<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
{x} ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1996
{ } TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transaction period from _______ to _______
COMMISSION FILE NUMBER 0-9592
LOMAK PETROLEUM, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 34-1312571
(State of incorporation) (I.R.S. Employer
Identification No.)
500 THROCKMORTON STREET, FT. WORTH, TEXAS 76102
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (817) 870-2601
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
PREFERRED STOCK, $1 PAR VALUE
(Title of class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes x No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. {X}
The aggregate market value of voting stock of the Registrant held by
non-affiliates (excluding voting shares held by officers and directors) was
$398,718,000 on March 17, 1997.
Indicate the number of shares outstanding of each of the Registrant's
classes of stock on March 17, 1997: Common Stock $.01 par value: 20,272,242;
Preferred Stock $1 par value: 1,150,000.
DOCUMENTS INCORPORATED BY REFERENCE:
Part III of this report incorporates by reference the Registrant's Proxy
Statement relating to the Registrant's 1997 Annual Meeting of Stockholders.
<PAGE> 2
LOMAK PETROLEUM, INC.
ANNUAL REPORT ON FORM 10-K
YEAR ENDED DECEMBER 31, 1996
PART I
ITEM 1. BUSINESS
GENERAL
Lomak Petroleum, Inc. ("Lomak" or the "Company") is an independent oil
and gas company engaged in the development, exploration and acquisition of oil
and gas properties in the United States. Lomak's core areas of operation are
located in Midcontinent, the Gulf Coast and Appalachia. The Company has grown
through a combination of development, exploration and acquisition activities.
Since January 1, 1991, 62 acquisitions have been consummated at a total cost of
approximately $250 million and approximately $40 million has been expended on
development and exploration activities. As a result, reserves and production
have each grown during this period at a rate in excess of 69% per annum. At
December 31, 1996, proved reserves totaled 384 Bcfe, having a pre-tax present
value at constant prices of $492 million and a reserve life of nearly 14 years.
At December 31, 1996, Lomak held interests in 6,761 gross (5,187 net)
productive oil and gas wells. The Company currently operates over 6,500 wells
which account for more than 95% of its developed reserves. In addition, the
Company owns and operates approximately 1,900 miles of gas gathering systems in
proximity to its principal gas properties. The Company also provides oil field
services, including brine disposal and various well services primarily for
certain of its own properties. The operations of the Company are considered to
fall within a single industry segment; the exploration for, development and
production of crude oil and natural gas.
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"). On a pro forma basis, the Cometra Acquisition increases
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. Forward looking statements included
hereafter will include the effects of the Cometra Acquisition.
The Company's common stock is listed on the New York Stock Exchange
("NYSE") under the symbol "LOM". During 1996, trading volume averaged 117,600
shares per day. The Company maintains its corporate headquarters at 500
Throckmorton Street, Fort Worth, Texas 76102 and its telephone number is (817)
870-2601.
<PAGE> 3
DESCRIPTION OF THE BUSINESS
Strategy
The Company's objective is to continue to increase its asset base,
cash flow and earnings through a balanced strategy of development, exploration
and acquisition activities in core operating areas. In each core area, the
Company establishes separate acquisition, engineering, operating, geological and
other technical expertise. The Company currently has core operating areas in
Midcontinent, the Gulf Coast and Appalachia. Through its strategy, the Company
does not depend solely on any one region or activity to grow its asset base. In
addition, by operating in three core areas, the Company has expanded its
development, exploration and acquisition opportunities.
Development. The Company's development activities include
recompletions of existing wells, infield drilling and installation of secondary
recovery projects. Development projects are generated within core operating
areas where the Company has significant operational and technical experience. At
December 31, 1996, including the effect of the Cometra Acquisition, over 1,100
proven development projects were in inventory. These projects are geographically
diverse, vary between oil and gas, and are balanced with regard to risk. Between
175 and 200 of these projects are expected to be initiated in 1997 at a total
cost of approximately $45 million. Based on the number of projects currently in
inventory, development expenditures are currently projected to approximate $130
million for the next three years.
Exploration. Historically, the Company's drilling activities
concentrated on development drilling in its core operating areas. Beginning in
1994, the Company began participating in exploration projects in less developed
or lightly explored formations within its core operating areas. The Company has
an inventory of nearly 300 moderate risk/moderate reward exploitation drilling
opportunities, as well as higher risk/higher reward exploration projects. The
Company's existing inventory of exploration projects and leads varies in risk
and reward based on their depth, location and geology. Lomak has identified 250
exploitation drilling projects principally consisting of step-out drilling from
existing proved or proved undeveloped locations. 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. Lomak's strategy is based upon 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 projects exploitation and exploratory expenditures
to range between $6 million and $7 million in 1997 and currently estimates that
it will spend $25 million on exploitation activities and $20 million on
exploration activities over the next three years.
