experienced third parties. Although the Company has
no definitive plans to do so at this time, the Company has previously announced
that it may elect to sell all or part of the Gulf of Mexico properties because
they are not located in the Company's core areas.
RESERVES
The following table sets forth summary information with respect to the
proved reserves of the Cometra Properties by region at December 31, 1996:
<TABLE>
<CAPTION>
PRESENT VALUE NATURAL
----------------- NATURAL GAS
AMOUNT OIL & NGLS GAS EQUIV.
(THOUSANDS) % (MBBLS) (MMCF) (MMCFE)
----------- --- ---------- ------- -------
<S> <C> <C> <C> <C> <C>
West Texas................................... $387,852 81% 8,271 174,339 223,965
South Texas/Gulf of Mexico................... 93,639 19 1,459 27,667 36,422
-------- --- ----- ------- -------
Total.............................. $481,491 100% 9,730 202,006 260,387
======== === ===== ======= =======
</TABLE>
The West Texas properties consist of 450 producing wells on 99,000 gross
acres (70,000 net) located principally in the Val Verde and Permian Basins. The
Company operates 95% of the properties on a Present Value basis and the
pipelines and gas processing plant. Existing production ranges in depth from
3,000 to 7,000 feet. The Company has identified 365 proven recompletion and
development drilling projects in this area. In the Val Verde Basin, the Company
benefits from a $3.70 per Mcf gas sales contract covering 20,000 acres currently
producing approximately 20,000 Mcf/d. The contract is with a large gas utility
and expires in June 2000.
The South Texas/Gulf of Mexico properties consist of 65 producing wells on
51,000 gross acres (20,000 net). The Company operates 70% of the properties on a
Present Value basis, primarily in South Texas. The Gulf of Mexico properties
include 14 producing wells on seven offshore platforms, all of which are
operated by
17
<PAGE> 18
third parties, including affiliates of National Fuel Gas Co., Noble Affiliates,
Inc. and British Borneo Petroleum Syndicate plc. Total net daily production from
the South Texas/Gulf of Mexico properties currently is 22,300 Mcfe. Onshore,
production comes from depths ranging from 1,000 to 12,000 feet, and has an
estimated reserve life in excess of seven years. In the Gulf of Mexico,
production ranges in depth from 8,000 to 14,000 feet, while water depths vary
from 50 to 220 feet. The Company has identified a total of 36 development
projects. Both shallower and deeper horizons hold potential exploration
opportunities, which the Company expects to evaluate further with the assistance
of 3-D seismic technology.
GAS PLANTS AND PIPELINES
As part of the Cometra Acquisition, the Company has acquired 265 miles of
gas pipelines and a 25,000 Mcf/d capacity gas processing plant in the Permian
Basin. The gas plant, located outside Sterling City, Texas, was constructed in
1995 and is currently processing gas, approximately 50% of which is attributable
to Company operated wells, at the rate of 20,000 Mcf/d. The Company believes
that the plant's capacity could be expanded to 35,000 Mcf/d for an additional
capital expenditure of approximately $4.0 million.
NOTES OFFERING
Concurrently with the Common Stock Offering, the Company is offering $125
million aggregate principal amount of its 8.75% Senior Subordinated Notes due
2007. The closings of the Common Stock Offering and the Notes Offering are
contingent upon each other. The Notes will be unconditionally guaranteed on an
unsecured, senior subordinated basis, by each of the Company's Restricted
Subsidiaries (as defined in the Indenture for the Notes), provided that such
guarantees will terminate under certain circumstances. The Indenture for the
Notes will contain certain covenants, including, but not limited to, covenants
with respect to the following matters: (i) limitation on restricted payments;
(ii) limitation on the incurrence of indebtedness and issuance of Disqualified
Stock (as defined in the Indenture for the Notes); (iii) limitation on liens;
(iv) limitation on disposition of proceeds of asset sales; (v) limitation on
transactions with affiliates; (vi) limitation on dividends and other payment
restrictions affecting restricted subsidiaries; (vii) restrictions on mergers,
consolidations and transfers of assets; and (viii) limitation on "layering"
indebtedness.
USE OF PROCEEDS
The net proceeds of the Common Stock Offering are estimated to be
approximately $64.1 million and the net proceeds of the Notes Offering are
estimated to be approximately $121.0 million, after deducting underwriting
discounts and estimated expenses. The Company intends to use all of such net
proceeds to repay certain indebtedness incurred under the Credit Agreement to
fund a portion of the cash purchase price for the Cometra Properties. See
"Cometra Acquisition" and "Notes Offering." At March 5, 1997, indebtedness under
the Credit Agreement, which expires in February 2002, had a weighted average
interest rate of 7.0%. For additional information with respect to the interest
rates, maturity and covenants related to the Credit Agreement, see "Description
of Capital Stock and Indebtedness -- Credit Agreement."
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<PAGE> 19
CAPITALIZATION
The following table sets forth the capitalization of the Company at
December 31, 1996, and the pro forma capitalization of the Company at December
31, 1996, giving effect to the Cometra Acquisition and the related financings
(including the application of the net proceeds from the Offerings as described
in "Use of Proceeds") as if such transactions occurred on December 31, 1996.
This table should be read in conjunction with the Consolidated Financial
Statements and Unaudited Pro Forma Consolidated Financial Statements and Notes
thereto included herein, and "Selected Consolidated Financial Data" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
DECEMBER 31, 1996
----------------------
ACTUAL PRO FORMA
-------- -----------
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Current portion of debt..................................... $ 26 $ 26
======== ========
Long-term debt:
Revolving credit facility................................. $ 61,355 $231,305
8.75% Senior Subordinated Notes........................... -- 125,000
6% Convertible Subordinated Debentures (1)................ 55,000 55,000
Other long-term debt...................................... 425 425
-------- --------
Total long-term debt.............................. $116,780 $411,730
======== ========
Stockholders' equity:
Preferred Stock, $1 par value, 4,000,000 shares
authorized:
$2.03 Convertible Preferred Stock, 1,150,000 shares
outstanding ($28,750,000 liquidation preference)(2).... 1,150 1,150
Common Stock, $.01 par value, 35,000,000 shares
authorized:
14,750,537 issued and outstanding; 20,160,643 shares
issued
and outstanding pro forma (3).......................... 148 202
Capital in excess of par value............................ 110,248 204,294
Retained earnings......................................... 5,291 5,291
Unrealized gain on marketable securities.................. 692 692
-------- --------
Total stockholders' equity........................ 117,529 211,629
-------- --------
Total capitalization......................... $234,309 $623,359
======== ========
</TABLE>
- ---------------
(1) The 6% Convertible Subordinated Debentures were issued on December 27, 1996.
See "Description of Capital Stock and Indebtedness."
(2) The $2.03 Convertible Preferred Stock, may, at the election of the Company,
be exchanged for an aggregate of $28,750,000 principal amount of 8.125%
Convertible Subordinated Notes due December 31, 2005. See "Description of
Capital Stock and Indebtedness."
(3) The pro forma column includes the 1,410,106 shares issued to Cometra as
partial consideration for the Cometra Properties.
19
<PAGE> 20
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Common Stock was listed on the NYSE on October 11, 1996 under the
symbol "LOM." Prior to listing on the NYSE, the Common Stock was listed on the
Nasdaq National Market under the symbol "LOMK." At March 5, 1997, 16,244,451
shares were held by approximately 4,300 stockholders of record.
The following table sets forth the high and low sales prices as reported on
the NYSE Composite Transaction Tape or the Nasdaq National Market, as
applicable, on a quarterly basis for the periods indicated.
<TABLE>
<CAPTION>
COMMON STOCK
HIGH LOW DIVIDENDS
------- ------- ------------
<S> <C> <C> <C>
1997
First Quarter (through March 10)................ $23.625 $16.000 (a)
1996
Fourth Quarter.................................. $17.375 $13.125 $ .02
Third Quarter................................... 14.875 12.750 .02
Second Quarter.................................. 15.500 11.625 .01
First Quarter................................... 12.125 9.560 .01
1995
Fourth Quarter.................................. $ 7.500 $ 5.500 $ .01
Third Quarter................................... 9.250 7.250 --
Second Quarter.................................. 8.188 7.250 --
First Quarter................................... 7.375 5.500 --
</TABLE>
- ---------------
(a) Since the fourth quarter of 1995, dividends have been declared at the
beginning of the last month of each calendar quarter and have been paid at
the end of such calendar quarter.
Dividends on the Common Stock were initiated in December 1995 and have been
paid in each successive quarter. The $2.03 Convertible Preferred Stock receives
cumulative quarterly dividends at the annual rate of $2.03 per share. If there
is any arrearage in dividends on the $2.03 Convertible Preferred Stock, the
Company may not pay dividends on the Common Stock. The Company has never been in
arrears in the payment of dividends on the $2.03 Convertible Preferred Stock.
See "Description of Capital Stock and Indebtedness."
The payment of dividends is subject to declaration by the Board of
Directors and may depend upon earnings, capital expenditures and market factors
existing from time to time. The Credit Agreement and the Indenture for the Notes
contain restrictions on the Company's ability to pay dividends on capital stock.
Under the most restrictive of these provisions, the Company could have paid
$5,000,000 of dividends as of December 31, 1996.
20
<PAGE> 21
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
The accompanying unaudited pro forma consolidated financial statements give
effect to: (i) the purchase by the Company of certain oil and gas properties
from Bannon Energy Incorporated (the "Bannon Acquisition") in April 1996 for $37
million, (ii) the Cometra Acquisition, (iii) the private placements of 600,000
shares of Common Stock and $55 million of 6% Convertible Subordinated Debentures
(collectively referred to as the "Private Placements"), (iv) the Offerings, (v)
the application of the estimated net proceeds from the Private Placements and
the Offerings and (vi) the conversion of the Company's 7 1/2% Convertible
Exchangeable Preferred Stock into Common Stock. The unaudited pro forma
consolidated statement of income for the year ended December 31, 1996 was
prepared as if the Bannon Acquisition, the Cometra Acquisition, the Private
Placements and the Offerings (collectively, the "Transactions") had occurred on
January 1, 1996. The accompanying unaudited pro forma consolidated balance sheet
of the Company as of December 31, 1996 has been prepared as if the Transactions
had occurred as of that date. The historical information provided under the
heading "Bannon Acquisition" in the statement of income for the year ended
December 31, 1996, includes results for the properties acquired in the Bannon
Acquisition for the period from January 1, 1996 until its purchase on March 31,
1996. The historical information provided in the statement of income of the
Company for the year ended December 31, 1996 includes results for the properties
acquired in the Bannon Acquisition for the period from April 1, 1996 through
December 31, 1996.
This information is not necessarily indicative of future consolidated
results of operations and it should be read in conjunction with the separate
historical statements and related notes of the respective entities appearing
elsewhere in this Registration Statement or incorporated by reference herein.
21
<PAGE> 22
LOMAK PETROLEUM, INC. AND SUBSIDIARIES
PRO FORMA COMBINED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 1996
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
PRO FORMA
BANNON COMETRA PRO FORMA PRE-OFFERING OFFERING PRO FORMA
LOMAK ACQUISITION ACQUISITION ADJUSTMENTS LOMAK ADJUSTMENTS LOMAK
------- ----------- ----------- ----------- ------------ ----------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
REVENUES
Oil and gas sales.......... $68,054 $1,703 $60,751 $ $130,508 $ $130,508
Field services............. 14,223 -- -- 14,223 14,223
Gas transportation and
marketing................ 5,575 -- 7,273 11,478(a) 24,326 24,326
Interest and other......... 3,386 -- -- 3,386 3,386
------- ------ ------- -------- --------
91,238 1,703 68,024 172,443 172,443
------- ------ ------- -------- --------
EXPENSES
Direct operating........... 24,456 562 14,376 39,394 39,394
Field services............. 10,443 -- -- 10,443 10,443
Gas transportation and
marketing................ 1,674 -- -- 11,478(a) 13,152 13,152
Exploration................ 1,460 -- -- 1,460 1,460
General and
administrative........... 3,966 -- -- 3,966 3,966
Interest................... 7,487 -- -- 23,991(b) 31,478 (521)(e) 30,957
Depletion, depreciation and
amortization............. 22,303 -- -- 22,086(c) 44,389 44,389
------- ------ ------- -------- --------
71,789 562 14,376 144,282 143,761
------- ------ ------- -------- --------
Income before taxes.......... 19,449 1,141 53,648 28,161 28,682
INCOME TAXES
Current.................... (729) -- -- (115)(d) (844) (16)(f) (860)
Deferred................... (6,105) -- -- (2,906)(d) (9,011) (167)(f) (9,178)
------- ------ ------- -------- --------
Net income................... $12,615 $1,141 $53,648 $ 18,306 $ 18,644
======= ====== ======= ======== ========
Net income applicable to
common shares.............. $10,161 $ 15,972 $ 16,310
======= ======== ========
Earnings per common share.... $ 0.69 $ 0.97 $ 0.80
======= ======== ========
Weighted average shares
outstanding................ 14,812 1,583 16,395 4,000 20,395
======= ======== ========
</TABLE>
See notes to pro forma combined financial statements
22
<PAGE> 23
LOMAK PETROLEUM, INC.
PRO FORMA COMBINED BALANCE SHEET
DECEMBER 31, 1996
(DOLLARS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
PRO FORMA
PRO FORMA PRE-OFFERING OFFERING PRO FORMA
LOMAK ADJUSTMENTS LOMAK ADJUSTMENTS LOMAK
-------- ----------- ------------ ----------- ---------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets
Cash and equivalents......... $ 8,625 $ $ 8,625 $ $ 8,625
Accounts receivable.......... 18,121 18,121 18,121
Marketable securities........ 7,658 7,658 7,658
Inventory and other.......... 799 799 799
-------- -------- --------
Total current assets...... 35,203 35,203 35,203
-------- -------- --------
Oil and gas properties......... 282,519 325,000(g) 607,519 607,519
Accumulated depletion and
amortization............ (53,102) (53,102) (53,102)
-------- -------- --------
229,417 554,417 554,417
-------- -------- --------
Gas transportation and field
service assets............... 21,139 60,000(g) 81,139 81,139
Accumulated
depreciation............ (4,997) (4,997) (4,997)
-------- -------- --------
16,142 76,142 76,142
-------- -------- --------
Other assets................... 1,785 1,785 4,050(h) 5,835
-------- -------- --------
$282,547 $667,547 $671,597
======== ======== ========
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities
Accounts payable............. $ 14,433 $ $ 14,433 $ $ 14,433
Accrued liabilities.......... 4,603 4,603 4,603
Accrual payroll and benefit
costs..................... 3,245 3,245 3,245
Current portion of debt...... 26 26 26
-------- -------- --------
Total current
liabilities............. 22,307 22,307 22,307
-------- -------- --------
(120,950)(h) }
Revolving credit facility...... 61,355 355,000(g) 416,355 (64,100)(i) } 231,305
8.75% Senior subordinated
notes........................ -- -- 125,000 (h) 125,000
6% Convertible subordinated
debentures................... 55,000 55,000 55,000
Other long-term debt........... 425 425 425
-------- -------- --------
116,780 471,780 411,730
-------- -------- --------
Deferred income taxes.......... 25,931 25,931 25,931
Stockholders' equity
$2.03 Preferred stock, $1 par
value..................... 1,150 1,150 1,150
Common Stock, $.01 par
value..................... 148 14(g) 162 40 (i) 202
Capital in excess of par
value..................... 110,248 29,986(g) 140,234 64,060 (i) 204,294
Retained earnings
(deficit)................. 5,291 5,291 5,291
Unrealized gain on marketable
securities................ 692 692 692
-------- -------- --------
Total stockholders'
equity.................. 117,529 147,529 211,629
-------- -------- --------
$282,547 $667,547 $671,597
======== ======== ========
</TABLE>
See notes to pro forma combined financial statements
23
<PAGE> 24
LOMAK PETROLEUM, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE (1) PRO FORMA ADJUSTMENTS FOR THE TRANSACTIONS -- FOR THE YEAR ENDED
DECEMBER 31, 1996
The accompanying unaudited pro forma consolidated statement of income for
the year ended December 31, 1996 has been prepared as if the Transactions had
occurred on January 1, 1996 and reflects the following adjustments:
(a) To reclassify gas transportation and marketing revenue and expenses to
conform with the accounting presentation followed by the Company.
(b) To adjust interest expense for the estimated amount that would have
been incurred on the incremental borrowings for the Bannon Acquisition
and the Cometra Acquisition, net of proceeds received from the Private
Placements. A 1/8% per annum increase in interest rate would decrease
the Company's income before taxes by $392,000.
(c) To record depletion expense for the Bannon Acquisition and the Cometra
Acquisition at a rate of $0.87 per Mcfe, which would have been the rate
in effect for 1996 had such acquisitions taken place at January 1,
1996. Additionally, to record depreciation expense on the gas
processing plant purchased in the Cometra Acquisition.
(d) To adjust the provision for income taxes for the change in taxable
income resulting from the Bannon Acquisition, the Cometra Acquisition
and the Private Placements and the effect on deferred taxes recorded at
January 1, 1996 as if such Transactions had taken place at that time.
(e) To adjust interest expense for the estimated amounts that would have
been repaid with the net proceeds from the Offerings. Because the net
proceeds from the Offerings will be used to repay debt, a 1/8% per
annum increase in interest rate would increase the Company's income
before taxes by $76,000.
(f) To adjust the provision for income taxes for the change in taxable
income resulting from interest adjustments made to reflect the amounts
of borrowings repaid with the net proceeds from the Offerings and the
effect on deferred taxes recorded at January 1, 1996 as if the
Offerings had taken place at that time.
NOTE (2) PRO FORMA ADJUSTMENTS FOR THE COMETRA ACQUISITION AND THE
OFFERINGS -- AS OF DECEMBER 31, 1996
(g) To record the Cometra Acquisition.
(h) To record the Notes Offering, net of offering costs and the application
of proceeds therefrom.
(i) To record the Common Stock Offering, net of offering costs and the
application of proceeds therefrom.
NOTE (3) EXPECTED GENERAL AND ADMINISTRATION EXPENSES
In connection with the Cometra Acquisition, the Company expects that
general and administrative expenses will increase approximately $1.7 million as
a result of offers made to Cometra personnel and that field service revenues
will increase approximately $240,000 for operating agreements acquired in the
Cometra Acquisition. The impact of these increases would be to reduce 1996 pro
forma earnings per share to $0.75.