Acquisitions. Since January 1, 1991, including the Cometra
Acquisition, 63 acquisitions have been completed for a total consideration of
$635 million. Approximately 719 Bcfe of proved reserves have been acquired at an
average cost of $.74 per Mcfe. The Company's acquisition strategy has
historically been based on: (i) Locale: focusing in areas containing many small
oil and gas operators and where larger companies are no longer active; (ii)
Efficiency: targeting acquisitions in which operating and cost efficiencies can
be obtained; (iii) Reserve Potential: pursuing properties with the potential for
reserve increases through recompletions and drilling; (iv) Incremental
Purchases: seeking acquisitions where opportunities for purchasing additional
interests in the same or adjoining properties exist; and (v) Complexity:
pursuing more complex but less competitive corporate or partnership
acquisitions.
3
<PAGE> 4
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 $130 million over the next three
years for development.
Exploration Activities
The Company has an inventory of nearly 300 moderate risk/moderate
reward exploitation drilling opportunities, as well as higher risk/higher reward
exploration projects. Lomak has identified 250 exploitation drilling projects,
principally consisting of step-out drilling from existing proved or proved
undeveloped locations. 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.
4
<PAGE> 5
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.
Acquisition Activities
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>
Number of Purchase Price (1) MMcfe Cost per
Period Transactions (In thousands) Acquired Mcfe (2)
- ---------- ------------ ------------------ -------- -----------
<S> <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
============ =============== ============ ============
<FN>
(1) Includes purchase price for proved reserves as well as other acquired
assets, including gas gathering lines, undeveloped leasehold 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.
</TABLE>
5
<PAGE> 6
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.
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.
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. On March 14, 1997, $186.1 million of
the bank borrowings were repaid through the issuance of 4 million shares of
Common Stock and $125 million of Senior Subordinated Notes.
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.
6
<PAGE> 7
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
Amount Oil & NGLs Natural Gas Gas Equiv.
(In 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 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.
7
<PAGE> 8
GAS PLANT 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.
Production
Production revenue is generated through the sale of oil and gas from
properties held directly and through partnerships and joint ventures. Additional
revenue is received from royalties. While oil and gas production is sold to a
limited number of purchasers, none accounts for more than 10% of oil and gas
revenues, it is believed that the loss of any one of them would not have a
material adverse effect on the business. Proximity to local markets,
availability of competitive fuels and overall supply and demand are factors
affecting the ability to market production. While the Company anticipates an
upward trend in energy prices, factors outside its control such as political
developments in the Middle East, overall energy supply, weather conditions and
economic growth rates have had, and may continue to have, an unpredictable
effect on energy prices.
The following table sets forth historical revenue and expense
information for the periods indicated (in thousands, except average sales price
and operating cost data).
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------------
1992 1993 1994 1995 1996
----------- ------------ ----------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Production
Oil (Bbl) ........ 199 318 640 913 1,068
Gas (Mcf) ........ 1,796 2,590 6,996 12,471 21,231
Mcfe (a) ......... 2,990 4,498 10,836 17,949 27,641
Revenues
Oil .............. $ 3,660 $ 5,118 $ 9,743 $15,133 $20,425
Gas .............. 4,043 6,014 14,718 22,284 47,629
======= ======= ======= ======= =======
Total ........ $ 7,703 $11,132 $24,461 $37,417 $68,054
======= ======= ======= ======= =======
Average Sales Price
Oil (Bbl) ........ $ 18.40 $ 16.07 $ 15.23 $ 16.57 $ 19.12
Gas (Mcf) ........ $ 2.25 $ 2.32 $ 2.10 $ 1.79 $ 2.24
Mcfe (a) ......... $ 2.58 $ 2.47 $ 2.26 $ 2.08 $ 2.46
Average Operating Cost
Per Mcfe ......... $ 0.99 $ 0.98 $ 0.93 $ 0.83 $ 0.88
<FN>
(a) Oil is converted to Mcfe at a rate of 6 Mcf per barrel.
</TABLE>
On a Mcfe basis, approximately 77% of 1996 production was natural gas.
Gas production was sold to utilities, brokers or directly to industrial users.