24
<PAGE> 25
SELECTED CONSOLIDATED FINANCIAL DATA
The following tables present selected consolidated financial data covering
the five years ended December 31, 1996. Such data has been derived from, and
should be read in conjunction with, the audited Consolidated Financial
Statements and Notes thereto for each of the five years ended December 31, 1996,
the Unaudited Pro Forma Consolidated Financial Statements and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included herein.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
PRO FORMA
1992 1993 1994 1995 1996 1996
-------- -------- -------- -------- -------- ---------
(UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales............................... $ 7,703 $ 11,132 $ 24,461 $ 37,417 $ 68,054 $130,508
Field services.................................. 5,283 6,966 7,667 10,097 14,223 14,223
Gas transportation and marketing................ 332 559 2,195 3,284 5,575 24,326
Interest and other.............................. 577 418 471 1,317 3,386 3,386
-------- -------- -------- -------- -------- --------
13,895 19,075 34,794 52,115 91,238 172,443
Expenses:
Direct operating................................ 3,039 4,438 10,019 14,930 24,456 39,394
Field services.................................. 3,951 5,712 5,778 6,469 10,443 10,443
Gas transportation and marketing................ -- 13 490 849 1,674 13,152
Exploration..................................... 36 86 359 512 1,460 1,460
General and administrative...................... 1,915 2,049 2,478 2,736 3,966 3,966
Interest........................................ 952 1,120 2,807 5,584 7,487 30,957
Depletion, depreciation and amortization........ 3,124 4,347 10,105 14,863 22,303 44,389
-------- -------- -------- -------- -------- --------
13,017 17,765 32,036 45,943 71,789 143,761
-------- -------- -------- -------- -------- --------
Income before taxes.............................. 878 1,310 2,758 6,172 19,449 28,682
Income taxes..................................... 192 (81) 139 1,782 6,834 10,038
-------- -------- -------- -------- -------- --------
Net income....................................... $ 686 $ 1,391 $ 2,619 $ 4,390 $ 12,615 $ 18,644
======== ======== ======== ======== ======== ========
Earnings per common share........................ $ 0.08 $ 0.18 $ 0.25 $ 0.31 $ 0.69 $ 0.80
======== ======== ======== ======== ======== ========
Cash dividends per common share.................. $ 0.00 $ 0.00 $ 0.00 $ 0.01 $ 0.06 N/A
======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA (a)....................................... $ 4,990 $ 6,863 $ 16,029 $ 27,131 $ 50,699 $105,488
Net cash provided by operations.................. 5,168 4,305 11,241 16,561 38,445 N/A
Net cash used in investing....................... (4,210) (43,459) (29,536) (76,113) (69,666) N/A
Net cash provided by financing................... 126 38,912 21,173 57,702 36,799 N/A
Capital expenditures............................. 5,920 48,240 70,024 88,530 79,390 N/A
Ratios:
EBITDA to interest expense...................... 5.2x 6.1x 5.7x 4.9x 6.8x 3.4x
Earnings to fixed charges (b)................... 1.9x 2.2x 2.0x 2.1x 3.6x 1.9x
Total debt to EBITDA............................ 2.6x 4.5x 3.9x 3.1x 2.3x 3.9x
BALANCE SHEET DATA (END OF PERIOD):
Cash and equivalents............................. $ 2,261 $ 2,019 $ 4,897 $ 3,047 $ 8,625 $ 8,625
Total assets..................................... 28,328 76,333 141,768 214,788 282,547 671,597
Long-term debt (c)............................... 13,127 31,108 62,592 83,088 116,806 411,756
Stockholders' equity............................. 9,504 32,263 43,248 99,367 117,529 211,629
</TABLE>
- ---------------
(a) EBITDA represents net income plus income taxes, exploration expense,
interest expense and depletion, depreciation, and amortization expense.
EBITDA is not presented as an indicator of the Company's operating
performance, an indicator of cash available for discretionary spending or as
a measure of liquidity. EBITDA may not be comparable to other similarly
titled measures of other companies. The Company's Credit Agreement requires
the maintenance of certain EBITDA ratios. See "Description of Capital Stock
and Indebtedness -- Credit Agreement."
(b) For the purpose of determining the ratio of earnings to fixed charges,
earnings are defined as income before taxes plus fixed charges. Fixed
charges consist of interest expense.
(c) Long-term debt includes current portion.
25
<PAGE> 26
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 herein.
RESULTS OF OPERATIONS
The Company has experienced significant growth in reserves, production,
cash flow and earnings over the past three years. The following tables set forth
selected financial and operating information as well as the annual percentage
change for each of the past three years:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1994 1995 1996
------- ------- -------
(DOLLARS IN THOUSANDS, EXCEPT
PRICE DATA)
<S> <C> <C> <C>
Revenues.............................................. $34,794 $52,115 $91,238
Expenses.............................................. 32,036 45,943 71,789
Net Income............................................ 2,619 4,390 12,615
EBITDA(1)............................................. 16,029 27,131 50,699
Production Volumes:
Natural Gas (Mmcf).................................. 6,996 12,471 21,231
Oil and NGLs (Mbbls)................................ 640 913 1,068
Natural Gas Equivalents (Mmcfe)..................... 10,836 17,949 27,641
Average Prices:
Natural Gas (per Mcf)............................... $ 2.10 $ 1.79 $ 2.24
Oil and NGLs (per Bbl).............................. 15.23 16.57 19.12
Natural Gas Equivalents (per Mcfe).................. 2.26 2.08 2.46
</TABLE>
<TABLE>
<CAPTION>
PERCENTAGE CHANGE
FROM PRIOR PERIOD
------------------
YEAR ENDED
DECEMBER 31,
------------------
1995 1996
----- -----
<S> <C> <C> <C>
Revenues....................................................... 50% 75%
Expenses....................................................... 43 56
Net Income..................................................... 68 187
EBITDA (1)..................................................... 69 87
Production Volumes:
Natural Gas.................................................. 78 70
Oil and NGLs................................................. 43 17
Natural Gas Equivalents...................................... 66 54
Average Prices:
Natural Gas (per Mcf)........................................ (15) 25
Oil and NGLs (per Bbl)....................................... 9 15
Natural Gas Equivalents (per Mcfe)........................... (8) 18
</TABLE>
- ---------------
(1) EBITDA represents net income plus income taxes, exploration expense,
interest expense and depletion, depreciation, and amortization expense.
EBITDA is not presented as an indicator of the Company's operating
performance, an indicator of cash available for discretionary spending or as
a measure of liquidity. EBITDA may not be comparable to other similarly
titled measures of other companies. The Company's Credit Agreement requires
the maintenance of certain EBITDA ratios. See "Description of Capital Stock
and Indebtedness -- Credit Agreement."
26
<PAGE> 27
Comparison of 1996 to 1995
The Company reported net income for the year ended December 31, 1996 of
$12.6 million, a 187% increase over 1995. The increase is the result of (i)
higher production volumes, over 60% of which is attributable to acquisitions and
the remainder is attributable to development activities; (ii) increased prices
received from the sale of oil and gas products and (iii) gains from asset sales.
During the year, oil and gas production volumes increased 54% to 27.6 Bcfe, an
average of 75,522 Mcfe/d. The increased revenues recognized from production
volumes were aided by an 18% increase in the average price received per Mcfe of
production to $2.46. The average oil price increased 15% to $19.12 per barrel
while average gas prices increased 25% to $2.24 per Mcf. As a result of the
Company's larger base of producing properties and production, oil and gas
production expenses increased 64% to $24.5 million in 1996 versus $14.9 million
in 1995. The average operating cost per Mcfe produced increased 6% from $0.83 in
1995 to $0.88 in 1996 due to unsuccessful recompletion costs and increases in
personnel costs.
Gas transportation and marketing revenues increased 70% to $5.6 million
versus $3.3 million in 1995 principally due to production growth. Gas
transportation and marketing expenses increased 97% to $1.7 million versus $0.8
million in 1995. The increase in expenses was due to production growth, as well
as the increase in gas transportation and marketing expense and higher
administrative costs associated with the growth in gas marketing.
Field services revenues increased 41% in 1996 to $14.2 million. The higher
revenues were due primarily to a larger base of operated properties. Field
services expenses increased 61% in 1996 to $10.4 million versus $6.5 million.
The increase is attributed to the cost of operating a larger base of properties
and lower overall margins on Oklahoma well servicing. In December 1996, the
Company sold its brine disposal and well servicing activities in Oklahoma for
$2.7 million and recorded a gain of approximately $1.2 million, which is
included in interest and other income.
Exploration expense increased 185% to $1.5 million due to the Company's
increased involvement in seismic and exploratory drilling. The Company
participated in 11 exploratory wells in 1996 versus 7 exploratory wells in 1995.
General and administrative expenses increased 45% from $2.7 million in 1995
to $3.9 million in 1996. As a percentage of revenues, general and administrative
expenses were 4% in 1996 as compared to 5% in 1995. This decreasing trend
reflects the spreading of administrative costs over a growing asset base.
Interest and other income rose 157% to $3.4 million primarily due to $1.4
million on gains from sale of marketable securities (which were not related to
hedging activities), and $1.2 million from the gain on the sale of the Oklahoma
well servicing assets. Interest expense increased 34% to $7.5 million as
compared to $5.6 million in 1995. This was primarily as a result of the higher
average outstanding debt balance during the year due to the financing of capital
expenditures. The average outstanding balances on the Credit Agreement were
$73.3 million and $107.2 million for 1995 and 1996, respectively. The weighted
average interest rate on these borrowings were 7.3% and 6.7% for the years ended
December 31, 1995 and 1996, respectively.
Depletion, depreciation and amortization increased 50% compared to 1995 as
a result of increased production volumes during the year. The Company-wide
depletion rate was $0.73 per Mcfe in 1995 and 1996.
Comparison of 1995 to 1994
The Company reported net income for the year ended December 31, 1995 of
$4.4 million, a 68% increase over 1994. This increase is the result of higher
production volumes attributable to acquisition and development activities.
During the year, oil and gas production volumes increased 66% to 17.9 Bcfe,
an average of 49.2 Mmcfe/d. The increased revenues recognized from production
volumes were partially offset by an 8% decrease in the average price received
per Mcfe of production to $2.08. The average oil price increased 9% to $16.57
per barrel while average gas prices dropped 15% to $1.79 per Mcf. As a result of
the Company's larger base of producing properties and production, oil and gas
production expenses increased 49% to $14.9 million in 1995 versus $10.0 million
in 1994. However, the average operating cost per Mcfe produced decreased 11%
from $0.93 in 1994 to $0.83 in 1995.
27
<PAGE> 28
Gas transportation and marketing revenues increased 50% to $3.3 million
versus $2.2 million in 1994. Coupled with this increase in gas transportation
and marketing revenues was a 73% increase in associated expenses for the year.
These increases were due primarily to the acquisition of several pipeline
systems, as well as the expansion of the gas marketing efforts.
Field services revenues increased 32% in 1995 to $10.1 million, despite the
September 1994 sale of virtually all well servicing and brine disposal assets in
Ohio. The decrease in activities due to this sale was more than offset by an
increase in well servicing and brine disposal activities in Oklahoma and well
operations on acquired properties. Field services expenses increased 12% in 1995
to $6.5 million versus $5.8 million. The increase is attributed to the Oklahoma
well servicing and the cost of operating a larger base of properties. The
increase in well operating costs was offset to a great extent by the disposal in
September 1994 of the Company's lower margin well servicing and brine hauling
and disposal businesses.
Exploration expense increased 43% to $0.5 million due to the Company's
increased involvement in exploration projects. These costs include delay
rentals, seismic and exploratory drilling activities.
General and administrative expenses increased 10% from $2.5 million in 1994
to $2.7 million in 1995. As a percentage of revenues, general and administrative
expenses were 5% in 1995 as compared to 7% in 1994. This improvement reflects
the spreading of administrative costs over a growing asset base.
Interest and other income rose 180% primarily due to higher sales of
non-strategic properties. Interest expense increased 99% to $5.6 million as
compared to $2.8 million in 1994. This was primarily as a result of the higher
average outstanding debt balance during the year due to the financing of capital
expenditures. The average outstanding balances on the Credit Agreement were
$42.0 million and $73.3 million for 1994 and 1995, respectively. The weighted
average interest rate on these borrowings was 6.3% and 7.3% for the years ended
December 31, 1994 and 1995, respectively.
Depletion, depreciation and amortization increased 47% compared to 1994 as
a result of increased production volumes during the year. The increased
depletion of oil and gas properties was partially offset by the reduction of
depreciation of field services assets due to the 1994 sale of field service
assets. The Company-wide depletion rate for 1995 was $0.73 per Mcfe versus $0.74
per Mcfe in 1994 due to the addition of properties at lower than historical Mcfe
costs.
Discussion of Pro Forma 1996
The Company had pro forma net income for the year ended December 31, 1996
of $18.6 million. During the year, pro forma oil and gas production volumes
averaged 135.6 Mmcfe/d, while average prices were $18.79 per barrel and $2.49
per Mcf. On a pro forma basis, the average price was $2.64 per Mcfe. The average
pro forma operating cost incurred in 1996 per Mcfe produced was $0.80.
Gas transportation and marketing revenues realized in 1996 on a pro forma
basis were $24.3 million, of which $18.7 million can be attributed to activities
related to the Cometra Properties. Pro forma gas transportation and marketing
expenses were $13.2 million for the year, of which $11.5 million can be
attributed to the Cometra Properties.
Interest expense totaled $31.0 million in 1996 on a pro forma basis. The
average outstanding balance under the Credit Agreement in 1996 on a pro forma
basis was $277.2 million. The weighted average interest rate on these borrowings
was 6.7% for the year ended December 31, 1996.
Depletion, depreciation and amortization totaled $44.4 million in 1996 on a
pro forma basis. The Company-wide depletion rate was $0.87 per Mcfe in 1996.
LIQUIDITY AND CAPITAL RESOURCES
General
Working capital at December 31, 1996 was $12.9 million, representing an
$8.3 million increase over the corresponding amount at December 31, 1995. At
December 31, 1996, the Company had $8.6 million in cash and total assets of
$282.5 million. During 1996, long-term debt rose from $83.0 million to $116.8
million.
28
<PAGE> 29
At December 31, 1996, capitalization totaled approximately $234 million, of
which approximately 50% was represented by stockholders' equity and 50% by
long-term debt. Approximately $61.4 million of the long-term debt at that date
was comprised of borrowings under the Credit Agreement, $55 million being
comprised of 6% Convertible Subordinated Debentures and the remaining $500,000
comprised of other indebtedness. The Credit Agreement currently provides for
quarterly payments of interest with principal due in February 2002.
In December 1996, the Company sold $55 million of 6% Convertible
Subordinated Debentures in a private placement. Net proceeds to the Company of
approximately $53 million were used, together with internally generated funds,
to reduce the amount outstanding under the Credit Agreement to $61.4 million at
December 31, 1996. The 6% Convertible Subordinated Debentures are redeemable by
the Company after February 1, 2000 and are convertible at the option of the
holder into Common Stock at any time prior to maturity or redemption at a
conversion price of $19.25 per share, subject to adjustment in certain
circumstances.
Cash Flow
The Company has three principal operating sources of cash: (i) sales of oil
and gas; (ii) revenues from field services and (iii) revenues from gas
transportation and marketing. The Company's cash flow is highly dependent upon
oil and gas prices. Decreases in the market price of oil or gas could result in
reductions of both cash flow and the borrowing base under the Credit Agreement
which would result in decreased funds available, including funds intended for
planned capital expenditures.
The Company's net cash provided by operations for the years ended December
31, 1994, 1995 and 1996 was $11.2 million, $16.6 million and $38.4 million,
respectively. The consistent increases in the Company's cash flow from
operations can be attributed to its growth primarily through acquisitions and
development.
The Company's net cash used in investing for the years ended December 31,
1994, 1995 and 1996 was $29.5 million, $76.1 million and $69.7 million,
respectively. Investing activities for these periods are comprised primarily of
additions to oil and gas properties through acquisitions and development and, to
a lesser extent, exploitation and additions of field service assets. These uses
of cash have historically been partially offset through the Company's policy of
divesting those properties that it deems to be marginal or outside the Company's
core areas of operations. The Company's acquisition and development activities
have been financed through a combination of operating cash flow, bank borrowings
and capital raised through equity and debt offerings.
The Company's net cash provided by financing for the years ended December
31, 1994, 1995 and 1996 was $21.2 million, $57.7 million and $36.8 million,
respectively. Sources of financing used by the Company have been primarily
borrowings under its Credit Agreement and capital raised through equity and debt
offerings.
Capital Requirements
In 1996, $12.5 million and $2.0 million of expenses were incurred for
development activities and exploration activities, respectively. Although these
expenditures are principally discretionary, the Company is currently projecting
that it will spend approximately $160 million on development, exploitation and
exploration activities, which includes approximately $45 million on exploitation
and exploration expenditures, through 1999. Internally generated funds are
expected to be sufficient to fund development and exploration expenditures. See
"Business -- Development Activities" and "-- Exploration Activities."
Credit Agreement
In connection with the financing of the Cometra Acquisition, the Company
and its subsidiaries expanded the existing credit facility with the bank
lenders. The Credit Agreement permits the Company to obtain revolving credit
loans and to issue letters of credit for the account of the Company from time to
time in an aggregate amount not to exceed $400 million (of which not more than
$150 million may be represented by letters of credit). The Borrowing Base, which
is initially $400 million, will be reduced to $300 million on the earlier of
August 13, 1997 or the consummation of the Offerings, unless otherwise agreed by
the lenders. The
29
<PAGE> 30
Borrowing Base is subject to semi-annual determination and certain other
redeterminations based upon a variety of factors, including the discounted
present value of estimated future net cash flow from oil and gas production.
The Company is required to make a mandatory prepayment of all amounts
outstanding under the Credit Agreement in excess of $300 million on the earlier
of August 13, 1997 or the consummation of the Offerings. At the Company's
option, loans may be prepaid, and revolving credit commitments may be reduced,
in whole or in part at any time in certain minimum amounts.
The obligations of the Company under the Credit Agreement are
unconditionally and irrevocably guaranteed by each of the Company's direct and
indirect domestic subsidiaries (collectively, the "Bank Guarantors"). In
addition, the Credit Agreement is secured by first priority security interests
in (i) existing mortgaged oil and gas properties of the Company, including the
Cometra Properties, (ii) all accounts receivable, inventory and intangibles of
the Company and the Bank Guarantors, and (iii) all of the capital stock of the
Company's direct or indirect subsidiaries. Substantially all of the assets of
the Company will be pledged as collateral if, on May 15, 1997, the Borrowing
Base and amounts outstanding under the Credit Agreement have not been reduced to
$325 million. Such security interests will be released upon the (i) reduction of
the amounts outstanding under the Credit Agreement to $325 million (or the then
determined Borrowing Base) and (ii) issuance of $65 million of Common Stock
and/or the sale of Company assets in excess of the Borrowing Base value
attributable to such assets as agreed by the lenders (the "Trigger Event").
At the Company's option, the applicable interest rate per annum is either
the Eurodollar loan rate plus a margin ranging from 0.625% to 1.125% or the
Alternate Base Rate (as defined) plus a margin ranging from 0% to 0.25%. The
Alternate Base Rate is the higher of (a) the administrative agent bank's prime
rate and (b) the federal funds effective rate plus 0.5%. Until the occurrence of
the Trigger Event, the interest rate margins will be increased by 50 basis
points prior to March 31, 1997 and 100 basis points thereafter.
On March 5, 1997, approximately $389.5 million was outstanding (including
$134 million of then outstanding letters of credit to secure the promissory note
issued to Cometra as part of the purchase price in the Cometra Acquisition)
under the Credit Agreement. Upon consummation of the Offerings, approximately
$204.5 million will be outstanding under the Credit Agreement. Furthermore, if
the over-allotment option applicable to the Common Stock Offering is exercised
for at least 56,000 shares of Common Stock, then the Trigger Event will occur
upon exercise of the over-allotment option. If the over-allotment option is not
exercised, then the Company will need to sell an additional $900,000 of Company
assets in excess of the applicable Borrowing Base value in order for the Trigger
Event to occur.
Hedging Activities
Periodically, the Company enters into futures, option and swap contracts to
reduce the effects of fluctuations in crude oil and natural gas prices. At
December 31, 1996, the Company had open contracts for oil and gas price swaps of
300,000 barrels of oil at average prices ranging from $22.10 to $22.76 per
barrel of oil and 155,000 MmBtu of gas at $2.04 per MmBtu. While these
transactions have no carrying value, the Company's mark-to-market exposure under
these contracts at December 31, 1996 was a net loss of $1.1 million. These
contracts expire monthly through April 1997. The gains or losses on the
Company's hedging transactions is determined as the difference between the
contract price and a reference price, generally closing prices on the NYMEX. The
resulting transaction gains and losses are determined monthly and are included
in the period the hedged production or inventory is sold. Net gains or losses
relating to these derivatives for the years ended December 31, 1994, 1995 and
1996 approximated $0, $217,000 and $(724,000), respectively.
30
<PAGE> 31
BUSINESS
GENERAL
Lomak is an independent energy company engaged in oil and gas development,
exploration and acquisition primarily in three core areas: the Midcontinent,
Appalachia and the Gulf Coast. Over the past five years, the Company has
significantly increased its reserves and production through acquisitions and, to
a growing extent, development and exploration of its properties. On a pro forma
basis as of December 31, 1996, the Company had proved reserves of 644 Bcfe with
a Present Value of $974 million. On an Mcfe basis, the reserves were 63%
developed and 77% natural gas, with a reserve life in excess of 13 years.
Properties operated by the Company accounted for 94% of its pro forma Present
Value. The Company also owns over 2,000 miles of gas gathering systems and a gas
processing plant in proximity to its principal gas properties. On a pro forma
basis in 1996, the Company had revenues of $172 million and EBITDA of $105
million.
From 1991 through 1996, the Company has made 63 acquisitions, including the
Cometra Acquisition, for an aggregate purchase price of approximately $635
million and has spent $39 million on development and exploration activities. The
Company's acquisition activities were financed with $335 million of debt, $216
million of equity and $84 million of operating cash flow. These activities have
added approximately 719 Bcfe at an average cost of $0.76 per Mcfe. As a result,
the Company has achieved the following since 1991, on a pro forma basis:
- Reserves increased from 20 Bcfe in 1991 to 644 Bcfe in 1996;
- Production increased from 2 Bcfe in 1991 to 49 Bcfe in 1996;
- EBITDA increased from $4 million in 1991 to $105 million in 1996;
- Net income increased from $427,000 in 1991 to $19 million in 1996; and
- Earnings per share increased from $0.01 in 1991 to $0.80 in 1996.
The Company emphasizes strict cost controls in all aspects of its business.
As a result, combined direct operating and administrative costs have been
reduced from $1.42 per Mcfe in 1991 to $0.79 per Mcfe in 1996 on a pro forma
basis. Consequently, while the average price realized by the Company has not
increased significantly over the last five years, operating margins have
increased from $1.17 per Mcfe in 1991 to $1.85 per Mcfe in 1996 on a pro forma
basis.
BUSINESS STRATEGY
The Company's objective is to maximize shareholder value through aggressive
growth in its reserves, production, cash flow and earnings through a balanced
program of development drilling and acquisitions, as well as a growing
exploration effort. Management believes that the Cometra Acquisition has
substantially enhanced the Company's ability to increase its production and
reserves through drilling activities. The Cometra Acquisition substantially
increased the Company's inventory of proven drilling locations and, to an even
greater degree, its exploration and exploitation drilling potential. Including
the Cometra Properties, the Company has over 1,100 proven recompletion and
development drilling locations. As a result of the Cometra Acquisition, the
Company believes that it can achieve significant growth in reserves, production,
cash flow and earnings over the next several years, even if no future
acquisitions are consummated. The Company currently plans to spend $160 million
over the next three years on the further development and exploration of its
properties. Consequently, while acquisitions are expected to continue to play an
important role in the Company's future growth, the primary emphasis will shift
towards exploiting the potential of the Company's larger property base.
In order to most effectively implement its operating strategy, the Company
has concentrated its activities in selected geographic areas. In each core area,
the Company has established separate acquisition, engineering, geological,
operating and other technical expertise. The Company believes that this
geographic focus provides it with a competitive advantage in sourcing and
evaluating new business opportunities within these areas, as well as providing
economies of scale in developing and operating properties.
Lomak believes the competitive strengths described below will greatly
enhance its ability to achieve its long-term goals and objectives.
- Diversified, Long Lived Reserve Base. Lomak has compiled a diversified
group of predictable, long lived properties. The Company's oil and gas
reserves are attributable to 7,280 producing wells that have
31
<PAGE> 32
a reserve life index in excess of 13 years. The reserves are concentrated
in seven basins and are geographically and geologically diversified.
- Substantial Inventory of Development and Exploration Projects. Lomak has
over 1,100 proven development projects and a substantial number of
exploration and exploitation drilling projects located within core
operating areas in which the Company has significant operating and
technical expertise.
- Successful Acquisition Record. The Company's primary strength has
historically been to identify and acquire properties that have increased
reserves, production, cash flow and earnings. Excluding the Cometra
Acquisition, since 1991 the Company has completed 62 acquisitions for an
aggregate purchase price of $249 million, of which $237 million was
attributable to proved oil and gas properties. These acquisitions have
added proved reserves of approximately 396 Bcfe at an average acquisition
cost of $0.60 per Mcfe.
- Significant Operational Control. Lomak operates properties representing
nearly 94% of its Present Value. This allows the Company to directly
control operating and drilling costs and also allows it to dictate the
timing of development and exploration activities.
- High Operating Margins. The Company's low cost structure, coupled with
the premium gas price it receives for a significant portion of its
production, creates high operating margins. In 1996 on a pro forma basis,
Lomak generated operating margins, after deducting direct operating and
administrative costs, of $1.85 per Mcfe.
- Experienced, Incentivized Management Team. The Company's board of
directors, executive officers, technical staff and administrative
personnel have considerable industry experience and will own,
collectively, shares representing approximately 11% of the outstanding
shares of Common Stock, after giving effect to the Cometra Acquisition
and the Common Stock Offering. Over 75% of Lomak's employees either own,
or hold options to acquire, shares of Common Stock.
DEVELOPMENT ACTIVITIES
The Company's development activities include recompletions of existing
wells, infill drilling and installation of secondary recovery projects.
Development projects are generated within core operating areas where the Company
has significant operational and technical expertise. Currently, as described
below, the Company has 1,163 proven development projects in inventory. These
projects are geographically diverse, vary between oil and gas and are balanced
with regard to risk. The following table sets forth information pertaining to
the Company's proven development inventory at December 31, 1996.
PROVEN DEVELOPMENT INVENTORY
<TABLE>
<CAPTION>
NUMBER OF PROJECTS
-----------------------------------
DRILLING
RECOMPLETIONS LOCATIONS TOTAL
------------- --------- -----
<S> <C> <C> <C>
Midcontinent Region
Permian Basin.................................... 85 129 214
Val Verde Basin.................................. 76 134 210
Anadarko Basin................................... 117 86 203
San Juan Basin................................... 18 29 47
--- --- -----
Subtotal................................. 296 378 674
Appalachian Region................................. 43 320 363
Gulf Coast Region.................................. 79 47 126
--- --- -----
Total.................................... 418 745 1,163
=== === =====
</TABLE>
The Company currently anticipates that it will initiate 175 to 200
development projects in 1997. Assuming that 200 projects are initiated per year,
the Company currently has more than a five year inventory of proven development
projects. Lomak expects to spend approximately $115 million over the next three
years for development.
32
<PAGE> 33
EXPLORATION ACTIVITIES
The Company has a large inventory of moderate risk/moderate reward
exploitation drilling opportunities, as well as higher risk/higher reward
exploration projects. Lomak has identified 267 exploitation drilling projects on
the Cometra Properties, principally consisting of step-out drilling from
existing proved or proved undeveloped locations. In addition, the Company has
identified numerous other exploitation drilling opportunities within its
existing properties. Current exploration projects target deeper horizons within
existing Company-operated fields, as well as establishing new fields in
exploration trend areas in which Lomak's technical staff has experience. The
Company has not previously, and does not currently, plan to participate in
wildcat exploratory drilling outside its core operating areas.
Lomak's strategy is based on limiting its risk by allocating no more than
10% of its cash flow to higher risk exploration activities and by participating
in a variety of projects with differing characteristics. The Company's existing
inventory of exploration projects and leads varies in risk and reward based on
their depth, location and geology. A significant portion of the existing, as
well as future, exploration projects will be enhanced by use of advanced
technology including 3-D seismic and improved completion techniques.
In each of its core operating areas, the Company's geological and
geophysical staff generate both exploitation and exploration projects with the
assistance of the Company's reservoir engineers, landmen and production
engineers. The Company currently estimates that it will spend $25 million on
exploitation activities and $20 million on exploration activities over the next
three years. Existing exploitation and exploration project inventory is
described below.
Midcontinent. Exploitation projects in the Midcontinent region include 116
infill or step-out drilling locations on leasehold acreage held by currently
producing wells adjacent to the Company's production in the Sterling area of the
Permian Basin, as well as 134 infill or step-out locations on leasehold acreage
held by currently producing wells primarily in the Oakridge and Francis Hill
Fields in the Val Verde Basin. In the Big Lake area of the Permian Basin, the
Company is conducting an analysis to determine the potential for recovery of
additional reserves through increased density drilling. Based on the initial
results of the study, the Company believes there is potential for 200 economic
drill sites on its Big Lake area acreage.
Current exploration projects include deeper drilling to the Ellenburger and
Fussleman formations in the Permian and Val Verde Basins. Several projects
targeting the Red Fork, Morrow and Hunton formations are in various stages of
development in the Anadarko Basin. In the San Juan Basin, the Company's acreage
holds exploration potential for production from the Pictured Cliffs, Gallup and
Dakota formations.
Appalachia. In the Appalachian region, the Company has identified
approximately 100 infill or step-out drilling projects on existing leasehold
acreage. In addition, the Company has identified several hundred additional
potential locations near Company-owned gathering systems on acreage the Company
believes will be available for leasing in the future. The Company believes that
the location of its pipelines will provide it with a competitive advantage in
leasing this acreage, which is currently unleased. These locations target the
blanket Clinton and Medina sandstones. Exploration activity in Appalachia
centers around the drilling of deeper formations from leasehold acreage
generally being held by existing production from shallower production. The
targeted formations are in the Knox Sequence trend, which includes the Rose Run,
Beekmantown and Trempealeau formations. Lomak currently owns leasehold acreage
aggregating over 250,000 net acres in the Knox Sequence trend area. With the
assistance of higher quality 2-D seismic as well as 3-D seismic, Lomak believes
the Knox Sequence trend area could generate substantial reserves over the next
five years.
Gulf Coast. Exploitation projects in the Gulf Coast region include 34
infill or step-out drilling locations for the Yegua and Frio formations in South
Texas and the Wilcox and Carrizo formations in East Texas. Deeper, higher risk
exploratory projects have been generated in South Texas targeting the Wilcox and
Vicksburg formations. On the offshore properties, 11 exploitation and
exploration projects have been identified to the Lenticulina and Marginulina
sands. There are four exploration projects targeting the Taylor sand of the
Cotton Valley formation in East Texas.
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<PAGE> 34
ACQUISITION ACTIVITIES
The Company seeks to acquire properties that are expected to be immediately
accretive to cash flow and earnings and provide long-term growth in reserves and
production. The Company focuses on acquisitions that generally meet the
following criteria.
- Location. The Company targets potential acquisitions located in its core
operating areas which typically contain many small operators and where
the major oil companies are less active.
- Operating Efficiency. The Company targets potential acquisitions in
which it believes direct operating cost reductions and administrative
cost efficiencies can be achieved.
- Potential for Increasing Reserves. The Company pursues properties that
it believes have the potential for increased reserves and production
through development and exploration activities.
- Potential for Incremental Purchases. The Company seeks acquisitions
where opportunities to purchase additional interests in the same or
adjoining properties exist.
- Complex Transactions. The Company often pursues transactions which are
more complex as a result of ownership issues or financial structure as it
believes such transactions will attract fewer potential buyers.
The following table sets forth information pertaining to acquisitions
completed during the period January 1, 1991 through December 31, 1996 (including
the Cometra Acquisition):
<TABLE>
<CAPTION>
PURCHASE
NUMBER OF PRICE(1) MMCFE COST
PERIOD TRANSACTIONS (IN THOUSANDS) ACQUIRED PER MCFE(2)
------ ------------ -------------- -------- -----------
<C> <C> <C> <C> <C>
1991 9 $ 11,189 14,602 $0.75
1992 7 6,884 12,513 0.41
1993 12 40,527 64,552 0.59
1994 17 63,354 92,851 0.67
1995 9 71,074 103,849 0.61
1996 9 441,812 369,986 0.84
-- -------- ------- -----
Total 63 $634,840 658,353 $0.74
== ======== ======= =====
</TABLE>
- ---------------
(1) Includes purchase price for proved reserves as well as other acquired
assets, including gas gathering systems and a processing plant, undeveloped
leasehold acreage and field service assets.
(2) Includes purchase price for proved reserves only. For the Cometra
Acquisition, the purchase price for proved reserves includes the amount
attributable to the above-market gas contract. If the cost per Mcfe was
adjusted for the above-market gas contract, the 1996 cost per Mcfe would be
reduced from $0.84 to $0.74 and the total cost per Mcfe would be reduced
from $0.74 to $0.69.
RECENT SIGNIFICANT ACQUISITIONS
In addition to the Cometra Acquisition, the Company completed a number of
significant acquisitions in 1995 and 1996 as described below. See "Cometra
Acquisition" for a description of the Cometra Acquisition.
Bannon Interests. In April 1996, the Company acquired interests in
approximately 270 producing wells and 108 proven recompletion and development
drilling opportunities for $37.0 million. After giving effect to a subsequent
sale of certain Rocky Mountain region interests for $6.5 million, the acquired
properties were estimated to contain approximately 71 Bcfe of proved reserves.
Also included were 17,300 net undeveloped acres located in east and south Texas.
Red Eagle Resources Corporation. Through a series of transactions effected
in late 1994 and early 1995, the Company acquired Red Eagle Resources
Corporation for $29.6 million in cash and $16.9 million of Common Stock. Red
Eagle's assets included interests in approximately 370 producing wells located
primarily in the Okeene Field of Oklahoma's Anadarko Basin. Subsequently, the
Company acquired additional interests in over 100 Red Eagle wells for $3.9
million.
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<PAGE> 35
Eastern Petroleum Company. In January 1996, the Company acquired proved
oil and gas reserves and 40 miles of gas gathering lines in Ohio for $13.7
million. In the second quarter of 1996, the Company initiated a program
extending purchase offers to other interest owners in these properties. Through
September 30, 1996, interests in 61 wells had been purchased for approximately
$100,000.
Transfuel Interests. In September 1995, the Company acquired proved oil
and gas reserves, 1,100 miles of gas gathering lines and 175,000 undeveloped
acres in Ohio, Pennsylvania and New York from Transfuel, Inc. for $21.0 million.
Parker & Parsley Interests. In August 1995, the Company purchased proved
oil and gas reserves, 300 miles of gas gathering lines and 16,400 undeveloped
acres in Pennsylvania and West Virginia from Parker & Parsley Petroleum Company
for $20.2 million.
SIGNIFICANT PROPERTIES
At December 31, 1996, on a pro forma basis, 98% of the Company's reserves
were located in the Midcontinent, Appalachian and Gulf Coast regions. At
December 31, 1996, the Company's properties included, on a pro forma basis,
working interests in 7,280 gross (5,586 net) productive oil and gas wells and
royalty interests in 310 additional wells. The Company also held interests in
243,100 gross (166,700 net) undeveloped acres on a pro forma basis at December
31, 1996. The following table sets forth summary information with respect to the
Company's estimated proved oil and gas reserves on a pro forma basis at December
31, 1996.
<TABLE>
<CAPTION>
PRESENT VALUE
-------------------------- OIL & NATURAL NATURAL
AMOUNT NGLS GAS GAS EQUIV.
(IN THOUSANDS) % (MBBLS) (MMCF) (MMCFE)
-------------- -------- ------- -------- ----------
<S> <C> <C> <C> <C> <C>
Midcontinent Region
Permian Basin.............. $218,201 22% 12,468 54,833 129,642
Val Verde Basin............ 208,613 21 34 126,579 126,783
Anadarko Basin............. 125,143 13 1,964 71,065 82,851
San Juan Basin............. 43,845 5 3,082 16,836 35,326
-------- --- ------- -------- --------
Subtotal........... 595,802 61 17,548 269,313 374,602
Appalachian Region........... 201,215 21 1,189 181,325 188,456
Gulf Coast Region............ 160,353 16 4,179 46,403 71,477
Other........................ 16,293 2 1,489 559 9,495
-------- --- ------- -------- --------
Total.............. $973,663 100% 24,405 497,600 644,030
======== === ======= ======== ========
</TABLE>
MIDCONTINENT REGION
The Company's Midcontinent properties are situated in the Permian Basin of
west Texas, the Val Verde Basin of west Texas, the Anadarko Basin of western
Oklahoma and the Texas panhandle and the San Juan Basin of New Mexico. Reserves
in these basins represent 61% of total Present Value. Midcontinent proved
reserves total 375 Bcfe, of which approximately 57% are developed. On an Mcfe
basis, 72% of the reserves are natural gas. Combined net daily production from
these properties currently averages 3,300 barrels of oil and 52 Mmcf of natural
gas. At December 31, 1996, the Midcontinent properties had an inventory of 674
proven development projects.
Permian Basin. The Permian Basin properties contain 130 Bcfe of proved
reserves, or 22% of total Present Value. Net daily production currently averages
2,500 barrels of oil and 9 Mmcf of gas. Producing wells total 842 (617 net), of
which the Company operates 88% on a Present Value basis. Major producing
properties include the Sterling area and the Big Lake area. The Sterling area
properties produce gas from Canyon/Cisco sub-marine sand deposits at 4,000 to
8,000 feet and oil from Silurian Fussleman carbonates. The Sterling area
properties are complemented by a 25,000 Mcf/d gas plant, which processes gas
from the Company's operated properties, as well as gas produced by third
parties. The Big Lake area properties produce primarily oil from approximately
2,500 feet in various sequences of the San Andres/Grayburg formations. At
December 31, 1996, the Permian Basin properties contained 85 proven
recompletions and 129 development drilling locations.
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<PAGE> 36
Val Verde Basin. The Val Verde Basin properties contain 127 Bcfe of proved
reserves, or 21% of total Present Value. From 205 gross wells (163 net), the
Company currently produces 27 Mmcf/d of natural gas. The Company operates 89% of
the wells on a Present Value basis. Production is from 15 different deltaic
Canyon/Cisco sandstones with complex stratigraphic traps at depths ranging from
2,600 to 6,000 feet. On a Present Value basis, the Oakridge and Francis Hill
Fields contribute 91% of the Val Verde Basin reserves. At December 31, 1996, the
Company had an inventory of 76 proven recompletions and 134 development drilling
locations.
Anadarko Basin. The Anadarko Basin properties contain 83 Bcfe of proved
reserves, or 13% of total Present Value. The 431 gross wells (345 net), of which
65% are operated by the Company on a Present Value basis. Net daily production
averages 440 barrels of oil and 14 Mmcf of natural gas. Over 250 operated wells
in the Okeene Field account for 55% of the reserves on a Present Value basis.
The Anadarko Basin wells produce from a variety of sands and carbonates in both
structural and stratigraphic traps in the Hunton, Red Fork and Morrow formations
at depths ranging from 6,000 to 12,000 feet. At December 31, 1996, 117 proven
recompletions and 86 development drilling locations had been identified with
respect to the Anadarko Basin properties.
San Juan Basin. The San Juan Basin properties contain 35 Bcfe of proved
reserves, or 5% of total Present Value. The properties consist of 122 gross
wells (116 net) located in the southeastern portion of the basin, all of which
are Company operated. On an Mcfe basis, 52% of the reserves are oil and natural
gas liquids. Current daily production averages 350 barrels of oil and natural
gas liquids and 2 Mmcf of gas. Producing depths range from 2,000 to 8,000 feet
in the tight blanket sands of the Gallup and Pictured Cliffs zones, as well as
the Dakota formation. These properties have an inventory of 18 proven
recompletions and 29 development drilling locations.
APPALACHIAN REGION
The Appalachian properties contain 188 Bcfe of proved reserves, or 21% of
total Present Value. The reserves are attributable to 5,326 gross wells (4,417
net wells) located in Pennsylvania, Ohio, West Virginia and New York. The
Company operates 94% of these wells. The reserves, which on an Mcfe basis are
96% natural gas, produce principally from the Medina, Clinton and Rose Run
formations at depths ranging from 2,500 to 7,000 feet. Net daily production
currently totals 400 barrels of oil and 32 Mmcf of gas. After initial flush
production, these properties are characterized by gradual decline rates. Gas
production is transported through 1,900 miles of Company owned gas gathering
systems and is sold primarily to utilities and industrial end-users.
GULF COAST REGION
The Gulf Coast region consists of onshore properties located in the East
Texas Basin and in South Texas, as well as offshore properties located in the
Gulf of Mexico. Reserves in these areas represent 16% of the Company's total
Present Value. Gulf Coast properties contain 71 Bcfe of proved reserves, of
which approximately 63% are developed. On an Mcfe basis, 65% of the reserves are
natural gas. Current net daily production from these properties averages 1,800
barrels of oil and 21 Mmcf of natural gas. At December 31, 1996, the Gulf Coast
properties were estimated to contain 126 proven development projects.