Gas sales are made pursuant to various arrangements ranging from month-to-month
contracts, one year contracts at fixed or variable prices and contracts at fixed
prices for the life of the well. All contracts other than the fixed price
contracts contain provisions for price adjustment, termination and other terms
customary in the industry. A number of the Appalachian gas contracts hold
favorable sales prices when compared to spot market prices. 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. Oil purchasers are selected on the basis of price and service. In 1996,
revenues from oil and gas production amounted to $68.1 million, representing 75%
of revenues. Oil and gas revenues for 1996 increased 82% over 1995.
8
<PAGE> 9
Field Services
The field services area is comprised of three components -- well
operations, brine disposal and well servicing. As of December 31, 1996, Lomak
acted as operator of, or provided pumping services for, over 6,500 wells. For
its well operations, the Company receives a monthly fee plus reimbursement of
third party charges. In September 1994 , the Company sold substantially all of
its brine disposal and well servicing assets located in Ohio. During 1996 the
majority of the Company's brine disposal and well servicing activities are
carried out in Oklahoma. In January 1997, the Company completed the sale of its
brine disposal and well servicing activities in Oklahoma.
In total, field services provided revenues of $14.2 million in 1996,
representing 16% of total revenues. Field service revenues for 1996 increased
41% over the prior year.
Gas Transportation and Marketing
The gas transportation and marketing revenues are comprised of fees for
the transportation of production through gathering lines and income from
marketing of oil and gas.
The Company's natural gas gathering and processing assets are primarily
comprised of (i) its Sterling system obtained through the Cometra Acqusition,
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.
In order to handle more efficiently the sale of its natural gas, the
Company began to market its own gas production in 1993. Including activities of
the Cometra properties, 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. Including production from the Cometra Properties,
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, however, it currently anticipates that such
percentage would not exceed 50%. Although these hedging activities provide the
Company some protection against falling prices, these activities also reduce the
potential benefits to the Company of price increases above the levels of the
hedges.
9
<PAGE> 10
Interest and Other
The Company earns interest on its cash and investment accounts, as well
as on various notes receivable. Other income in 1996 was comprised principally
of gains on sales of marketable equity securities and gains on sales of
non-strategic properties. The Company expects to continue to sell assets which
have no strategic benefit. Interest and other income in 1996 amounted to $3.4
million, representing 4% of total revenues. Revenues from interest and other for
1996 increased 157% from the 1995 level.
COMPETITION
The Company encounters substantial competition in acquiring properties,
marketing oil and gas, securing personnel and conducting its field services
operations. Many competitors have financial and other resources which
substantially exceed those of the Company. The competitors in acquisitions,
development, exploration and production include the major oil companies in
addition to numerous independents, individual proprietors and others. 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 permit. The ability of the Company to
replace and expand its reserve base in the future will be dependent upon its
ability to select and acquire suitable producing properties and prospects for
future drilling.
The Company's acquisitions have been partially financed through
issuances of equity and debt securities and internally generated cash flow. The
competition for capital to finance oil and gas acquisitions and drilling is
intense. The ability of the Company to obtain such financing is uncertain and
can be affected by numerous factors beyond its control. The inability of the
Company to raise capital in the future could have an adverse effect on certain
areas of its business.
GOVERNMENTAL REGULATION
The Company's operations are affected from time to time in varying
degrees by political developments and federal, state and local laws and
regulations. In particular, oil and natural gas production and related
operations are or have been subject to price controls, taxes and other laws and
regulations relating to the oil and gas industry. Failure to comply with such
laws and regulations can result in substantial penalties. The regulatory burden
on the oil and natural gas industry increases the Company's cost of doing
business and affects its profitability. Although the Company believes it is in
substantial compliance with all applicable laws and regulations, because such
laws and regulations are frequently amended or reinterpreted, the Company is
unable to predict the future cost or impact of complying with such laws and
regulations.
ENVIRONMENTAL MATTERS
The Company's oil and natural gas exploration, development, production
and pipeline gathering operations are subject to stringent federal, state and
local laws governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental
departments such as the Environmental Protection Agency ("EPA") issue
regulations to implement and enforce such laws which are often difficult and
costly to comply with and which carry substantial civil and criminal penalties
for failure to comply. These laws and regulations may require the acquisition of
a permit before drilling commences, restrict the types, quantities and
concentrations of various substances that can be released into the environment
in connection with drilling, production and pipeline gathering activities, limit
or prohibit drilling activities on certain lands lying within wilderness,
wetlands, frontier and other protected areas, require some form of remedial
action to prevent pollution from former operations, such as plugging abandoned
wells, and impose substantial liabilities for pollution resulting from the
Company's operations. In addition, these laws, rules and regulations may
restrict the rate of oil and natural gas production below the rate that would
otherwise exist. The regulatory burden on the oil and gas industry increases the
cost of doing business and consequently affects its profitability. Changes in
environmental laws and regulations
10
<PAGE> 11
occur frequently, and any changes that result in more stringent and costly waste
handling, disposal or clean-up requirements could adversely affect the Company's
operations and financial position, as well as the oil and gas industry in
general. While management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and the Company has
not experienced any material adverse effect from compliance with these
environmental requirements, there is no assurance that this will continue in the
future.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances at the site
where the release occurred. Under CERCLA, such persons may be subject to joint
and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damages allegedly caused by the release of hazardous substances or
other pollutants into the environment. Furthermore, although petroleum,
including crude oil and natural gas, is exempt from CERCLA, at least two courts
have ruled that certain wastes associated with the production of crude oil may
be classified as "hazardous substances" under CERCLA and thus such wastes may
become subject to liability and regulation under CERCLA. State initiatives to
further regulate the disposal of oil and natural gas wastes are also pending in
certain states, and these various initiatives could have a similar impact on the
Company.
Stricter standards in environmental legislation may be imposed in the
oil and gas industry in the future. For instance, legislation has been proposed
in Congress from time to time that would reclassify certain oil and natural gas
exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent handling, disposal and clean-up
restrictions. 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. Compliance with environmental requirements generally
could have a material adverse effect upon the capital expenditures, earnings or
competitive position of the Company. Although the Company has not experienced
any material adverse effect from compliance with environmental requirements, no
assurance may be given that this will continue in the future.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of produced waters and other oil and
gas wastes into navigable waters. Permits must be obtained to discharge
pollutants to state and federal waters. The FWPCA and analogous state laws
provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and
may impose substantial potential liability for the costs of removal, remediation
and damages. State water discharge regulations and the federal (NPDES) permits
prohibit or are expected to prohibit within the next year the discharge of
produced water and sand, and some other substances related to the oil and gas
industry, to coastal waters. Although the costs to comply with zero discharge
mandated under federal or state law may be significant, the entire industry will
experience similar costs and the Company believes that these costs will not have
a material adverse impact on the Company's financial condition and results of
operations. Some oil and gas exploration and production facilities are required
to obtain permits for their storm water discharges. Costs may be incurred in
connection with treatment of wastewater or developing storm water pollution
prevention plans.
The Resources Conservation and Recovery Act ("RCRA"), as amended,
generally does not regulate most wastes generated by the exploration and
production of oil and natural gas. RCRA specifically excludes from the
definition of hazardous waste "drilling fluids, produced waters, and other
wastes associated with the exploration, development, or production of crude oil,
natural gas or geothermal energy." However, these wastes may be regulated by the
EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such
as paint wastes, waste solvents, laboratory wastes and waste compressor
11
<PAGE> 12
oils, are regulated as hazardous wastes. Although the costs of managing solid
hazardous waste may be significant, the Company does not expect to experience
more burdensome costs than similarly situated companies involved in oil and gas
exploration and production.
In addition, the U.S. Oil Pollution Act ("OPA") requires owners and
operators of facilities that could be the source of an oil spill into "waters of
the United States" (a term defined to include rivers, creeks, wetlands and
coastal waters) to adopt and implement plans and procedures to prevent any spill
of oil into any waters of the United States. OPA also requires affected facility
owners and operators to demonstrate that they have at least $35 million in
financial resources to pay for the costs of cleaning up an oil spill and
compensating any parties damaged by an oil spill. Substantial civil and criminal
fines and penalties can be imposed for violations of OPA and other environmental
statutes.
EMPLOYEES
As of December 31, 1996, the Company had approximately 300 full time
employees, of whom 190 were field personnel. None are covered by a collective
bargaining agreement and management believes that its relationship with its
employees is good.
ITEM 2. PROPERTIES
On December 31, 1996, including the Cometra Properties the Company held
working interests in 7,280 gross (5,586 net) productive oil and gas wells and
royalty interests in 310 additional wells. The properties contained, net to the
Company's interest, estimated proved reserves of 498 Bcf of gas and 24 million
barrels of oil or a total of 644 Bcfe. The Company also held interests in
902,700 gross (628,700 net) undeveloped acres at year end.
PROVED 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 NGL's (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.