South Texas/Gulf of Mexico. The South Texas/Gulf of Mexico properties
contain 54 Bcfe of proved reserves, or 13% of total Present Value. On an Mcfe
basis, gas makes up 79% of the reserves. Current net daily production from the
South Texas/Gulf of Mexico properties totals 1,200 barrels of oil and 21 Mmcf of
gas. Onshore South Texas, these fields range in location from Brooks County in
deep South Texas to Galveston County, near Houston. Significant fields include
Hagist Ranch, Alta Mesa, Riverside, Keeran/Welder and Moses Bayou. These fields
produce from the Wilcox, Frio, Yegua, Vicksburg and Miocene at depths ranging
from 1,000 to 10,000 feet. In total, the onshore fields include 179 gross wells
(153 net), of which 92% are Company operated. The offshore properties in the
Gulf of Mexico include seven platforms offshore Texas and Louisiana in water
depths ranging from 50 to 220 feet. All 15 gross wells (4 net) are operated by
experienced third parties. The Company's working interest in these wells ranges
from 11% to 33%. The offshore properties produce from the Miocene and
Pleistocene age formations, at depths ranging from 8,000 to 14,000 feet. With
multiple producing horizons, untested formations and complex faulting, the South
Texas/Gulf of Mexico
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<PAGE> 37
properties contain substantial development and exploration potential, including
the continued use of 3-D seismic technology. At December 31, 1996, these
properties are estimated to contain 15 proven recompletions and 24 development
drilling locations.
East Texas Basin. The East Texas properties contain 18 Bcfe of proved
reserves accounting for 3% of total Present Value. On an Mcfe basis, 79% of the
reserves are oil. Gross wells total 126 (110 net), of which 74% are Company
operated. Current net daily production averages 620 barrels of oil and 150 Mcf
of gas. Production ranges from the shallow Carrizo section of the Wilcox
formation at a depth of approximately 1,600 feet to the tight Cotton Valley
Taylor blanket sands at approximately 12,000 feet. Approximately 79% of the
Present Value of the East Texas properties is ascribed to 64 operated wells in
the Laura LaVelle Field. At December 31, 1996, 64 proven recompletions and 23
development drilling locations had been identified in the East Texas properties.
OIL AND GAS RESERVES
The following table sets forth estimated proved reserves for each year in
the five-year period ended December 31, 1996 and pro forma for the Cometra
Acquisition.
<TABLE>
<CAPTION>
DECEMBER 31, PRO
---------------------------------------------------- FORMA
1992 1993 1994 1995 1996 1996
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Natural gas (Mmcf)
Developed............................... 13,171 38,373 97,251 174,958 207,601 311,350
Undeveloped............................. 4,444 36,190 52,119 57,929 87,993 186,250
------ ------- ------- ------- ------- -------
Total........................... 17,615 74,563 149,370 232,887 295,594 497,600
------ ------- ------- ------- ------- -------
Oil and NGLs (Mbbls)
Developed............................... 1,643 3,344 6,431 8,880 10,703 15,298
Undeveloped............................. 337 1,195 2,018 1,983 3,972 9,107
------ ------- ------- ------- ------- -------
Total........................... 1,980 4,539 8,449 10,863 14,675 24,405
------ ------- ------- ------- ------- -------
Total equivalents (Mmcfe)................. 29,495 101,797 200,064 298,065 383,644 644,030
====== ======= ======= ======= ======= =======
</TABLE>
In connection with the evaluation of its reserves, the Company has engaged
the following independent petroleum consultants: Netherland, Sewell &
Associates, Inc. (Cometra Properties), Wright & Company, Inc. (Appalachia), H.J.
Gruy and Associates, Inc. (Midcontinent and Gulf Coast), Huddleston & Co., Inc.
(Midcontinent) and Clay, Holt & Klammer (Appalachia). These engineers have been
employed primarily based on geographic expertise as well as their history in
engineering certain of the acquired properties. At December 31, 1996,
approximately 95% of the proved reserves set forth above were evaluated by
independent petroleum consultants, while the remainder were evaluated by the
Company's engineering staff. All estimates of oil and gas reserves are subject
to significant uncertainty. See "Risk Factors -- Uncertainty of Estimates of
Reserves and Future Net Revenues."
The following table sets forth on a pro forma basis at December 31, 1996
the estimated future net cash flow from and the present value of the proved
reserves. Future net cash flow represents future gross cash flow from the
production and sale of proved reserves, net of production costs (including
production taxes, ad valorem taxes and operating expenses) and future
development costs. Such calculations, which are prepared in accordance with the
Statement of Financial Accounting Standards No. 69 "Disclosures about Oil and
Gas Producing Activities" are based on constant cost and price factors. Average
product prices at December 31, 1996 were $23.58 per barrel of oil and $3.54 per
Mcf of gas and pro forma average product prices at December 31, 1996 were $23.23
per barrel of oil and $3.99 per Mcf of gas. These prices were substantially
higher than historical prices used by the Company to calculate Present Value in
recent years. A decline in prices relative to year end 1996 would cause a
substantial decline in Present Value. For example, a $0.10 decline in gas
prices, holding all other variables constant, would decrease Present Value by
1.9% or $18.7 million and a $1.00 decline in oil and NGL prices world decrease
Present Value by 1.7% or $16.6 million. Furthermore, there can be no assurance
that the proved reserves will be developed within the periods indicated and it
is likely that actual prices received in the future will vary from those used in
deriving
37
<PAGE> 38
this information. There are numerous uncertainties inherent in estimating
reserves and related information and different reservoir engineers often arrive
at different estimates for the same properties.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
---------- -------------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Estimated future net cash flow.............. $1,138,704 $652,064 $1,790,768
Present Value............................... 658,121 315,541 973,663
Standardized Measure........................ N/A N/A 665,035
</TABLE>
PRODUCING WELLS
The following table sets forth certain information relating to productive
wells at December 31, 1996 on a pro forma basis. The Company owns royalty
interests in an additional 310 wells. Wells are classified as oil or gas
according to their predominant production stream.
<TABLE>
<CAPTION>
AVERAGE
GROSS NET WORKING
WELLS WELLS INTEREST
----- ----- --------
<S> <C> <C> <C>
Oil...................................................... 1,510 816 54%
Natural gas.............................................. 5,770 4,770 83%
----- ----- ---
Total............................................... 7,280 5,586 77%
===== ===== ===
</TABLE>
ACREAGE
The following table sets forth the developed and undeveloped gross and net
acreage held at December 31, 1996 on a pro forma basis.
<TABLE>
<CAPTION>
AVERAGE
WORKING
GROSS NET INTEREST
------- ------- --------
<S> <C> <C> <C>
Developed............................................ 659,619 461,999 70%
Undeveloped.......................................... 243,088 166,725 69%
------- ------- ---
Total........................................... 902,707 628,724 70%
======= ======= ===
</TABLE>
DRILLING RESULTS
The following table summarizes actual drilling activities for the three
years ended December 31, 1996. The drilling results below do not reflect the
Cometra Acquisition (or any other acquisitions).
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1994 1995 1996
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Exploratory wells:
Productive........................ 3.0 0.1 5.0 0.4 7.0 3.4
Dry............................... 6.0 1.5 2.0 0.2 4.0 1.1
Development wells:
Productive........................ 61.0 56.3 53.0 38.8 49.0 45.2
Dry............................... 1.0 0.3 2.0 0.2 3.0 2.2
----- ----- ----- ----- ----- -----
Total.......................... 71.0 58.2 62.0 39.6 63.0 51.9
===== ===== ===== ===== ===== =====
</TABLE>
POSSIBLE DISPOSITION OF NON-STRATEGIC ASSETS
In the ordinary course of its business, the Company regularly considers
transactions involving the disposition of non-strategic oil and gas assets.
Negotiations are currently in progress with respect to the possible disposition
of assets having a historical cost of approximately $5.0 million. Such assets
would be exchanged for approximately 20% of the common stock of a small publicly
traded company. The properties being considered for disposition are located
primarily outside the Company's core operating areas, with the largest portion
located in the state of Utah. There can be no assurance that any transaction
will be effected.
38
<PAGE> 39
GAS GATHERING AND PROCESSING
The Company's natural gas gathering and processing assets are primarily
comprised of (i) its Sterling system, which consists of 265 miles of gas
gathering pipelines and a gas processing plant in the Sterling area of the
Permian Basin, and (ii) over 1,900 miles of gas gathering pipelines in
Appalachia. The Sterling plant is a refrigerated turbo-expander cryogenic gas
plant that was placed in service in early 1995. The plant, designed for
approximately 25,000 Mcf/d, is currently operating at 87% of capacity. The
Company estimates that the plant's capacity can be increased to 35,000 Mcf/d for
approximately $4.0 million in additional capital expenditures.
The Appalachian gas gathering systems serve to transport a majority of the
Company's Appalachian gas production as well as third party gas to major
trunklines and directly to industrial end-users. This affords the Company
considerable control and flexibility in marketing its Appalachian production.
Third parties who transport their gas through the systems are charged a
gathering fee ranging from $0.20 to $0.32 per Mcf.
OIL AND GAS MARKETING
In order to handle more efficiently the sale of its natural gas, the
Company began to market its own gas production in 1993. On a pro forma basis,
the Company is currently marketing 173 Mmcf/d for its own account as well as
additional volumes for third party producers. The Company's gas production is
sold primarily to utilities and directly to industrial users.
The Company has managed the impact of potential price declines by
developing a balanced portfolio of fixed price and market sensitive contracts
and commodity hedging. On a pro forma basis, approximately 47% of average gas
production at December 31, 1996 was sold subject to fixed price sales contracts.
These fixed price contracts are at prices ranging from $2.15 to $3.70 per Mcf.
The fixed price contracts with terms of less than one year, between one and five
years and greater than five years constitute approximately 31%, 65% and 4%,
respectively, of the volume sold under fixed price contracts.
From time to time, the Company enters into oil and natural gas price hedges
to reduce its exposure to commodity price fluctuations. At December 31, 1996,
approximately 12% on an Mcfe basis of the Company's monthly production for the
period January 1997 to April 1997 was hedged under such arrangements. No
production after this period was hedged. In the future, the Company may hedge a
larger percentage of its production.
Approximately 30% of the Company's pro forma December 1996 gas production
on an Mcfe basis was attributable to Appalachia. Gas production in Appalachia
has historically received a higher price, due to its proximity to the
northeastern gas markets.
The Company's oil production is sold at the well site at posted field
prices tied to the spot oil markets. Oil purchasers are selected on the basis of
price and service.
As part of the Cometra Acquisition, the Company acquired a gas contract,
which expires June 30, 2000, with a major Texas gas utility company representing
17% of the Company's pro forma December 1996 production on an Mcfe basis. The
price paid pursuant to the contract was $3.70 per Mcf at December 31, 1996 (65%
higher than average 1996 natural gas prices received by the Company) and
escalates at $0.05 per Mcf per annum. No other purchaser of the Company's oil or
gas during 1996 exceeded 10% of the Company's total revenues.
FACILITIES
The Company owns a 24,000 square foot facility located on approximately
seven acres near Hartville, Ohio. The facility houses certain operating and
administrative personnel. The Company leases approximately 33,000 square feet in
Fort Worth and Oklahoma City under standard office lease arrangements that
expire at various times through March 2004. All facilities are adequate to meet
the Company's existing needs and can be expanded with minimal expense.
The Company owns various rolling stock and other equipment which is used in
its field operations. Such equipment is believed to be in good repair and, while
such equipment is important to its operations, it can be readily replaced as
necessary.
39
<PAGE> 40
EMPLOYEES
As of March 5, 1997, the Company had approximately 300 full-time employees,
of whom approximately 190 were field personnel. None are covered by a collective
bargaining agreement and management believes that its relationship with its
employees is good.
LEGAL PROCEEDINGS
The Company is involved in various legal actions and claims arising in the
ordinary course of business. In the opinion of management, such litigation and
claims will be resolved without a material adverse effect on the Company's
financial position.
The Company recently received notice from two parties, each of whom claims
that it is entitled to fees from the Company based upon a Yemen oil concession
that they claim Red Eagle Resources Corporation received in August 1992, which
was prior to the acquisition of Red Eagle by the Company. Based upon the
Company's examination of the available documentation relevant to such claims,
the Company believes that the claims are without merit because the claimed oil
concession was never obtained in Yemen. The Company has requested further
documentation from the two parties with respect to their claims but no such
documentation has yet been provided. The claims are for approximately $4.0
million in the aggregate (including the value of approximately 70,000 shares of
Common Stock that would be required to be issued if the oil concession had been
obtained). To date, no proceedings have been commenced with respect to either of
these claims.
40
<PAGE> 41
MANAGEMENT
The current executive officers and Directors of the Company are listed
below, together with a description of their experience and certain other
information. Each of the Directors was re-elected for a one-year term at the
Company's 1996 annual meeting of stockholders. Executive officers are appointed
by the Board of Directors.
<TABLE>
<CAPTION>
HELD
NAME AGE OFFICE SINCE POSITION WITH COMPANY
---- --- ------------ ---------------------
<S> <C> <C> <C>
Thomas J. Edelman 46 1988 Chairman and Chairman of the Board
John H. Pinkerton 42 1988 President, Chief Executive Officer and Director
Robert E. Aikman 65 1990 Director
Anthony V. Dub 47 1995 Director
Allen Finkelson 50 1994 Director
Ben A. Guill 46 1995 Director
C. Rand Michaels 59 1976 Vice Chairman and Director
Jeffery A. Bynum 42 1985 Vice President-Land
Steven L. Grose 48 1980 Vice President-Appalachia Region
Chad L. Stephens 41 1990 Vice President-Midcontinent Region
Thomas W. Stoelk 41 1994 Vice President-Finance and
Chief Financial Officer
Danny W. Sowell 46 1996 Vice President-Gas Management
John R. Frank 41 1990 Controller
Geoffrey T. Doke 30 1996 Treasurer
</TABLE>
Thomas J. Edelman holds the office of Chairman and is Chairman of the Board
of Directors. Mr. Edelman joined the Company in 1988 and served as its Chief
Executive Officer until 1992. From 1981 to February 1997, Mr. Edelman served as
a director and President of Snyder Oil Corporation ("SOCO"), an independent,
publicly traded oil and gas company. Mr. Edelman currently serves as an employee
of SOCO. In 1996, Mr. Edelman was appointed Chairman, President and Chief
Executive Officer of Patina Oil & Gas Corporation, a publicly traded affiliate
of SOCO. Prior to 1981, Mr. Edelman was a Vice President of The First Boston
Corporation. From 1975 through 1980, Mr. Edelman was with Lehman Brothers Kuhn
Loeb Incorporated. Mr. Edelman received his Bachelor of Arts Degree from
Princeton University and his Masters Degree in Finance from Harvard University's
Graduate School of Business Administration. Mr. Edelman is also a director of
Petroleum Heat & Power Co., Inc., a Connecticut-based fuel oil distributor, Star
Gas Corporation, a private company, which is the general partner of Star Gas
Partners, L.P., a publicly-traded master limited partnership, which distributes
propane gas.
John H. Pinkerton, President, Chief Executive Officer and a Director,
joined the Company in 1988. He was appointed President in 1990 and Chief
Executive Officer in 1992. Previously, Mr. Pinkerton was a Senior Vice
President-Acquisitions of SOCO. Prior to joining SOCO in 1980, Mr. Pinkerton was
with Arthur Andersen & Co. Mr. Pinkerton received his Bachelor of Arts Degree in
Business Administration from Texas Christian University and his Master of Arts
Degree in Business Administration from the University of Texas. Mr. Pinkerton is
also director of North Coast Energy, Inc. ("North Coast"), an exploration and
production company in which Lomak acquired an approximately 50% interest in
1996.
Robert E. Aikman, a Director, joined the Company in 1990. Mr. Aikman has
more than 40 years experience in petroleum and natural gas exploration and
production throughout the United States and Canada. From 1984 to 1994 he was
Chairman of the Board of Energy Resources Corporation. From 1979 through 1984,
he was the President and principal shareholder of Aikman Petroleum, Inc. From
1971 to 1977, he was President of Dorchester Exploration Inc. and from 1971 to
1980, he was a Director and a member of the Executive Committee of Dorchester
Gas Corporation. Mr. Aikman is also Chairman of Provident Trade Company,
President of EROG, Inc., and President of The Hawthorne Company, an entity which
organizes joint ventures and provides advisory services for the acquisition of
oil and gas properties, including the financial restructuring, reorganization
and sale of companies. He was President of Enertec Corporation which was
reorganized under Chapter 11 of the Bankruptcy Code in December 1994. In
addition, Mr. Aikman is a director of the Panhandle Producers and Royalty Owners
Association and a member of the Independent
41
<PAGE> 42
Petroleum Association of America, Texas Independent Producers and Royalty Owners
Association and American Association of Petroleum Landmen. Mr. Aikman graduated
from the University of Oklahoma in 1952.
Anthony V. Dub was elected to serve as a Director of the Company in 1995.
Mr. Dub is Managing Director-Senior Advisor of Credit Suisse First Boston, an
international investment banking firm with headquarters in New York City. Mr.
Dub joined Credit Suisse First Boston in 1971 and was named a Managing Director
in 1981. Mr. Dub received his Bachelor of Arts Degree from Princeton University
in 1971.
Allen Finkelson was appointed a Director in 1994. Mr. Finkelson has been a
partner at Cravath, Swaine & Moore since 1977, with the exception of the period
from September 1983 through August 1985, when he was a managing director of
Lehman Brothers Kuhn Loeb Incorporated. Mr. Finkelson was first employed by
Cravath, Swaine & Moore as an associate in 1971. Mr. Finkelson received his
Bachelor of Arts Degree from St. Lawrence University and his Doctor of Laws
Degree from Columbia University School of Law.
Ben A. Guill was elected to serve as a Director of the Company in 1995. Mr.
Guill is a Partner and Managing Director of Simmons & Company International, an
investment banking firm located in Houston, Texas focused exclusively on the oil
service and equipment industry. Mr. Guill has been with Simmons & Company since
1980. Prior to joining Simmons & Company, Mr. Guill was with Blyth Eastman
Dillon & Company from 1978 to 1980. Mr. Guill received his Bachelor of Arts
Degree from Princeton University and his Masters Degree in Finance from the
Wharton Graduate School of Business at the University of Pennsylvania.
C. Rand Michaels, who holds the office of Vice Chairman and is a Director,
served as President and Chief Executive Officer of the Company from 1976 through
1988 and Chairman of the Board from 1984 through 1988, when he became Vice
Chairman. Mr. Michaels received his Bachelor of Science Degree from Auburn
University and his Master of Business Administration Degree from the University
of Denver. Mr. Michaels is also a director of American Business Computers
Corporation of Akron, Ohio, a public company serving the beverage dispensing and
fast food industries, and North Coast.
Jeffery A. Bynum, Vice President-Land and Secretary, joined the Company in
1985. Previously, Mr. Bynum was employed by Crystal Oil Company and Kinnebrew
Energy Group of Shreveport, Louisiana. Mr. Bynum holds a Professional
Certification with American Association of Petroleum Landmen and attended
Louisiana State University in Baton Rouge, Louisiana and Centenary College in
Shreveport, Louisiana.
Steven L. Grose, Vice President-Appalachia Region, joined the Company in
1980. Previously, Mr. Grose was employed by Halliburton Services, Inc. as a
Field Engineer from 1971 until 1974. In 1974, he was promoted to District
Engineer and in 1978, was named Assistant District Superintendent based in
Pennsylvania. Mr. Grose is a member of the Society of Petroleum Engineers and a
trustee of The Ohio Oil and Gas Association. Mr. Grose received his Bachelor of
Science Degree in Petroleum Engineering from Marietta College. Mr. Grose is also
a director of North Coast.