12
<PAGE> 13
The following table sets forth as of 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 cost and price factors on December 31, 1996. Average product prices in effect
at December 31, 1996 were $23.58 per barrel of oil and $3.54 per Mcf of gas and
pro forma product prices in effect at December 31, 1996 were $23.23 per barrel
of oil and $3.99 per Mcf of gas. There can be no assurance that the proved
reserves will be developed within the periods indicated or that prices and costs
will remain constant. There are numerous uncertainties inherent in estimating
reserves and related information and different reservoir engineers often arrive
at different estimates for the same properties. No estimates of reserves have
been filed with or included in reports to another federal authority or agency
since December 31, 1996. The following is a table of estimated cash flows at
December 31, 1996, including the Cometra properties.
<TABLE>
<CAPTION>
Developed Undeveloped Total
----------------- ----------------- -----------------
(in thousands)
<S> <C> <C> <C>
Future net cash flow from estimated
production of proved reserves
1997.................................. $ 133,587 $ (12,490) $ 121,097
1998.................................. 235,187 17,183 252,370
1999.................................. 357,784 57,514 415,298
Remainder............................. 412,146 589,857 1,002,003
================= ================= =================
Total................................. $ 1,138,704 $ 652,064 $ 1,790,768
================= ================= =================
Present value
Pre-tax............................... $ 658,121 $ 315,541 $ 973,663
================= ================= =================
After-tax............................. N.A. N.A. $ 665,035
================= ================= =================
</TABLE>
SIGNIFICANT PROPERTIES
At December 31, 1996, on a pro forma basis, 98% of the Company's
reserves were located in the Midcontinent, the Gulf Coast and Appalachian
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.
13
<PAGE> 14
<TABLE>
<CAPTION>
Present Value
--------------------- Natural
Amount Oil & NGLs Natural Gas Gas Equiv.
(In thousands) % (Mbbls) (Mmcfe) (Mmcf)
------------ ------- ---------- ---------- -----------
<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.
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.
14
<PAGE> 15
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.
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 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.
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.
15
<PAGE> 16
PRODUCTION
The following table sets forth production information for the preceding
five years (in thousands, except average sales price and operating cost data).
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------------
Pro Forma
1992 1993 1994 1995 1996 1996
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Production
Oil and NGL's (Bbl) ... 199 318 640 913 1,068 1,890
Gas (Mcf) ............. 1,796 2,590 6,996 12,471 21,231 38,157
Mcfe (a) .............. 2,990 4,498 10,836 17,949 27,641 49,497
Revenues
Oil ................... $ 3,660 $ 5,118 $ 9,743 $ 15,133 $ 20,425 $ 35,506
Gas ................... 4,043 6,014 14,718 22,284 47,629 95,002
-------- -------- -------- -------- -------- --------
Total ................. $ 7,703 $ 11,132 $ 24,461 $ 37,417 $ 68,054 $130,508
Direct operating expenses 3,019 4,438 10,019 14,930 24,456 39,394
-------- -------- -------- -------- -------- --------
Gross margin ............ $ 4,684 $ 6,694 $ 14,442 $ 22,487 $ 43,598 $ 91,114
======== ======== ======== ======== ======== ========
Average sales price
Oil (Bbl) ............. $ 18.40 $ 16.07 $ 15.23 $ 16.57 $ 19.12 $ 18.79
Gas (Mcf) ............. $ 2.25 $ 2.32 $ 2.10 $ 1.79 $ 2.24 $ 2.49
Mcfe (a) .............. $ 2.58 $ 2.47 $ 2.26 $ 2.08 $ 2.46 $ 2.64
Average operating expense
per Mcfe .............. $ 0.99 $ 0.98 $ 0.93 $ 0.83 $ 0.88 $ 0.80
<FN>
(a) Oil is converted to Mcfe at a rate of 6 Mcf per barrel, based upon relative energy content.
</TABLE>
PRODUCING WELLS
The following table sets forth certain information relating to
productive wells at December 31, 1996, including the Cometra Properties. 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>
Crude 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 acreage
held at December 31, 1996, including the Cometra Properties.
<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>
16
<PAGE> 17
DRILLING RESULTS
The following table summarizes 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>
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.
17
<PAGE> 18
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.
REAL PROPERTY
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.
ITEM 3. 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
18
<PAGE> 19
PART II
ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED MATTERS
The Company's Common Stock is listed on NYSE under the symbol
"LOM". Prior to listing on the NYSE, the Common Stock was listed on the Nasdaq
National Market under the symbol "LOMK". During 1996, trading volume averaged
117,600 shares per day. The stock prices below are based on the last trade
price. On March 17, 1997, the closing price of the Common Stock was $18.25. To
date in 1997, trading volume has averaged 217,200 shares per day. 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 Average Daily
High Low Dividends Volume
----------- ----------- ----------- ---------------
(shares)
1996
----
<S> <C> <C> <C> <C>
Fourth Quarter..................... $17.375 $13.125 $ .02 102,140
Third Quarter...................... 14.875 12.750 .02 97,380
Second Quarter..................... 15.500 11.625 .01 92,400
First Quarter...................... 12.125 9.560 .01 133,800
1995
----
Fourth Quarter..................... $7.500 $5.500 $ .01 92,000
Third Quarter...................... 9.250 7.250 - 80,700
Second Quarter..................... 8.188 7.250 - 111,500
First Quarter...................... 7.375 5.500 - 57,800
</TABLE>
DIVIDENDS
Dividends on the Common Stock were initiated in December 1995 and have
been paid 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.
The payment of dividends is subject to declaration by the Board of
Directors and may depend on earnings, capital expenditures and market factors
existing from time to time. The Amended Credit Facility and the Indenture for
the 6% Convertible Subordinated Debenture Due 2007 and 8.75% Senior Subordinated
Notes due 2007 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.
HOLDERS OF RECORD
At March 17, 1997, the number of holders of record of the Common Stock,
and $2.03 Convertible Preferred Stock were approximately 4,300 and 2,
respectively.
19
<PAGE> 20
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial information covering
the preceding five years.
<TABLE>
<CAPTION>
As of or for the Year Ended December 31, Pro Forma
---------------------------------------------------- ---------
1992 1993 1994 1995 1996 1996
------- ------ ------ ------ ------ ------
(In thousands, except per share data)
OPERATIONS
<S> <C> <C> <C> <C> <C> <C>
Revenues..............................$ 13,895 $ 19,075 $ 34,794 $ 52,115 $ 91,238 $172,443
Net income............................ 686 1,391 2,619 4,390 12,615 18,644
Earnings per common share............. .08 .18 .25 .31 .69 .80
BALANCE SHEET
Working capital......................$ 167 $ 1,350 $ 1,002 $ 4,563 $ 12,896 $ 12,896
Oil and gas properties, net........... 18,599 55,310 112,964 176,702 229,417 554,417
Total assets.......................... 28,328 76,333 141,768 214,788 282,547 671,597
Long-term debt (a).................... 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
<FN>
(a) Long-term debt includes current portion
</TABLE>
The following table sets forth summary unaudited financial information
on a quarterly basis for the past two years (in thousands, except per share
data).
<TABLE>
<CAPTION>
1995
-------------------------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
----------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
Revenues............................ $ 10,903 $ 11,588 $ 12,136 $ 17,488
Net income.......................... 795 1,026 897 1,672
Earnings per common share........... .07 .08 .07 .10
Total assets........................ 151,801 157,222 203,305 214,788
Long-term debt (a).................. 66,835 71,635 113,238 83,088
Stockholders' equity................ 57,701 58,884 60,554 99,367
1996
-------------------------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
----------- ------------- ------------- ------------
Revenues............................ $20,513 $22,774 $22,312 $25,639
Net income.......................... 2,603 2,780 2,719 4,513
Earnings per common share........... 0.14 0.15 0.14 0.26
Total assets........................ 232,207 274,041 284,152 282,547
Long-term debt (a).................. 95,116 119,380 121,905 116,806
Stockholders' equity................ 101,146 110,762 112,866 117,529
<FN>
(a) Long-term debt includes current portion.
</TABLE>
The total of the earnings per share for each quarter does not equal the
earnings per share for the full year, either because the calculations are based
on the weighted average shares outstanding during each of the individual
periods, or due to rounding.
20
<PAGE> 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FACTORS EFFECTING FINANCIAL CONDITION AND LIQUIDITY
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.
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.
21
<PAGE> 22
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, for the three years ending 1999. For the next
three years, development and exploration expenditures are currently expected to
consume roughly 50% of internally generated cash flows. The remaining funds will
be available for acquisitions and other capital 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 bank credit facility. 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 was
initially $400 million, was reduced to $300 million upon the consummation of the
Offerings. 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 is required to make a mandatory prepayment of all
amounts outstanding under the Credit Agreement in excess of $300 million. 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. Security
obligations in place with the Credit Agreement were released upon the
consummation of the Offerings on March 14, 1997.
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%.
On March 17, 1997, approximately $204 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.