Chad L. Stephens, Vice President-Midcontinent Region, joined the Company in
1990. Previously, Mr. Stephens was a landman with Duer Wagner & Co., an
independent oil and gas producer, since 1988. Prior thereto, Mr. Stephens was an
independent oil operator in Midland, Texas for four years. From 1979 to 1984,
Mr. Stephens was a landman for Cities Service Company and HNG Oil Company. Mr.
Stephens received his Bachelor of Arts Degree in Finance and Land Management
from the University of Texas.
Thomas W. Stoelk, Vice President-Finance and Chief Financial Officer,
joined the Company in 1994. Mr. Stoelk is a Certified Public Accountant and was
a Senior Manager with Ernst & Young LLP. Prior to rejoining Ernst & Young LLP in
1986 he was with Partners Petroleum, Inc. Mr. Stoelk received his Bachelor of
Science Degree in Industrial Administration from Iowa State University.
Danny M. Sowell, Vice President-Gas Management, joined the Company in 1996.
Previously, Mr. Sowell was Chief Executive Officer and President of Jay Gas
Marketing, which Lomak acquired May 1, 1996. Prior to founding Jay Gas, Mr.
Sowell was Director of Marketing for a subsidiary of Oklahoma Gas & Electric
42
<PAGE> 43
Company. Mr. Sowell received his Master and Bachelor of Science Degrees in
Mathematics from Lamar University.
John R. Frank, Controller and Chief Accounting Officer, joined the Company
in 1990. From 1989 until he joined Lomak in 1990, Mr. Frank was Vice President
Finance of Appalachian Exploration, Inc. Prior thereto, he held the positions of
Internal Auditor and Treasurer with Appalachian Exploration, Inc. beginning in
1977. Mr. Frank received his Bachelor of Arts Degree in Accounting and
Management from Walsh College and attended graduate studies at the University of
Akron.
Geoffrey T. Doke, Treasurer, joined the Company in 1991. He was appointed
Treasurer in 1996. Previously, Mr. Doke served in the accounting department of
Edisto Resources Corporation. Mr. Doke received his Bachelor of Business
Administration Degree in Finance and International Business from Baylor
University and his Master of Business Administration Degree from Case Western
Reserve University.
43
<PAGE> 44
PRINCIPAL STOCKHOLDERS AND SHARE OWNERSHIP OF MANAGEMENT
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the share ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company by all Directors and executive officers as a group, in each case as of
March 5, 1997 and on a pro forma basis giving effect to the Offerings. The
business address of each officer and Director listed below is: c/o Lomak
Petroleum, Inc., 500 Throckmorton Street, Fort Worth, Texas 76102.
<TABLE>
<CAPTION>
ACTUAL PRO FORMA
----------------------------- -----------------------------
NUMBER OF SHARES NUMBER OF SHARES
BENEFICIALLY PERCENTAGE BENEFICIALLY PERCENTAGE
OWNED OF CLASS OWNED OF CLASS
---------------- ---------- ---------------- ----------
<S> <C> <C> <C> <C>
Thomas J. Edelman............................. 979,541(1) 5.98% 979,541(1) 4.80%
John H. Pinkerton............................. 494,093(2) 3.01% 494,093(2) 2.42%
C. Rand Michaels.............................. 301,598(3) 1.85% 301,598(3) 1.49%
Robert E. Aikman.............................. 83,776(4) 0.52% 83,776(4) 0.41%
Anthony V. Dub................................ 64,165(5) 0.39% 64,165(5) 0.32%
Allen Finkelson............................... 6,000(6) 0.04% 6,000(6) 0.03%
Ben A. Guill.................................. 52,400(7) 0.32% 52,400(7) 0.26%
Chad L. Stephens.............................. 126,651(8) 0.78% 126,651(8) 0.62%
Thomas W. Stoelk.............................. 33,500(9) 0.21% 33,500(9) 0.17%
All Directors and executive officers as a
group (14 persons).......................... 2,394,666(10) 14.16% 2,394,666(10) 11.45%
Public Employees Retirement System of Ohio
(11)........................................ 1,350,000 8.31% 1,350,000 6.67%
Cometra Energy, L.P. (12) .................... 1,410,106 8.68% 1,410,106 6.97%
</TABLE>
- ---------------
(1) Includes 145,000 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days; 113,333
shares held under IRA, KEOGH and pension plan accounts; 29,916 shares owned
by Mr. Edelman's spouse; and 91,200 shares owned by Mr. Edelman's minor
children, to which Mr. Edelman disclaims beneficial ownership.
(2) Includes 171,667 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days; 115,899
shares held under IRA and pension plan accounts; 1,572 shares owned by Mr.
Pinkerton's minor children; and 743 shares owned by Mr. Pinkerton's spouse,
to which Mr. Pinkerton disclaims beneficial ownership.
(3) Includes 60,666 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days; 1,804 shares
held under the IRA account; 107,011 shares owned by Mr. Michael's spouse;
and 19,460 shares owned by Mr. Michael's minor children, to which Mr.
Michaels disclaims beneficial ownership.
(4) Includes 21,000 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days; 7,566 shares
owned by Mr. Aikman's spouse; and 10,010 shares owned by Mr. Aikman's minor
children, to which Mr. Aikman disclaims beneficial ownership.
(5) Includes 2,400 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days.
(6) Includes 6,000 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days.
(7) Includes 2,400 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days.
(8) Includes 61,167 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days; 10,000 shares
owned by Mr. Stephens' spouse; and 3,879 shares owned by Mr. Stephens'
minor children, to which Mr. Stephens disclaims beneficial ownership.
(9) Includes 32,500 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days.
(10) Includes 667,349 shares which may be purchased under currently exercisable
stock options or options that are exercisable within 60 days.
(11) Such stockholder's address is 227 East Town Street, Columbus, Ohio 43215.
(12) Such stockholder's address is 500 Throckmorton, Suite 2500, Fort Worth,
Texas 76102.
44
<PAGE> 45
DESCRIPTION OF CAPITAL STOCK AND INDEBTEDNESS
The authorized capital stock of the Company consists of (i) 4,000,000
shares of serial preferred stock, $1.00 par value and (ii) 35,000,000 shares of
Common Stock, $.01 par value. As of March 5, 1997, the Company had outstanding
16,244,451 shares of Common Stock and 1,150,000 shares of $2.03 Convertible
Preferred Stock.
COMMON STOCK
Holders of Common Stock are entitled to receive dividends if, when and as
declared by the Board of Directors of the Company out of funds legally available
therefor (however, the Indenture for the Notes and the Credit Agreement contain
certain restrictions on the payment of cash dividends. If there is any arrearage
in the payment of dividends on any preferred stock, the Company may not pay
dividends upon, repurchase or redeem shares of its Common Stock. All shares of
Common Stock have equal voting rights on the basis of one vote per share on all
matters to be voted upon by stockholders. Cumulative voting for the election of
directors is not permitted. Shares of Common Stock have no preemptive,
conversion, sinking fund or redemption provisions and are not liable for further
call or assessment. Each share of Common Stock is entitled to share on a pro
rata basis in any assets available for distribution to the holders of the Common
Stock upon liquidation of the Company after satisfaction of any liquidation
preference on any series of the Company's preferred stock. All outstanding
shares of Common Stock have been, and all shares offered in the Common Stock
Offering will be when issued, validly issued, fully paid and nonassessable.
OPTIONS
The Company's stock option plan, which is administered by the Compensation
Committee, provides for the granting of options to purchase shares of Common
Stock to key employees and certain other persons who are not employees for
advice or other assistance or services to the Company. The plan permits the
granting of options to acquire up to 2,000,000 shares of Common Stock subject to
a limitation of 10% of the outstanding Common Stock on a fully diluted basis. At
March 5, 1997, a total of 1,216,032 options had been granted under the plan of
which options to purchase 503,632 shares were exercisable at that date. The
options outstanding at March 5, 1997 were granted at an exercise price of $3.38
to $13.88 per share. The exercise price of all such options was equal to the
fair market value of the Common Stock on the date of grant. All were options
granted for a term of five years, with 30% of the options becoming exercisable
after one year, an additional 30% becoming exercisable after two years and the
remaining options becoming exercisable after three years.
WARRANTS
Warrants to acquire 20,000 shares of Common Stock at a price of $12.88 per
share were outstanding at March 5, 1997. These warrants expire in May 1999. The
warrants were issued in a private placement not registered under the Securities
Act, and the shares of Common Stock underlying such warrants have not been
registered under the Securities Act. In connection with the issuance of the
warrants, the warrant holder was granted certain registration rights.
PREFERRED STOCK
The Board of Directors of the Company, without action by stockholders, is
authorized to issue shares of serial preferred stock in one or more series and,
within certain limitations, to determine the voting rights (including the right
to vote as a series on particular matters), preferences as to dividends and the
liquidation, conversion, redemption and other rights of each such series. The
Board of Directors could issue a series with rights more favorable with respect
to dividends, liquidation and voting than those held by the holders of its
Common Stock. At March 5, 1997, 1,150,000 shares of Preferred Stock were
outstanding, designated as $2.03 Convertible Preferred Stock.
The $2.03 Convertible Preferred Stock bears an annual dividend rate of
$2.03 payable quarterly. If dividends have not been paid on the $2.03
Convertible Preferred Stock, the Company cannot redeem or pay dividends on
shares of stock ranking junior to the $2.03 Convertible Preferred Stock. No new
serial preferred
45
<PAGE> 46
stock can be created with rights superior to those of the $2.03 Convertible
Preferred Stock, as to dividends and liquidation rights, without the approval of
the holders of a majority of the $2.03 Convertible Preferred Stock. In addition,
the holders of the $2.03 Convertible Preferred Stock are entitled to one vote
for each share owned. Additionally, if dividends remain unpaid for six full
quarterly periods, or if any future class of preferred stockholders is entitled
to elect members of the Board of Directors based on actual missed and unpaid
dividends, the number of members of the Board of Directors will be increased to
such number as may be necessary to entitle the holders of the $2.03 Convertible
Preferred Stock and such other future preferred stockholders, voting as a single
class, to elect one-third of the members of the Board of Directors. The $2.03
Convertible Preferred Stock has liquidation rights of $25 per share. The Company
may exchange the $2.03 Convertible Preferred Stock for an aggregate of
$28,750,000 principal amount of its 8.125% Convertible Subordinated Notes due
December 31, 2005. Each share of $2.03 Convertible Preferred Stock is
convertible into Common Stock at a conversion price of $9.50 per share, subject
to adjustment under certain circumstances. The conversion price will be reduced
for a limited period (but to not less than $5.21) if a change in control or
fundamental change in the Company occurs at a time that the market price of the
Common Stock is less than the conversion price. The Company may redeem the $2.03
Convertible Preferred Stock at any time after November 1, 1998, at redemption
prices declining from $26.50 to $25.00 per share, plus cumulative unpaid
dividends.
6% CONVERTIBLE SUBORDINATED DEBENTURES
On December 27, 1996, the Company sold $55,000,000 aggregate principal
amount of 6% Convertible Subordinated Debentures in a private offering not
registered under the Securities Act. The 6% Convertible Subordinated Debentures
are convertible at any time prior to maturity, unless previously redeemed or
repurchased, into shares of Common Stock, at a conversion price of $19.25 per
share, subject to adjustment under certain circumstances. The 6% Convertible
Subordinated Debentures are unsecured and subordinate to all senior and senior
subordinated indebtedness and do not restrict the incurrence of additional
indebtedness by the Company or any of its subsidiaries. The 6% Convertible
Subordinated Debentures will mature on February 1, 2007. The Company may redeem
the 6% Convertible Subordinated Debentures, in whole or in part, on or after
February 1, 2000, at certain redemption prices, plus accrued but unpaid interest
at the date fixed for redemption. Upon certain changes of control of the
Company, the Company is required to offer to repurchase each holder's 6%
Convertible Subordinated Debentures at a purchase price equal to 100% of the
principal amount thereof, plus accrued and unpaid interest to the date of
repurchase.
Pursuant to a Registration Rights Agreement between the Company and the
initial purchasers of the 6% Convertible Subordinated Debentures, the Company
has agreed to file a shelf registration statement (the "Shelf Registration
Statement") relating to the resale of the 6% Convertible Subordinated Debentures
and the shares of Common Stock issuable upon conversion of the 6% Convertible
Subordinated Debentures. The Company will use its reasonable best efforts to
maintain the effectiveness of the Shelf Registration Statement until the third
anniversary of the issuance of the 6% Convertible Subordinated Debentures,
except that it shall be permitted to suspend the use of the Shelf Registration
Statement during certain periods under certain circumstances. If the Company
fails to meet certain of its obligations under the Shelf Registration Statement,
then a supplemental payment will be made to the holders of the 6% Convertible
Subordinated Debentures or shares of Common Stock actually issued upon
conversion of the 6% Convertible Subordinated Debentures. During the first 90
days of such a default, the supplemental payment will be $0.05 per week per
$1,000 principal amount of the 6% Convertible Subordinated Debentures and
$0.0005 per week per share of such Common Stock. The amount of such supplemental
payment will increase over time if the default continues, subject to a maximum
supplemental payment of $0.20 per week per $1,000 principal amount of 6%
Convertible Subordinated Debentures and $0.002 per week per share of Common
Stock.
CREDIT AGREEMENT
In connection with the financing of the Cometra Acquisition, the Company
and its subsidiaries expanded the existing credit facility with the bank
lenders. The Credit Agreement permits the Company to obtain revolving credit
loans and to issue letters of credit for the account of the Company from time to
time in an
46
<PAGE> 47
aggregate amount not to exceed $400 million (of which not more than $150 million
may be represented by letters of credit). The Borrowing Base, which is initially
$400 million under the expanded facility, will be reduced to $300 million on the
earlier of August 13, 1997 or the consummation of the Offerings, unless
otherwise agreed by the lenders. The Borrowing Base is subject to semi-annual
determination and certain other redeterminations based upon a variety of
factors, including the discounted present value of estimated future net cash
flow from oil and gas production.
The Company will be required to make a mandatory prepayment of all amounts
outstanding under the Credit Agreement in excess of $300 million on the earlier
of August 13, 1997 or the consummation of the Offerings. At the Company's
option, loans may be prepaid, and revolving credit commitments may be reduced,
in whole or in part at any time in certain minimum amounts. The Credit Agreement
matures in February 2002.
The obligations of the Company under the Credit Agreement are
unconditionally and irrevocably guaranteed by the Bank Guarantors. In addition,
the Credit Agreement is secured by first priority security interests in (i)
existing mortgaged oil and gas properties of the Company and the Cometra
Properties, (ii) all accounts receivable, inventory and intangibles of the
Company and the Bank Guarantors, and (iii) all of the capital stock of the
Company's direct or indirect subsidiaries. Substantially all of the assets of
the Company will be pledged as collateral if, on May 15, 1997, the Borrowing
Base and amounts outstanding under the Credit Agreement have not been reduced to
$325 million. Such security interests will be released upon the (i) reduction of
the amounts outstanding under the Credit Agreement to $325 million (or the then
determined Borrowing Base) and (ii) issuance of $65 million of Common Stock
and/or the sale of Company assets in excess of the Borrowing Base value
attributable to such assets as agreed by the lenders (the "Trigger Event").
At the Company's option, the applicable interest rate per annum is either
the Eurodollar loan rate plus a margin ranging from 0.625% to 1.125% or the
Alternate Base Rate (as defined) plus a margin ranging from 0% to 0.25%. The
Alternate Base Rate is the higher of (a) the administrative agent bank's prime
rate and (b) the federal funds effective rate plus 0.5%. Until the occurrence of
the Trigger Event, the interest rate margins will be increased by 50 basis
points prior to March 31, 1997 and 100 basis points thereafter.
Immediately following the Cometra Acquisition, approximately $392.3 million
was outstanding (including $134 million of then outstanding letters of credit to
secure the promissory note issued to Cometra as part of the purchase price in
the Cometra Acquisition) under the Credit Agreement. Upon consummation of the
Offerings, approximately $204.5 million will be outstanding under the Credit
Agreement. Furthermore, if the over-allotment option applicable to the Common
Stock Offering is exercised for at least 56,000 shares of Common Stock, then the
Trigger Event will occur upon exercise of the over-allotment option. If the
over-allotment option is not exercised, then the Company will need to sell an
additional $900,000 of Company assets in excess of the applicable Borrowing Base
value in order for the Trigger Event to occur.
The Credit Agreement includes various covenants that require, among other
things, that the Company (i) maintain a minimum consolidated tangible net worth
of at least $100 million plus 90% of the net proceeds from the Common Stock
Offering and 50% of the net proceeds from any subsequent equity offering; (ii)
maintain a ratio of EBITDA to consolidated interest expense on total debt for
each period of four consecutive fiscal quarters of at least 2.5 to 1.0; and
(iii) not make restricted payments (defined as dividends, distributions or
guarantees to third parties or the retirement, repurchase or prepayment prior to
the scheduled maturity of its subordinated debt) in an aggregate amount in any
one fiscal year in excess of $5 million plus 50% of the net proceeds from equity
offerings subsequent to the Common Stock Offering and 50% of the Company's
consolidated net income earned after January 1, 1997. In addition, the Credit
Agreement restricts the ability of the Company to dispose of assets, incur
additional indebtedness, repay other indebtedness or amend other debt
instruments, create liens on assets, make investments or acquisitions, engage in
mergers or consolidations, make capital expenditures or engage in certain
transactions with affiliates.
47
<PAGE> 48
UNDERWRITING
Subject to the terms and subject to the conditions contained in an
Underwriting Agreement dated the date hereof, the Underwriters named below, for
whom Morgan Stanley & Co. Incorporated, PaineWebber Incorporated, Smith Barney
Inc., A.G. Edwards & Sons, Inc. and McDonald & Company Securities, Inc. are
serving as Representatives, have severally agreed to purchase, and the Company
has agreed to sell to the Underwriters, an aggregate of 4,000,000 shares of
Common Stock. The number of shares of Common Stock that each Underwriter has
agreed to purchase is set forth opposite its name below:
<TABLE>
<CAPTION>
NAME NUMBER OF SHARES
---- ----------------
<S> <C>
Morgan Stanley & Co. Incorporated .......................... 660,000
PaineWebber Incorporated.................................... 660,000
Smith Barney Inc. .......................................... 660,000
A.G. Edwards & Sons, Inc. .................................. 660,000
McDonald & Company Securities, Inc. ........................ 660,000
Bear, Stearns & Co. Inc. ................................... 70,000
Dean Witter Reynolds Inc. .................................. 70,000
Donald & Co., Securities Inc. .............................. 70,000
Forum Capital Markets L.P. ................................. 70,000
Hanifen, Imhoff Inc. ....................................... 70,000
Jefferies & Company, Inc. .................................. 70,000
Morgan Keegan & Company, Inc. .............................. 70,000
Oppenheimer & Co., Inc. .................................... 70,000
Petrie Parkman & Co. ....................................... 70,000
Rauscher Pierce Refsnes, Inc. .............................. 70,000
---------
Total............................................. 4,000,000
=========
</TABLE>
The Underwriting Agreement provides that the obligations of the several
Underwriters to pay for and accept delivery of the shares of Common Stock
offered hereby are subject to the approval of certain legal matters by counsel
and to certain other conditions. The Underwriters are obligated to take and pay
for all of the shares of Common Stock offered hereby (other than those covered
by the over-allotment option described below) if any are taken.
The Underwriters propose to offer part of the shares directly to the public
at the public offering price set forth on the cover page hereof and part to
certain dealers at a price which represents a concession not in excess of $0.48
per share under the public offering price. The Underwriters may allow, and such
dealers may reallow, a concession not in excess on $0.10 per share to certain
other dealers.
Pursuant to the Underwriting Agreement, the Company has granted to the
Underwriters an option, exercisable for 30 days from the date of this
Prospectus, to purchase up to 600,000 additional shares of Common Stock at the
public offering price set forth on the cover page hereof, less underwriting
discounts and commissions. The Underwriters may exercise such option to purchase
solely for the purpose of covering over-allotments, if any, made in connection
with the Common Stock Offering. To the extent such option is exercised, each
Underwriter will become obligated, subject to certain conditions, to purchase
approximately the same percentage of such additional shares as the number set
forth next to such Underwriter's name in the preceding table bears to the total
number of shares of Common Stock offered hereby.