Common Stock and Notes Offering
On March 14, 1997, the Company completed a 4,060,000 million share
Common stock offering (the "Common Offering") and a $125 million aggregate
principal amount of its 8.75% Senior Subordinated Notes due 2007 (the "Notes
Offering")(collectively the "Offerings"). The Notes are 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 contains 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.
22
<PAGE> 23
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.
INFLATION AND CHANGES IN PRICES
The Company's revenues and the value of its oil and gas properties have
been and will be affected by changes in oil and gas prices. The Company's
ability to maintain current borrowing capacity and to obtain additional capital
on attractive terms is also substantially dependent on oil and gas prices. Oil
and gas prices are subject to significant seasonal and other fluctuations that
are beyond the Company's ability to control or predict. During 1996, the Company
received an average of $19.12 per barrel of oil and $2.24 per Mcf of gas.
Although certain of the Company's costs and expenses are affected by the level
of inflation, inflation did not have a significant effect in 1996. Should
conditions in the industry improve, inflationary cost pressures may resume.
23
<PAGE> 24
RESULTS OF OPERATIONS
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 76 Mmcfe/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.
24
<PAGE> 25
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.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to the Index to Financial Statements on page 29 for a
listing of the Company's financial statements and notes thereto and for
supplementary schedules. Schedules I, III, IV, V, VI, VII, VIII, IX, X, XI, XII
and XIII have been omitted as not required or not applicable or because the
information required to be presented is included in the financial statements and
related notes.
25
<PAGE> 26
MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS
The financial statements have been prepared by management in conformity
with generally accepted accounting principles. Management is responsible for the
fairness and reliability of the financial statements and other financial data
included in this report. In the preparation of the financial statements, it is
necessary to make informed estimates and judgments based on currently available
information on the effects of certain events and transactions.
The Company maintains accounting and other controls which management
believes provide reasonable assurance that financial records are reliable,
assets are safeguarded, and that transactions are properly recorded. However,
limitations exist in any system of internal control based upon the recognition
that the cost of the system should not exceed benefits derived.
The Company's independent auditors, Arthur Andersen LLP, are engaged to
audit the financial statements and to express an opinion thereon. Their audit is
conducted in accordance with generally accepted auditing standards to enable
them to report whether the financial statements present fairly, in all material
respects, the financial position and results of operations in accordance with
generally accepted accounting principles.
ITEM 9. CHANGE IN ACCOUNTANTS AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
26
<PAGE> 27
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
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 elected for a one-year term at the
Company's 1997 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
Danny M. 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.
27
<PAGE> 28
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 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.
28
<PAGE> 29
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
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.
The Lomak Board has established three committees to assist in the discharge
of its responsibilities.
AUDIT COMMITTEE. The Audit Committee reviews the professional services
provided by Lomak's independent public accountants and the independence of such
accountants from management of Lomak. This Committee also reviews the scope of
the audit coverage, the annual financial statements of Lomak and such other
matters with respect to the accounting, auditing and financial reporting
practices and procedures of Lomak as it may find appropriate or as have been
brought to its attention. Messrs. Aikman, Dub and Guill members of the Audit
Committee.
COMPENSATION COMMITTEE. The Compensation Committee reviews and approves
executive salaries and administers bonus, incentive compensation and stock
option plans of Lomak. This Committee advises and consults with management
regarding pensions and other benefits and significant compensation policies and
practices of Lomak. This Committee also considers nominations of candidates for
corporate officer positions. The members of Compensation committee are Messrs.
Aikman, Guill and Finkelson.
29
<PAGE> 30
EXECUTIVE COMMITTEE. The Executive Committee reviews and authorizes actions
required in the management of the business and affairs of Lomak, which would
otherwise be determined by the Board, where it is not practicable to convene the
full Board. One of the principal responsibilities of the Executive Committee
will be to review and approve smaller acquisitions. The members of the Executive
Committee are Messrs. Edelman, Finkelson and Pinkerton.
ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
Information with respect to executive compensation is incorporated
herein by reference to the Proxy Statement for its 1997 annual meeting of
stockholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information with respect to security ownership of certain beneficial
owners and management is incorporated herein by reference to the Company's Proxy
Statement for its 1997 annual meeting of stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information with respect to certain relationships and related
transactions is incorporated herein by reference to the Company's Proxy
Statement for its 1997 annual meeting of stockholders.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements and Financial Statement
Schedules. The items listed in the accompanying index to
financial statements are filed as part of this Annual Report
on Form 10-K.
3. Exhibits.
The items listed on the accompanying index to exhibits are
filed as part of this Annual Report on Form 10-K.