In order to facilitate the Common Stock Offering, the Underwriters may
engage in transactions that stabilize, maintain or otherwise affect the price of
the Common Stock. Specifically, the Underwriters may overallot in connection
with the Common Stock Offering, creating a short position in the Common Stock
for their own account. In addition, to cover overallotments or to stabilize the
price of the Common Stock, the Underwriters may bid for, and purchase, shares of
Common Stock in the open market. Finally, the underwriting syndicate may reclaim
selling concessions allowed to an underwriter or a dealer for distributing the
Common Stock in the Common Stock Offering, if the syndicate repurchases
previously distributed
48
<PAGE> 49
Common Stock in transactions to cover syndicate short positions, in
stabilization transactions or otherwise. Any of these activities may stabilize
or maintain the market price of the Common Stock above independent market
levels. The Underwriters are not required to engage in these activities, and may
end any of these activities at any time.
The Company, each of its directors, certain of its officers and certain
other stockholders of the Company have agreed with the Underwriters not to sell,
offer to sell, grant any option for the sale of or otherwise dispose of any
shares of or enter into any agreement to sell Common Stock for a period of 90
days after the date of this Prospectus without the prior written consent of
Morgan Stanley & Co. Incorporated for the Underwriters, except that the Company
may issue shares of Common Stock and options to purchase Common Stock under its
existing stock purchase and stock option plans or upon conversion or exercise of
currently outstanding convertible securities and warrants. Cometra has agreed
with the Company not to sell or otherwise dispose of the 1,410,106 shares it
received pursuant to the Cometra Acquisition until 45 days after the date of
this Prospectus.
The Company and the Underwriters have agreed to indemnify each other
against certain liabilities, including liabilities under the Securities Act.
LEGAL MATTERS
Certain legal matters with respect to the valid issuance, due
authorization, full payment and nonassessability of the Common Stock offered
hereby will be passed upon for the Company by Vinson & Elkins L.L.P., 2300 First
City Tower, Houston, Texas 77002-6760, and for the Underwriters by Simpson
Thacher & Bartlett (a partnership which includes professional corporations), 425
Lexington Avenue, New York, New York 10017-3909.
EXPERTS
The Consolidated Financial Statements of the Company, as of December 31,
1995 and 1996 and for the three years then ended, included and incorporated by
reference in this Prospectus, have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their reports with respect
thereto included and incorporated by reference in this Prospectus in reliance
upon the authority of said firm as experts in giving said reports.
The statements of revenues and direct operating expenses of the American
Cometra Interests (referred to herein as the Cometra Properties) for the years
ended December 31, 1994, 1995 and 1996, included in the Registration Statement
have been audited by Coopers & Lybrand L.L.P., independent accountants, and are
included herein in reliance upon the authority of that firm as experts in
accounting and auditing.
The financial statements of the Bannon Interests as of December 31, 1995
and for the year then ended, have been incorporated by reference herein and in
the Registration Statement in reliance upon the report of KPMG Peat Marwick LLP,
independent certified public accountants, incorporated by reference herein, and
upon the authority of said firm as experts in accounting and auditing.
Certain information with respect to the gas and oil reserves of the Company
derived from the respective reports of Netherland, Sewell & Associates, Inc.,
Wright & Company, Inc., H. J. Gruy and Associates, Inc., Huddleston & Co., Inc.
and Clay, Holt & Klammer, each of which is a firm of independent petroleum
consultants, has been included and incorporated herein and elsewhere in the
Registration Statement in reliance upon the authority of said firm as experts
with respect to the matters contained in their respective reports.
49
<PAGE> 50
GLOSSARY
The terms defined in this glossary are used throughout this Prospectus.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6
Mcf for each barrel of oil, which reflects the relative energy content.
Development well. A well drilled within the proved area of an oil or natural
gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil or natural gas
in sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce oil or gas in an unproved
area, to find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir, or to extend a known reservoir.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Infill well. A well drilled between known producing wells to better exploit the
reservoir.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6
Mcf for each barrel of oil, which reflects the relative energy content.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
MmBtu. One million British thermal units. One British thermal unit is the heat
required to raise the temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.
Mmcf. One million cubic feet.
Mmcfe. One million cubic feet of natural gas equivalents.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net oil and gas sales. Oil and natural gas sales less oil and natural gas
production expenses.
Present Value. The pre-tax present value, discounted at 10%, of future net cash
flows from estimated proved reserves, calculated holding prices and costs
constant at amounts in effect on the date of the report (unless such prices or
costs are subject to change pursuant to contractual provisions) and otherwise in
accordance with the Commission's rules for inclusion of oil and gas reserve
information in financial statements filed with the Commission.
Productive well. A well that is producing oil or gas or that is capable of
production.
Proved developed non-producing reserves. Reserves that consist of (i) proved
reserves from wells which have been completed and tested but are not producing
due to lack of market or minor completion problems which are expected to be
corrected and (ii) provided reserves currently behind the pipe in existing wells
and which are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves. Proved reserves that can be expected to be
recovered from currently producing zones under the continuation of present
operating methods.
Proved developed reserves. Proved reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
50
<PAGE> 51
Proved reserves. The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.
Royalty interest. An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves after income taxes calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
51
<PAGE> 52
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
NUMBER
------
<S> <C>
LOMAK PETROLEUM, INC. CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Public Accountants.................. F-2
Consolidated balance sheets at December 31, 1995 and
1996................................................... F-3
Consolidated statements of income for the years ended
December 31, 1994, 1995 and 1996....................... F-4
Consolidated statements of stockholders' equity for the
years ended December 31, 1994, 1995 and 1996........... F-5
Consolidated statements of cash flows for the years ended
December 31, 1994, 1995 and 1996....................... F-6
Notes to consolidated financial statements................ F-7
COMETRA INTERESTS FINANCIAL STATEMENTS:
Report of Independent Accountants......................... F-21
Statement of revenues and direct operating expenses for
the years ended December 31, 1994, 1995 and 1996....... F-22
Notes to the statement of revenues and direct operating
expenses............................................... F-23
</TABLE>
F-1
<PAGE> 53
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
The Board of Directors and Stockholders
Lomak Petroleum, Inc.
We have audited the accompanying consolidated balance sheets of Lomak
Petroleum, Inc. (a Delaware corporation) as of December 31, 1995 and 1996, and
the related consolidated statements of income, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1996. 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 Lomak Petroleum, Inc. as of
December 31, 1995 and 1996, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
February 14, 1997
F-2
<PAGE> 54
LOMAK PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1995 1996
-------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and equivalents...................................... $ 3,047 $ 8,625
Accounts receivable....................................... 14,109 18,121
Marketable securities..................................... 953 7,658
Inventory and other....................................... 1,114 799
-------- --------
19,223 35,203
-------- --------
Oil and gas properties, successful efforts method........... 210,073 282,519
Accumulated depletion..................................... (33,371) (53,102)
-------- --------
176,702 229,417
-------- --------
Gas transportation and field service assets................. 23,167 21,139
Accumulated depreciation.................................. (4,304) (4,997)
-------- --------
18,863 16,142
-------- --------
Other....................................................... -- 1,785
-------- --------
$214,788 $282,547
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 9,084 $ 14,433
Accrued liabilities....................................... 3,761 4,603
Accrued payroll and benefit costs......................... 1,762 3,245
Current portion of debt (Note 4).......................... 53 26
-------- --------
14,660 22,307
-------- --------
Long-term debt (Note 4)..................................... 83,035 116,780
Deferred taxes (Note 10).................................... 17,726 25,931
Commitments and contingencies (Note 6)......................
Stockholders' equity (Notes 7 and 8)
Preferred stock, $1 par, 2,000,000 shares authorized,
7 1/2% convertible preferred, 200,000 issued
(liquidation preference $5,000,000).................... 200 --
$2.03 convertible preferred, 1,150,000 issued
(liquidation preference $28,750,000)................... 1,150 1,150
Common stock, $.01 par, 20,000,000 shares authorized,
13,322,738 and 14,750,537 issued....................... 133 148
Capital in excess of par value............................ 101,773 110,248
Retained earnings (deficit)............................... (4,013) 5,291
Unrealized gain on marketable securities.................. 124 692
-------- --------
99,367 117,529
-------- --------
$214,788 $282,547
======== ========
</TABLE>
See accompanying notes.
F-3
<PAGE> 55
LOMAK PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Revenues
Oil and gas sales......................................... $24,461 $37,417 $68,054
Field services............................................ 7,667 10,097 14,223
Gas transportation and marketing.......................... 2,195 3,284 5,575
Interest and other........................................ 471 1,317 3,386
------- ------- -------
34,794 52,115 91,238
------- ------- -------
Expenses
Direct operating.......................................... 10,019 14,930 24,456
Field services............................................ 5,778 6,469 10,443
Gas transportation and marketing.......................... 490 849 1,674
Exploration............................................... 359 512 1,460
General and administrative................................ 2,478 2,736 3,966
Interest.................................................. 2,807 5,584 7,487
Depletion, depreciation and amortization.................. 10,105 14,863 22,303
------- ------- -------
32,036 45,943 71,789
------- ------- -------
Income before taxes......................................... 2,758 6,172 19,449
Income taxes
Current................................................... 21 86 729
Deferred.................................................. 118 1,696 6,105
------- ------- -------
139 1,782 6,834
------- ------- -------
Net income.................................................. $ 2,619 $ 4,390 $12,615
======= ======= =======
Earnings per common share................................... $ 0.25 $ 0.31 $ 0.69
======= ======= =======
Weighted average shares outstanding......................... 9,051 11,841 14,812
======= ======= =======
</TABLE>
See accompanying notes.
F-4
<PAGE> 56
LOMAK PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
PREFERRED STOCK COMMON STOCK
---------------- --------------- CAPITAL IN RETAINED
PAR PAR EXCESS OF EARNINGS
SHARES VALUE SHARES VALUE PAR VALUE (DEFICIT)
------ ------ ------ ----- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1993......... 200 $ 200 8,309 $ 83 $ 41,768 $ (9,788)
Preferred dividends.............. -- -- -- -- -- (375)
Common issued.................... -- -- 1,504 15 9,220 --
Common repurchased............... -- -- (59) (1) (493) --
Net income....................... -- -- -- -- -- 2,619
----- ------ ------ ---- -------- --------
Balance, December 31, 1994......... 200 200 9,754 97 50,495 (7,544)
Preferred dividends.............. -- -- -- -- -- (731)
Common dividends................. -- -- -- -- -- (128)
Common issued.................... -- -- 3,609 36 24,953 --
Common repurchased............... -- -- (40) -- (332) --
$2.03 preferred issued........... 1,150 1,150 -- -- 26,657 --
Net income....................... -- -- -- -- -- 4,390
----- ------ ------ ---- -------- --------
Balance, December 31, 1995......... 1,350 1,350 13,323 133 101,773 (4,013)
Preferred dividends.............. -- -- -- -- -- (2,454)
Common dividends................. -- -- -- -- -- (857)
Common issued.................... -- -- 887 9 8,687 --
Common repurchased............... -- -- (36) -- (406) --
Conversion of 7 1/2% preferred... (200) (200) 577 6 194 --
Net income....................... -- -- -- -- -- 12,615
----- ------ ------ ---- -------- --------
Balance, December 31, 1996......... 1,150 $1,150 14,751 $148 $110,248 $ 5,291
===== ====== ====== ==== ======== ========
</TABLE>
See accompanying notes.
F-5
<PAGE> 57
LOMAK PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operations:
Net income............................................... $ 2,619 $ 4,390 $ 12,615
Adjustments to reconcile net income to net cash provided
by operations:
Depletion, depreciation and amortization.............. 10,105 14,863 22,303
Deferred income taxes................................. 118 1,335 6,105
Changes in working capital net of effects of purchases
of businesses:
Accounts receivable................................. 3,106 (5,247) (494)
Marketable securities............................... (534) (296) (5,264)
Inventory and other................................. (45) 278 137
Accounts payable.................................... (2,126) 663 5,385
Accrued liabilities and payroll and benefit costs... (1,531) 1,778 781
Gain on sale of assets and other...................... (471) (1,203) (3,123)
-------- -------- --------
Net cash provided by operations............................ 11,241 16,561 38,445
Cash flows from investing:
Acquisition of businesses, net of cash................... (9,399) -- (13,950)
Oil and gas properties................................... (22,251) (69,992) (59,137)
Additions to property and equipment...................... (813) (9,102) (1,250)
Proceeds on sale of assets............................... 2,927 2,981 4,671
-------- -------- --------
Net cash used in investing................................. (29,536) (76,113) (69,666)
Cash flows from financing:
Proceeds from indebtedness............................... 22,235 21,304 85,201
Repayments of indebtedness............................... (1,024) (808) (53,268)
Preferred stock dividends................................ (375) (731) (2,454)
Common stock dividends................................... -- (128) (857)
Proceeds from Common stock issuance...................... 830 10,590 8,315
Repurchase of Common stock............................... (493) (332) (138)
Proceeds from Preferred stock issuance................... -- 27,807 --
-------- -------- --------
Net cash provided by financing............................. 21,173 57,702 36,799
-------- -------- --------
Change in cash............................................. 2,878 (1,850) 5,578
Cash and equivalents at beginning of period................ 2,019 4,897 3,047
-------- -------- --------
Cash and equivalents at end of period...................... $ 4,897 $ 3,047 $ 8,625
======== ======== ========
Supplemental disclosures of non-cash investing and
financing activities:
Purchase of businesses, oil and gas property and
equipment financed with common stock.................. $ 7,694 $ 14,299 $ --
Conversion of 10% Convertible Subordinated Notes......... 464 -- --
Common stock issued in connection with benefit plans..... 228 100 381
</TABLE>
See accompanying notes.
F-6
<PAGE> 58
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Lomak Petroleum, Inc. ("Lomak" or the "Company") is an independent oil and
gas company engaged in development, exploration and acquisition primarily in
three core areas: the Midcontinent, Appalachia and the Gulf Coast. Historically,
the Company has increased its reserves and production through acquisitions,
development and exploration of its properties. Over the past six years, 62
acquisitions have been consummated at a total cost of $249 million and
approximately $39 million has been expended on development and exploration
activities. As a result, proved reserves and production have each grown during
this period at compounded rates of 90% and 70% per annum, respectively. At
December 31, 1996, proved reserves totaled 384 Bcfe, having a pre-tax present
value at constant prices on that date of $492 million and a reserve life index
of nearly 14 years.
Effective January 1997, the Company acquired oil and gas properties from
American Cometra, Inc. for a purchase price of $385 million, subject to
adjustment. This transaction is more fully described in Note 15 Cometra
Acquisition.
Lomak's objective is to maximize shareholder value through growth in its
reserves, production, cashflow and earnings through a balanced program of
development drilling and acquisitions, as well as, to a growing extent,
exploration effort. In order to effectively implement its operating strategy,
the Company has concentrated its activities in selected geographic areas. In
each core area, the Company has established separate acquisition, engineering,
geological, operating and other technical expertise. The Company believes that
this geographic focus provides it with a competitive advantage in sourcing and
evaluating new business opportunities within these areas, as well as providing
economies of scale in developing and operating its properties.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying financial statements include the accounts of the Company,
all majority owned subsidiaries and its pro rata share of the assets,
liabilities, income and expenses of certain oil and gas partnerships and joint
ventures. Highly liquid temporary investments with an initial maturity of ninety
days or less are considered cash equivalents.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and
gas properties. Exploratory costs which result in the discovery of reserves and
the cost of development wells are capitalized. Geological and geophysical costs,
delay rentals and costs to drill unsuccessful exploratory wells are expensed.
Depletion is provided on the unit-of-production method. Oil is converted to Mcfe
at the rate of six Mcf per barrel. The depletion rates per Mcfe were $.74, $.73
and $.73 in 1994, 1995 and 1996, respectively. Approximately $4.3 million, $12.2
million and $22.8 million of oil and gas properties were not subject to
amortization as of December 31, 1994, 1995 and 1996, respectively. These costs
are assessed periodically to determine whether their value has been impaired,
and if impairment is indicated, the excess costs are charged to expense.
Effective January 1, 1996, the Company adopted Statement of Financial
Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of," which establishes accounting
standards for the impairment of long-lived assets, certain identifiable
intangibles and goodwill. SFAS No. 121 requires a review for impairment whenever
circumstances indicate that the carrying amount of an asset may not be
recoverable. In performing the review for recoverability, the Company would
estimate future cash flows (undiscounted and without interest charges) expected
to result from the use of an asset and its eventual disposition. Impairment is
recognized only if the carrying amount of an asset is greater
F-7
<PAGE> 59
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
than its expected future cash flows. The amount of the impairment is based on
the estimated fair value of the asset. The initial adoption of SFAS No. 121 had
no impact on the Company.
Gas Imbalances
The Company uses the sales method to account for gas imbalances. Under the
sales method, revenue is recognized based on cash received rather than the
proportionate share of gas produced. Gas imbalances at year end 1996 and 1995
were not material.
Gas Transportation and Field Services Assets
The Company owns and operates approximately 1,900 miles of gas gathering
lines in proximity to its principal gas properties. Depreciation is calculated
on the straight-line method based on estimated useful lives ranging from four to
fifteen years.
The Company receives fees for providing field related services. These fees
are recognized as earned. Depreciation on field service assets is calculated on
the straight-line method based on estimated useful lives ranging from one to six
years, except for buildings which are being depreciated over ten to fifteen year
periods.
During 1996 the majority of the Company's brine disposal and well servicing
activities were based in Oklahoma. In December 1996, the Company sold its brine
disposal and well servicing activities in Oklahoma for $2.7 million and recorded
a gain on sale of approximately $1.2 million which is included in interest and
other income. In 1994, the Company sold substantially all of its brine disposal
and well servicing assets located in Appalachia for approximately $1.8 million.
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 at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Nature of Business
The Company operates in an environment with many financial and operating
risks, including, but not limited to, the ability to find or acquire additional
economically recoverable oil and gas reserves, the inherent risks of the search
for, development of and production of oil and gas, the ability to sell oil and
gas at prices which will provide attractive rates of return, the highly
competitive nature of the industry and worldwide economic conditions. The
Company's ability to expand its reserve base and diversify its operations is
also dependent upon the Company's ability to obtain the necessary capital
through operating cash flow, borrowings or the issuance of additional equity.
Marketable Securities
The Company has adopted Statement of Financial Accounting Standards No.
115, "Accounting for Certain Investments in Debt and Equity Securities." Under
Statement No. 115, debt and marketable equity securities are required to be
classified in one of three categories: trading, available-for-sale, or held to
maturity. The Company's equity securities qualify under the provisions of
Statement No. 115 as available-for-sale. Such securities are recorded at fair
value, and unrealized holding gains and losses, net of the related tax effect,
are reflected as a separate component of stockholders' equity. A decline in the
market value of an available-for-sale security that is deemed other than
temporary is charged to earnings and results in the establishment of a
F-8
<PAGE> 60
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
new cost basis for the security. Realized gains and losses are determined on the
specific identification method and are reflected in income.
Debt Issuance Costs
Expenses associated with the issuance of the 6% Convertible Subordinated
Debentures Due 2007 are included in Other Assets on the accompanying balance
sheet and are being amortized on the interest method over the term of the
debentures.
Earnings per Common Share
Net income per share is computed by subtracting preferred dividends from
net income and dividing by the weighted average number of common and common
equivalent shares outstanding. The calculation of fully diluted earnings per
share assumes conversion of convertible securities when the result would be
dilutive. Outstanding options and warrants are included in the computation of
net income per common share when their effect is dilutive.
Reclassifications
Certain reclassifications have been made to prior period presentation to
conform with current period classifications.
(3) ACQUISITION AND DEVELOPMENT
All of the Company's acquisitions have been accounted for as purchases. The
purchase prices were allocated to the assets acquired based on the fair value of
such assets and liabilities at the respective acquisition dates. The
acquisitions were funded by working capital, advances under a revolving credit
facility and the issuance of equity.
During 1996, the Company acquired oil and gas properties, equipment and
acreage from Bannon Energy, Incorporated for approximately $37.0 million and
acquired Eastern Petroleum Company for approximately $13.7 million. The Bannon
interests included 270 producing properties located in Texas, Oklahoma, New
Mexico and Wyoming. Eastern Petroleum Company owned interests in oil and gas
properties, equipment and acreage in Ohio.
In 1995, the Company acquired oil and gas properties, equipment and acreage
from Transfuel, Inc. for $21 million, which included cash and approximately
$800,000 of Common Stock, and from Parker & Parsley Petroleum Company for $20.2
million. The Transfuel interests included developed and undeveloped properties
in Ohio, Pennsylvania and New York. The Parker & Parsley interests included
developed and undeveloped properties in Pennsylvania and Ohio.
In 1994, the Company acquired Red Eagle Resources Corporation for $46.5
million. Included in this amount were 2.8 million shares of Common Stock valued
at approximately $16.9 million issued to the acquired company's shareholders.
Red Eagle's assets included 370 producing wells, equipment and acreage located
primarily in the Okeene Field of Oklahoma's Anadarko Basin. In addition, the
Company purchased Grand Banks Energy Company for $3.7 million and Gillring Oil
Company for $11.5 million. Grand Bank's assets included interests in 182
producing properties located in west Texas and Gillring's assets included $5.2
million of working capital and interests in 106 producing properties located in
south Texas.
F-9
<PAGE> 61
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Unaudited Pro Forma Financial Information
The following table presents unaudited, pro forma operating results as if
the transactions had occurred at the beginning of each period presented. The pro
forma operating results include the following acquisitions, all of which were
accounted for as purchase transactions; (i) the purchase of certain oil and gas
properties from a subsidiary of Parker & Parsley Petroleum Company (ii) the
purchase of certain oil and gas properties from Transfuel, Inc., (iii) the
purchase of certain oil and gas properties from Bannon Energy Incorporated, (iv)
the private placement of 1.15 million shares of Convertible Preferred Stock and
the application of the net proceeds therefrom and (v) the private placement of
1.8 million shares of Common Stock and (vi) the private placement of $55 million
of 6% Convertible Subordinated Debentures Due 2007 and the application of the
net proceeds therefrom.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1995 1996
---------- ----------
(IN THOUSANDS EXCEPT PER
SHARE DATA)
<S> <C> <C>
Revenues............................................... $ 69,664 $ 92,823
Net income............................................. 6,808 12,481
Earnings per share..................................... 0.31 0.68
Total assets........................................... 252,442 282,547
Stockholders' equity................................... 99,367 117,529
</TABLE>
The pro forma operating results have been prepared for comparative purposes
only. They do not purport to present actual operating results that would have
been achieved had the acquisitions and financings been made at the beginning of
each period presented or to necessarily be indicative of future results of
operations.
(4) INDEBTEDNESS
The Company had the following debt outstanding as of the dates shown.
Interest rates at December 31, 1996 are shown parenthetically:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1995 1996
------- --------
(IN THOUSANDS)
<S> <C> <C>
Bank credit facility (6.7%)................................. $83,035 $ 61,355
6% Convertible Subordinated Debentures Due 2007............. -- 55,000
Other (5.9%-7.0%)........................................... 53 451
------- --------
83,088 116,806
Less amounts due within one year............................ 53 26
------- --------
Long-term debt, net......................................... $83,035 $116,780
======= ========
</TABLE>
The Company maintains a $250 million revolving bank credit facility. The
facility provides for a borrowing base which is subject to semi-annual
redeterminations. At December 31, 1996, the borrowing base on the credit
facility was $150 million. The facility bears interest at prime rate or LIBOR
plus 0.75% to 1.25% depending upon the percentage of the borrowing base drawn.
Interest is payable quarterly and the loan is payable in sixteen quarterly
installments beginning February 1, 1999. A commitment fee of 3/8% of the
undrawn balance is payable quarterly. It is the Company's policy to extend the
term period of the credit facility annually.
As described in Note 15, the revolving bank credit facility was amended and
expanded in connection with the financing of the Cometra Acquisition (the
"Amended Credit Facility"). The Amended Credit Facility is secured by first
priority security interests in (i) existing mortgaged oil and gas properties of
the Company,
F-10
<PAGE> 62
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
including the Cometra Properties, (ii) all accounts receivable, inventory and
intangibles of the Company and the subsidiaries guaranteeing the Amended Credit
Facility, and (iii) all of the capital stock of the Company's direct or indirect
subsidiaries. Substantially all of the assets of the Company will be pledged as
collateral if, on May 15, 1997, the Borrowing Base and amounts outstanding under
the Amended Credit Facility have not been reduced to $325 million. Such security
interests will be released upon the (i) reduction of the amounts outstanding
under the Amended Credit Facility to $325 million (or the then determined
Borrowing Base) and (ii) issuance of $75 million of Common Stock and/or the sale
of Company assets in excess of the Borrowing Base value attributable to such
assets as agreed by the lenders.
The 6% Convertible Subordinated Debentures Due 2007 (the "Debentures") are
convertible at the option of the holder at any time prior to maturity into
shares of the Company's Common Stock, at a conversion price of $19.25 per share,
subject to adjustment in certain events. Interest is payable semi-annually. The
Debentures will mature in 2007 and are not redeemable prior to February 1, 2000.
The Debentures are unsecured general obligations of the Company subordinated to
all senior indebtedness, as defined.
The debt agreements contain various covenants relating to net worth,
working capital maintenance and financial ratio requirements. The Company is in
compliance with these various covenants as of December 31, 1996. Interest paid
during the years ended December 31, 1994, 1995 and 1996 totaled $2.8 million,
$4.9 million and $7.5 million, respectively.
Maturities of indebtedness as of December 31, 1996 were as follows (in
thousands):
<TABLE>
<S> <C>
1997.............................................. $ 26
1998.............................................. 413
1999.............................................. 15,354
2000.............................................. 15,339
2001.............................................. 15,339
Remainder......................................... 70,335
--------
$116,806
========
</TABLE>
(5) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Company's financial instruments include cash and equivalents, accounts
receivable, accounts payable, debt obligations, commodity and interest rate
futures, options and swaps. The book value of cash and equivalents, accounts
receivable and payable and short term debt are considered to be representative
of fair value because of the short maturity of these instruments. The Company
believes that the carrying value of its borrowings under its bank credit
facility approximates their fair value as they bear interest at rates indexed to
LIBOR. The Company's accounts receivable are concentrated in the oil and gas
industry. The Company does not view such a concentration as an unusual credit
risk. The Company has recorded an allowance for doubtful accounts of $306,000
and $450,000 at December 31, 1995 and 1996, respectively.
A portion of the Company's crude oil and natural gas sales are periodically
hedged against price risks through the use of futures, option or swap contracts.
The gains and losses on these instruments are included in the valuation of the
production being hedged in the contract month and are included as an adjustment
to oil and gas revenue. The Company also manages interest rate risk on its
credit facility through the use of interest rate swap agreements. Gains and
losses on swap agreements are included as an adjustment to interest expense.
F-11
<PAGE> 63
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the book value and estimated fair values of
the Company's financial instruments:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 DECEMBER 31, 1996
----------------------- -----------------------
(IN THOUSANDS)
BOOK VALUE FAIR VALUE BOOK VALUE FAIR VALUE
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Cash and equivalents.................... $ 3,047 $ 3,047 $ 8,625 $ 8,625
Marketable securities................... 829 953 6,966 7,658
Long-term debt.......................... (83,088) (83,088) (116,806) (116,806)
Commodity swaps......................... -- 93 -- (1,051)
Interest rate swaps..................... -- 375 -- 81
</TABLE>
At December 31, 1996, the Company had open contracts for oil and gas price
swaps of 300,000 barrels and 155,000 Mcfs. The swap contracts are designed to
set average prices ranging from $22.10 to $22.76 per barrel and $2.04 per Mcf.
While these transactions have no carrying value, their fair value, represented
by the estimated amount that would be required to terminate the contracts, was a
net cost of approximately $1,051,000 at December 31, 1996. These contracts
expire monthly through April 1997. The gains or losses on the Company's hedging
transactions is determined as the difference between the contract price and the
reference price, generally closing prices on the New York Mercantile Exchange.
The resulting transaction gains and losses are determined monthly and are
included in net income in the period the hedged production or inventory is sold.
Net gains or (losses) relating to these derivatives for the years ended December
31, 1994, 1995 and 1996 approximated $-0-, $217,000 and $(724,000),
respectively.
Interest rate swap agreements, which are used by the Company in the
management of interest rate exposure, are accounted for on the accrual basis.
Income and expense resulting from these agreements are recorded in the same
category as expense arising from the related liability. Amounts to be paid or
received under interest rate swap agreements are recognized as an adjustment to
expense in the periods in which they accrue. At December 31, 1996, the Company
had $60 million of borrowings subject to three interest rate swap agreements at
rates of 5.25%, 5.49% and 5.64% through July 1997, October 1997 and October
1998, respectively. The interest rate swaps may be extended at the
counterparties' option for two years. The agreements require that the Company
pay the counterparty interest at the above fixed swap rates and require the
counterparties to pay the Company interest at the 30-day LIBOR rate. The closing
30-day LIBOR rate on December 31, 1996 was 5.53%. The fair value of the interest
rate swap agreements at December 31, 1996, is based upon current quotes for
equivalent agreements.
These hedging activities are conducted with major financial or commodities
trading institutions which management believes entail acceptable levels of
market and credit risks. At times such risks may be concentrated with certain
counterparties or groups of counterparties. The credit worthiness of
counterparties is subject to continuing review and full performance is
anticipated.
(6) COMMITMENTS AND CONTINGENCIES
The Company is involved in various other legal actions and claims arising
in the ordinary course of business. In the opinion of management, such
litigation and claims will be resolved without material adverse effect on the
Company's financial position.
The Company recently received notice from two parties, each of whom claims
that it is entitled to fees from the Company based upon a Yemen oil concession
that they claim Red Eagle Resources Corporation received in August 1992, which
was prior to the acquisition of Red Eagle by the Company. Based upon the
Company's examination of the available documentation relevant to such claims,
the Company believes that the claims are without merit because the claimed oil
concession was never obtained in Yemen. The Company has requested further
documentation from the two parties with respect to their claims but no such
F-12
<PAGE> 64
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
documentation has yet been provided. The claims are for approximately $4.0
million in the aggregate (including the value of approximately 70,000 shares of
Common Stock that would be required to be issued if the oil concession had been
obtained). To date, no proceedings have been commenced with respect to either of
these claims.
The Company leases certain office space and equipment under cancelable and
non-cancelable leases, most of which expire within 10 years and may be renewed
by the Company. Rent expense under such arrangements totaled $202,000, $335,000
and $208,000 in 1994, 1995 and 1996, respectively. Future minimum rental
commitments under non-cancelable leases are as follows (in thousands):
<TABLE>
<S> <C>
1997........................................................ $ 270
1998........................................................ 270
1999........................................................ 233
2000........................................................ 195
2001........................................................ 210
2002 and thereafter......................................... 270
------
$1,448
======
</TABLE>
(7) EQUITY SECURITIES
In 1993, $5,000,000 of 7 1/2% cumulative convertible exchangeable preferred
stock (the "7 1/2% Preferred Stock") was privately placed. In April and May
1996, the Company exercised its option and converted the 7 1/2% Preferred Stock
into 576,945 shares of Common Stock.
In November 1995, the Company sold 1,150,000 shares of $2.03 convertible
exchangeable preferred stock (the "$2.03 Preferred Stock") for $28.8 million.
The $2.03 Preferred Stock is convertible into the Company's Common Stock at a
conversion price of $9.50 per share, subject to adjustment in certain events.
The $2.03 Preferred Stock is redeemable, at the option of the Company, at any
time on or after November 1, 1998, at redemption prices beginning at 105%. At
the option of the Company, the $2.03 Preferred Stock is exchangeable for the
Company's 8 1/8% convertible subordinated notes due 2005. The notes would be
subject to the same redemption and conversion terms as the $2.03 Preferred
Stock.
In December 1995, the Company privately placed 1.2 million shares of its
Common Stock for $10.2 million to a state sponsored retirement plan. In April
1996, the Company privately placed 600,000 shares of its Common Stock to a
limited number of institutional investors for approximately $6.9 million.
Warrants to acquire 40,000 shares of common stock were exercised in October
1996. Additionally, warrants to acquire 20,000 shares of Common Stock at a price
of $12.88 per share were outstanding at December 31, 1996 and will expire in May
1999.
F-13
<PAGE> 65
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(8) STOCK OPTION AND PURCHASE PLAN
The Company maintains a Stock Option Plan which authorizes the grant of
options on up to 2.0 million shares of Common Stock. However, no new options may
be granted which would result in there being aggregate outstanding options
exceeding 10% of the Company's common shares outstanding plus those shares
issuable under convertible securities. Under the plan, incentive and
non-qualified options may be issued to officers, key employees and consultants.
The plan is administered by the Compensation Committee of the Board. All options
issued under the plan vest 30% after one year, 60% after two years and 100%
after three years. The following is a summary of stock option activity:
<TABLE>
<CAPTION>
NUMBER OF OPTIONS EXERCISE
-------------------------------- PRICE RANGE
1994 1995 1996 PER SHARE
------- ------- ---------- -------------
<S> <C> <C> <C> <C>
Outstanding at beginning of year.... 428,983 680,483 977,149 $ 3.38-$ 9.38
Granted............................. 298,500 342,000 378,500 10.50- 13.88
Canceled............................ (16,000) (12,000) (7,950) 7.00- 10.50
Exercised........................... (31,000) (33,334) (115,250) 3.38- 8.25
------- ------- ---------- -------------
Outstanding at end of year.......... 680,483 977,149 1,232,499 $ 3.38-$13.88
======= ======= ========== =============
</TABLE>
In 1994, the stockholders approved the 1994 Outside Directors Stock Option
Plan (the "Directors Plan"). Only Directors who are not employees of the Company
are eligible under the Directors Plan. The Directors Plan covers a maximum of
200,000 shares. At December 31, 1996, 76,000 options were outstanding under the
Directors Plan of which 16,800 were exercisable as of that date. The exercise
price of the options ranges from $7.75 to $13.88 per share.
In 1994, the stockholders approved the 1994 Stock Purchase Plan (the "1994
Plan") which authorizes the sale of up to 500,000 shares of Common Stock to
officers, directors, key employees and consultants. Under the Plan, the right to
purchase shares at prices ranging from 50% to 85% of market value may be
granted. The Company had a 1989 Stock Purchase Plan (the "1989 Plan") which was
identical to the 1994 Plan except that it covered 333,333 shares. Upon adoption
of the 1994 Plan, the 1989 Plan was terminated. The plans are administered by
the Compensation Committee of the Board. During the year ended December 31,
1996, the Company sold 100,000 unregistered shares of Common Stock to officers
and outside directors for an aggregate amount of approximately $966,000.
The Company has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock Based
Compensation." Accordingly, no compensation cost has been recognized for the
stock option plans. Had compensation cost for the Company's two stock option
plans been determined based on the fair value at the grant date for awards in
1995 and 1996 consistent with the provisions of SFAS No. 123, the Company's net
earnings and earnings per share would have been reduced in the pro forma amounts
indicated below:
<TABLE>
<CAPTION>
1995 1996
-------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
<S> <C> <C>
Net earnings--as reported................................... $4,390 $12,615
Earnings per share--as reported............................. $ 0.31 $ 0.69
Net earnings--pro forma..................................... $4,081 $11,996
Earnings per share--pro forma............................... $ 0.28 $ 0.64
</TABLE>
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted-average
assumptions used for grants: dividend yield of 1%; expected volatility of 38%;
risk-free interest rate of 6%; and expected lives of 4 years.
F-14
<PAGE> 66
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(9) BENEFIT PLAN
The Company maintains a 401(k) Plan for the benefit of its employees. The
Plan permits employees to make contributions on a pre-tax salary reduction
basis. The Company makes discretionary contributions to the Plan. Company
contributions for 1994, 1995 and 1996 were $226,000, $346,000 and $548,000,
respectively. The Company has no other employee benefit plans.
(10) INCOME TAXES
Federal income tax expense was $139,000, $1.8 million and $6.8 million for
the years 1994, 1995 and 1996, respectively. The current portion of the income
tax provision represents alternative minimum tax currently payable. A
reconciliation between the statutory federal income tax rate and the Company's
effective federal income tax rate is as follows:
<TABLE>
<CAPTION>
1994 1995 1996
------- ------- --------
<S> <C> <C> <C>
Statutory tax rate................................. 34% 34% 34%
Realization of valuation allowance................. (29) (5) --
Other.............................................. -- -- 1
------- ------- --------
Effective tax rate................................. 5% 29% 35%
======= ======= ========
Income taxes paid.................................. $47,500 $60,000 $590,000
======= ======= ========
</TABLE>
The Company follows FASB Statement No. 109, "Accounting for Income Taxes."
Under Statement 109, the liability method is used in accounting for income
taxes. Under this method, deferred tax assets and liabilities are determined
based on differences between financial reporting and tax bases of assets and
liabilities and are measured using the enacted tax rates and laws that will be
in effect when the differences are expected to reverse.
Significant components of the Company's deferred tax liabilities and assets
are as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1995 1996
------- -------
<S> <C> <C>
Deferred tax liabilities:
Depreciation.............................................. $29,130 $31,726
======= =======
Deferred tax assets:
Net operating loss carryforwards.......................... 6,193 2,625
Percentage depletion carryforward......................... 4,388 2,589
AMT credits and other..................................... 863 621
------- -------
Total deferred tax assets................................. 11,444 5,835
Valuation allowance for deferred tax assets................. (40) (40)
------- -------
Net deferred tax assets..................................... $11,404 $ 5,795
======= =======
Net deferred tax liabilities................................ $17,726 $25,931
======= =======
</TABLE>
Due to uncertainty as to the company's ability to realize the tax benefit,
a valuation allowance was established for the full amount of the net deferred
tax assets. In 1995, income taxes were reduced from the statutory rate of 34% by
approximately $0.3 million through realization of a portion of the valuation
allowance, resulting in $40,000 of the allowance remaining at each of December
31, 1995 and 1996.
The Company has entered into several business combinations accounted for as
purchases. In connection with these transactions, deferred tax assets and
liabilities of $7.7 million and $23.8 million, respectively, were
F-15
<PAGE> 67
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
recorded. In 1996 the Company acquired Eastern Petroleum Company in a taxable
business combination accounted for as a purchase. A net deferred tax liability
of $2.1 million was recorded in the transaction.
As a result of the Company's issuance of equity and convertible debt
securities, it experienced a change in control during 1988 as defined by Section
382 of the Internal Revenue Code. The change in control placed limitations to
the utilization of net operating loss carryovers. At December 31, 1996, the
Company had available for federal income tax reporting purposes net operating
loss carryovers of approximately $7.5 million which are subject to annual
limitations as to their utilization and otherwise expire between 1997 and 2010,
if unused. The Company has alternative minimum tax net operating loss carryovers
of $6.6 million which are subject to annual limitations as to their utilization
and otherwise expire from 1997 to 2009 if unused. The Company has statutory
depletion carryover of approximately $3.2 million and an alternative minimum tax
credit carryover of approximately $500,000. The statutory depletion carryover
and alternative minimum tax credit carryover are not subject to limitation or
expiration.
(11) MAJOR CUSTOMERS
The Company markets its oil and gas production on a competitive basis. The
type of contract under which gas production is sold varies but can generally be
grouped into three categories: (a) life-of-the-well; (b) long-term (1 year or
longer); and (c) short-term contracts which may have a primary term of one year,
but which are cancelable at either party's discretion in 30-120 days.