(b) Reports on Form 8-K.
The Company's Current Report on Form 8-K, dated April 19,
1996, as amended by Form 8-K/A, dated May 31, 1996.
The Company's Current Report on Form 8-K, dated February 26,
1997, as amended by Form 8-K/A, dated March 14, 1997.
(c) Exhibits required by Item 601 of Regulation S-K.
Exhibits required to be filed by the Company pursuant to Item
601 of Regulation S-K are contained in Exhibits listed in
response to Item 14 (a)3, and are incorporated herein by
reference.
(d) Financial Statement Schedules Required by Regulation S-X.
The items listed in the accompanying index to financial
statements are filed as part of this Annual Report on Form
10-K.
30
<PAGE> 31
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE COMPANY HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Dated: March 21, 1997
LOMAK PETROLEUM, INC.
By: /s/ John H. Pinkerton
------------------------------
John H. Pinkerton
President
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE PERSONS ON BEHALF OF THE COMPANY AND IN
THE CAPACITIES AND ON THE DATES INDICATED.
<TABLE>
<S> <C>
/s/ Thomas J. Edelman Thomas J. Edelman,
- -------------------------------------------- Chairman and Chairman of the Board
March 21, 1997
/s/ John H. Pinkerton John H. Pinkerton,
- -------------------------------------------- Chief Executive Officer, President and Director
March 21, 1997
/s/ Thomas W. Stoelk Thomas W. Stoelk,
- -------------------------------------------- Chief Financial Officer and Vice President-Finance
March 21, 1997
/s/ John R. Frank John R. Frank,
- -------------------------------------------- Chief Accounting Officer and Controller
March 21, 1997
/s/ Robert E. Aikman Robert E. Aikman, Director
- --------------------------------------------
March 21, 1997
/s/ Allen Finkelson Allen Finkelson, Director
- --------------------------------------------
March 21, 1997
/s/ Anthony V. Dub Anthony V. Dub, Director
- --------------------------------------------
March 21, 1997
/s/ Ben A. Guill Ben A. Guill, Director
- --------------------------------------------
March 21, 1997
/s/ C. Rand Michaels C. Rand Michaels,
- -------------------------------------------- Vice Chairman and Director
March 21, 1997
</TABLE>
31
<PAGE> 32
LOMAK PETROLEUM, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(ITEM 14[a], [d])
<TABLE>
<CAPTION>
Page
Number
------
<S> <C>
Reports of Independent Public Accountants 33
Consolidated balance sheets at December 31, 1995 and 1996 34
Consolidated statements of income for the years ended December 31, 1994, 1995 and 1996 35
Consolidated statements of stockholders' equity for the years ended December 31, 1994, 1995 and 1996 36
Consolidated statements of cash flows for the years ended December 31, 1994, 1995 and 1996 37
Notes to consolidated financial statements 38
</TABLE>
Exhibits
All other schedules have been omitted since the required information is
not present in amounts sufficient to require submission of the schedule, or
because the information required is included in the financial statements or
footnotes.
32
<PAGE> 33
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 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 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
33
<PAGE> 34
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, 4,000,000 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, 35,000,000 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.
34
<PAGE> 35
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.
35
<PAGE> 36
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 1/2preferred.. (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.
36
<PAGE> 37
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
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 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.
37
<PAGE> 38
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
company engaged in development, exploration and acquisition primarily in three
core areas: Midcontinent, the Gulf Coast and Appalachia. 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 compound 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 of
approximately 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 than its expected
future cash flows. The amount of the
38
<PAGE> 39
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 SERVICE 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 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 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, and
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 obtaining the necessary capital through operating cash flow,
borrowings or the issuance of additional equity.
MARKETABLE SECURITIES
The Company 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 below cost that is deemed other
than temporary is charged to earnings and results in the establishment of a new
cost basis for the security. Realized gains and losses are determined on the
specific identification method and are reflected in income.
39
<PAGE> 40
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 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 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.
40
<PAGE> 41
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 by the Company of
certain oil and gas properties from a subsidiary of Parker & Parsley Petroleum,
Co., (ii) the purchase by the Company of certain oil and gas properties from
Transfuel, Inc., (iii) the purchase by the Company 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.......... - 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 of 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.
41
<PAGE> 42
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, 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 and 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 $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 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.
42
<PAGE> 43
The following table sets forth the book value and estimated fair values
of the Company's financial instruments:
<TABLE>
<CAPTION>
December 31, December 31,
1995 1996
------------------------------- -------------------------------
(In thousands)
Book