Approximately 60% of the Company's gas production is currently sold under market
sensitive contracts which do not contain floor price provisions. For the year
ended December 31, 1996, no one customer accounted for more than 10% of the
Company's total oil and gas revenues. Management believes that the loss of any
one customer would not have a material adverse effect on the operations of the
Company. Oil is sold on a basis such that the purchaser can be changed on 30
days notice. The price received is generally equal to a posted price set by the
major purchasers in the area. The Company sells to oil purchasers on a basis of
price and service.
(12) OIL AND GAS ACTIVITIES
The following summarizes selected information with respect to oil and gas
producing activities:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties:
Subject to amortization.......................... $129,082 $197,826 $259,681
Not subject to amortization...................... 4,291 12,247 22,838
-------- -------- --------
Total.................................... 133,373 210,073 282,519
Accumulated depletion amortization............... (20,409) (33,371) (53,102)
-------- -------- --------
Net oil and gas properties............... $112,964 $176,702 $229,417
======== ======== ========
Costs incurred:
Acquisition...................................... $ 59,501 $ 69,244 $ 63,579
Development...................................... 9,518 9,968 12,536
Exploration...................................... 192 216 2,025
-------- -------- --------
Total costs incurred..................... $ 69,211 $ 79,428 $ 78,140
======== ======== ========
</TABLE>
(13) RELATED PARTY TRANSACTIONS
Mr. Edelman, Chairman of the Company, is also a shareholder of Snyder Oil
Corporation ("SOCO"), and, until February 1996 was an executive officer of SOCO.
At December 31, 1996, Mr. Edelman owned 5.7%
F-16
<PAGE> 68
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of the Company's Common Stock. In 1995, the Company acquired SOCO's interest in
certain wells located in Appalachia for $4 million. The price was determined
based on arms-length negotiations through a third-party broker retained by SOCO.
Subsequent to the transaction, the Company and SOCO no longer held interests in
any of the same properties.
During 1995, the Company incurred fees of $145,000, to the Hawthorne
Company in connection with acquisitions. Mr. Aikman, a director of the Company,
is an executive officer and a principal owner of the Hawthorne Company. The fees
were consistent with those paid by the Company to third parties for similar
services.
(14) UNAUDITED SUPPLEMENTAL RESERVE INFORMATION
The Company's proved oil and gas reserves are located in the United States.
Proved reserves are those quantities of crude oil and natural gas which, upon
analysis of geological and engineering data, can with reasonable certainty be
recovered in the future from known oil and gas reservoirs. Proved developed
reserves are those proved reserves which can be expected to be recovered from
existing wells with existing equipment and operating methods. Proved undeveloped
oil and gas reserves are proved reserves that are expected to be recovered from
new wells on undrilled acreage.
Quantities of Proved Reserves
<TABLE>
<CAPTION>
CRUDE OIL NATURAL GAS
--------- -----------
(BBLS) (MCF)
(IN THOUSANDS)
<S> <C> <C>
Balance, December 31, 1993.................................. 4,539 74,563
Revisions................................................. 15 630
Extensions, discoveries and additions..................... 15 6,605
Purchases................................................. 4,599 75,698
Sales..................................................... (79) (1,130)
Production................................................ (640) (6,996)
------ -------
Balance, December 31, 1994.................................. 8,449 149,370
Revisions................................................. 255 (3,513)
Extensions, discoveries and additions..................... 475 10,076
Purchases................................................. 2,618 90,575
Sales..................................................... (21) (1,150)
Production................................................ (913) (12,471)
------ -------
Balance, December 31, 1995.................................. 10,863 232,887
Revisions................................................. 280 (7,545)
Extensions, discoveries and additions..................... 952 16,696
Purchases................................................. 3,884 86,022
Sales..................................................... (236) (11,235)
Production................................................ (1,068) (21,231)
------ -------
Balance, December 31, 1996.................................. 14,675 295,594
====== =======
Proved developed reserves:
December 31, 1994......................................... 6,430 97,251
====== =======
December 31, 1995......................................... 8,880 174,958
====== =======
December 31, 1996......................................... 10,703 207,601
====== =======
</TABLE>
F-17
<PAGE> 69
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The "Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement
under Statement of Financial Accounting Standards No. 69 "Disclosures about Oil
and Gas Producing Activities". The Standardized Measure does not purport to
present the fair market value of proved oil and gas reserves. This would require
consideration of expected future economic and operating conditions, which are
not taken into account in calculating the Standardized Measure.
Future cash inflows were estimated by applying year end prices to the
estimated future production less estimated future production costs based on year
end costs. Future net cash inflows were discounted using a 10% annual discount
rate to arrive at the Standardized Measure.
Standardized Measure
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------
1994 1995 1996
----------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows........................... $ 457,048 $ 729,566 $1,393,338
Future costs:
Production.................................. (133,972) (256,374) (365,753)
Development................................. (52,102) (60,554) (86,192)
----------- --------- ----------
Future net cash flows......................... 270,974 412,638 941,393
Income taxes.................................. (59,950) (102,108) (271,023)
----------- --------- ----------
Total undiscounted future net cash flows...... 211,024 310,530 670,370
10% discount factor........................... (91,475) (136,480) (319,481)
----------- --------- ----------
Standardized measure.......................... $ 119,549 $ 174,050 $ 350,889
=========== ========= ==========
</TABLE>
Changes in Standardized Measure
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------
1994 1995 1996
----------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year....... $ 53,751 $ 119,549 $ 174,050
Revisions:
Prices...................................... 4,224 (4,100) 151,508
Quantities.................................. 2,240 2,267 (6,762)
Estimated future development costs.......... -- (5,238) (2,971)
Accretion of discount....................... 6,512 15,054 22,924
Income taxes................................ (19,624) (24,200) (86,095)
----------- --------- ----------
Net revisions............................ (6,648) (16,217) 78,604
Purchases..................................... 84,836 87,741 125,871
Extensions, discoveries and additions......... 2,402 7,419 22,816
Production.................................... (14,442) (22,487) (43,598)
Sales......................................... (350) (1,955) (6,854)
----------- --------- ----------
Standardized measure, end of year............. $ 119,549 $ 174,050 $ 350,889
=========== ========= ==========
</TABLE>
F-18
<PAGE> 70
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(15) COMETRA ACQUISITION
Effective January 1, 1997, the Company acquired oil and gas properties
located in West Texas, South Texas and the Gulf of Mexico (the "Cometra
Properties") from American Cometra, Inc. ("Cometra") for a purchase price of
$385 million, subject to adjustment (the "Cometra Acquisition"). The Cometra
Acquisition increases the Company's proforma proved reserves at December 31,
1996 by 68% to 644 Bcfe and increases its Present Value by 98% to $974 million.
The Cometra Properties, located primarily in the Company's core operating areas,
include 515 producing wells, and additional development and exploration
potential on approximately 150,000 gross acres (90,000 net acres). In addition,
the Cometra Properties include gas pipelines, a 25,000 Mcf/d gas processing
plant and an above-market gas contract with a major Texas gas utility covering
approximately 30% of the current production from the Cometra Properties.
The Company will finance the cash portion of the purchase price with $221
million of borrowings through expansion of its bank credit facility (the
"Amended Credit Facility") and the issuance to Cometra of a $134 million
non-interest bearing promissory note due March 31, 1997, which is secured by a
bank letter of credit. The promissory note will be repaid at maturity through
borrowings under the Amended Credit Facility. The Amended Credit Facility will
enable the Company to obtain revolving credit loans and issue letters of credit
from time to time in an aggregate amount not to exceed $400 million initially.
Availability under the Amended Credit Facility will be reduced to $300 million
on the earlier of August 13, 1997 or the consummation of the Offerings, unless
otherwise agreed to by the lenders.
The Amended Credit Facility provides for a Borrowing Base which is subject
to semi-annual determinations and certain other redeterminations. The Amended
Credit Facility is secured by first priority security interests in (i) existing
mortgaged oil and gas properties of the Company, including the Cometra
Properties, (ii) all accounts receivable, inventory and intangibles of the
Company and the Bank Guarantors, and (iii) all of the capital stock of the
Company's direct or indirect subsidiaries. Substantially all assets of the
Company will be pledged as collateral, if, on May 15, 1997 the Borrowing Base
and amounts outstanding under the Credit Agreement have not been reduced to $325
million. Such security interests will be released upon the (i) reduction of the
amount outstanding under the Amended Credit Facility to $325 million (or the
then determined Borrowing Base) and (ii) issuance of $65 million of Common Stock
and/or sale of Company assets in excess of the Borrowing Base value attributable
to such assets as agreed by the Lenders (the "Trigger Event").
The Amended Credit Facility bears interest at either the Alternate Base
Rate (as defined) plus a margin ranging from 0% to 0.25% or the Eurodollar loan
rate plus a margin ranging from 0.625% to 1.125%. Interest is payable quarterly
and the Amended Credit Facility matures in February 2002.
The Amended Credit Facility includes various covenants that require, among
other things, that the Company (i) maintain a minimum consolidated tangible net
worth of at least $100 million plus 90% of the net proceeds from the Common
Stock offering described below and 50% of the net proceeds from any subsequent
equity offering; (ii) maintain a ratio of EBITDA to consolidated interest
expense on total debt for each period of four consecutive fiscal quarters of at
least 2.5 to 1.0; and (iii) not make restricted payments (defined as dividends,
distributions or guarantees to third parties or the retirement, repurchase or
prepayment prior to the scheduled maturity of its subordinated debt) in an
aggregate amount in any one fiscal year in excess of $5 million plus 50% of the
net proceeds from equity offerings subsequent to the Common Stock offering
described below and 50% of the Company's consolidated net income earned after
January 1, 1997. In addition, the Amended Credit Facility will restrict the
ability of the Company to dispose of assets, incur additional indebtedness,
repay other indebtedness or amend other debt instruments, create liens on
assets, make investments or acquisitions, engage in mergers or consolidations,
make capital expenditures or engage in certain transactions with affiliates.
In January 1997, the Company filed a registration statement with the
Securities and Exchange Commission. As amended, the registration statement
covers the sale of 4 million shares of Common Stock and $125 million aggregate
principal amount of ten year senior subordinated notes. The proceeds from the
F-19
<PAGE> 71
LOMAK PETROLEUM, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
offerings will be used to repay indebtedness from the Cometra Acquisition. The
notes will be guaranteed by all of the subsidiaries of the Company and each
guarantor is a wholly owned subsidiary of the Company. The guarantees are full,
unconditional and joint and several, and separate financial statements of each
guarantor are not presented because they are included in the consolidated
financial statements of the Company and management has concluded that they
provide no additional benefits.
Unaudited Pro Forma Financial Information
The following table presents unaudited pro forma operating results as if
the Cometra Acquisition had occurred as of January 1, 1996. The pro forma
operating results also include the following acquisitions, all of which were
accounted for as purchase transactions: (i) the purchase of certain oil and gas
properties from Bannon Energy Incorporated, (ii) the private placement of
600,000 shares of Common Stock, (iii) the private placement of $55 million of 6%
Convertible Subordinated Debentures Due 2007 and the application of the net
proceeds therefrom and (iv) the conversion of the Company's 7 1/2% Convertible
Exchangeable Preferred Stock into Common Stock. Additionally, the unaudited pro
forma operating results give effect to the sale of 4 million shares of Common
Stock and $125 million aggregate principal amount of ten year senior
subordinated notes.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1996
(IN THOUSANDS) ------------
<S> <C>
Revenues:
Oil and gas sales......................................... $130,508
Field services............................................ 14,223
Gas transportation and marketing.......................... 24,326
Interest and other........................................ 3,386
--------
172,443
--------
Expenses:
Direct operating.......................................... 39,394
Field services............................................ 10,443
Gas transportation and marketing.......................... 13,152
Exploration............................................... 1,460
General and administrative................................ 3,966
Interest.................................................. 30,957
Depletion, depreciation and amortization.................. 44,389
--------
143,761
--------
Earnings before income taxes................................ 28,682
Income taxes................................................ 10,038
--------
Net income.................................................. $ 18,644
========
Earnings per common share................................... $ 0.80
========
BALANCE SHEET DATA (AT DECEMBER 31, 1996):
Cash and equivalents........................................ $ 8,625
Total assets................................................ 671,597
Long-term debt, including current portion................... 411,756
Stockholders' equity........................................ 211,629
</TABLE>
F-20
<PAGE> 72
REPORT OF INDEPENDENT ACCOUNTANTS
The Board of Directors and Stockholders
Lomak Petroleum, Inc.:
We have audited the accompanying statements of revenues and direct
operating expenses of the American Cometra Interests, as described in Note 1,
for the years ended December 31, 1994, 1995 and 1996. These financial statements
are the responsibility of 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.
The accompanying statements of revenues and direct operating expenses
reflect the revenues and direct operating expenses attributable to the American
Cometra Interests, as described in Note 1, and are not intended to be a complete
presentation of the revenues and expenses of the American Cometra Interests.
In our opinion, the statements referred to above present fairly the
revenues and direct operating expenses of the American Cometra Interests, as
described in Note 1, for the years ended December 31, 1994, 1995 and 1996, in
conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Fort Worth, Texas
February 7, 1997
F-21
<PAGE> 73
THE AMERICAN COMETRA INTERESTS
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1994 1995 1996
------------ ------------ -----------------
<S> <C> <C> <C>
Revenues:
Oil and gas production....................... $ 46,808,830 $ 43,513,982 $ 60,751,200
Marketing and gas plant operating activities
(net)..................................... 3,370,500 5,276,900 7,273,100
------------ ------------ ------------
Total revenues.......................... 50,179,330 48,790,882 68,024,300
Direct operating expenses...................... (14,447,533) (12,727,532) (14,375,900)
------------ ------------ ------------
Excess of revenues over operating
expenses............................. $ 35,731,797 $ 36,063,350 $ 53,648,400
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-22
<PAGE> 74
THE AMERICAN COMETRA INTERESTS
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES
1. GENERAL:
Organization
The accompanying statements present the revenues and direct operating
expenses of certain working and other interests in oil and gas properties and
the Sterling gas plant and related pipeline owned by American Cometra, Inc. (the
"American Cometra Interests") which were purchased by Lomak Petroleum, Inc.
("Lomak"). Such financial statements were derived from the historical records of
the predecessor owner and represent Lomak's interest.
Basis of Presentation
The historical financial statements reflecting financial position, results
of operations and cash flows required by generally accepted accounting
principles are not presented, as such information is neither readily available
on an individual property basis nor meaningful for the American Cometra
Interests. During the periods presented, the American Cometra Interests were not
accounted for as a separate entity. These statements do not include
depreciation, depletion and amortization, general and administrative, interest,
federal income tax expenses, or federal income tax credits allowed under Section
29 of the Internal Revenue Code. Accordingly, the accompanying financial
statements are not intended to be a complete presentation of the results of
operations of the American Cometra Interests in conformity with generally
accepted accounting principles.
Revenue Recognition
Revenues are recognized when oil and gas production is sold. Direct
operating expenses are accrued when services are provided. Netted against
marketing and gas plant operating activities is $9,758,300, $7,700,000 and
$11,478,400 for the years ended December 31, 1994, 1995 and 1996, respectively,
relating to costs associated with those activities.
Use of Estimates
Management has made a number of estimates and assumptions relating to the
reporting of the revenues and direct operating expenses to prepare these
financial statements in conformity with generally accepted accounting
principles. Actual results could differ from those estimates.
2. SALES TO MAJOR CUSTOMERS:
For the years ended December 31, 1994, 1995 and 1996 four purchasers
accounted for 33%, 54% and 74% of total revenues, respectively.
3. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED):
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Exploration................................................. $14,154 $ 3,986 $ 1,124
Development................................................. 11,753 12,759 14,976
</TABLE>
OIL AND GAS RESERVE INFORMATION
The estimates of the American Cometra Interests in proved oil and gas
reserves, which are located entirely in the United States, are based on
evaluations by an independent petroleum engineer, Netherland, Sewell &
Associates as of December 31, 1996. These reserves were estimated in accordance
with guidelines established by the Securities and Exchange Commission which
require that reserve reports be prepared under existing economic and operating
conditions with no provision for price escalations except by contractual
F-23
<PAGE> 75
THE AMERICAN COMETRA INTERESTS
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES -- (CONTINUED)
3. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED), CONTINUED:
OIL AND GAS RESERVE INFORMATION, CONTINUED:
arrangements. Reserves as of December 31, 1994 and 1995 were derived from the
December 31, 1996 reserve estimates after considering production and drilling
activities.
Lomak's management emphasizes that reserve estimates are inherently
imprecise. Accordingly, the estimates are expected to change as future
information becomes available.
The following unaudited table sets forth the estimated proved oil and gas
reserve quantities of the American Cometra Interests at December 31, 1994, 1995
and 1996:
<TABLE>
<CAPTION>
CRUDE OIL NATURAL GAS
(BBLS) (MCFS)
--------- -----------
(IN THOUSANDS)
<S> <C> <C>
PROVED RESERVES:
Balance, December 31, 1993................................ 10,107 194,508
Production............................................. (404) (14,372)
Purchases.............................................. -- 1,294
Extensions, discoveries, renewals...................... 505 12,683
Sales.................................................. -- --
------ -------
Balance, December 31, 1994................................ 10,208 194,113
Production............................................. (626) (15,212)
Purchases.............................................. 93 1,502
Extensions, discoveries, renewals...................... 24 9,210
Sales.................................................. (14) --
------ -------
Balance, December 31, 1995................................ 9,685 189,613
Production............................................. (803) (16,124)
Extensions, discoveries, renewals...................... 848 28,516
------ -------
Balance, December 31, 1996................................ 9,730 202,005
====== =======
PROVED DEVELOPED RESERVES:
Balance, December 31, 1994................................ 5,062 97,269
====== =======
Balance, December 31, 1995................................ 4,550 93,398
====== =======
Balance, December 31, 1996................................ 4,595 103,749
====== =======
</TABLE>
The "Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement
under Statement of Financial Accounting Standards No. 69. The Standardized
Measure does not purport to present the fair market value of proved oil and gas
reserves. This would require consideration of expected future economic and
operating conditions, which are not taken into account in calculating the
Standardized Measure.
Future net cash flows for the periods presented were derived from the
December 31, 1996 reserve estimate after considering historical production and
drilling activities. December 31, 1996 prices in the reserve estimates were
adjusted for fixed and determinable escalations to the estimated future
production less estimated future production costs based on period-end costs and
future development costs. Future net cash inflows were discounted using a 10%
annual discount rate to arrive at the Standardized Measure. Future income tax
estimates are not included, as the historical tax basis of the properties is not
relevant.
F-24
<PAGE> 76
THE AMERICAN COMETRA INTERESTS
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES -- (CONTINUED)
3. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED), CONTINUED:
OIL AND GAS RESERVE INFORMATION, CONTINUED:
The standardized measure of discounted future net cash flows relating to
proved oil and gas properties is as follows:
<TABLE>
<CAPTION>
AS OF AS OF AS OF
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1994 1995 1996
------------ ------------ -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows............................ $1,207,887 $1,179,424 $1,156,858
Future costs:
Production................................... (243,413) (232,040) (219,098)
Development.................................. (99,353) (92,534) (88,350)
---------- ---------- ----------
Future net cash flows.......................... 865,121 854,850 849,410
Income taxes................................... -- -- --
---------- ---------- ----------
Undiscounted future net cash flows............. 865,121 854,850 849,410
10% discount factor............................ (444,749) (408,382) (367,919)
---------- ---------- ----------
Standardized measure........................... $ 420,372 $ 446,468 $ 481,491
========== ========== ==========
</TABLE>
Changes in standardized measure of discounted future net cash flows from
proved reserve quantities are as follows:
<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1994 1995 1996
------------ ------------ -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year........ $ 395,914 $ 420,372 $ 446,468
Purchases...................................... 627 1,228 --
Extensions, discoveries, additions............. 17,730 15,051 38,185
Production..................................... (33,490) (32,141) (47,809)
Sales.......................................... -- (79) --
Accretion of discount.......................... 39,591 42,037 44,647
--------- --------- ---------
Standardized measure, end of year.............. $ 420,372 $ 446,468 $ 481,491
========= ========= =========
</TABLE>
F-25
<PAGE> 77
Lomak Logo
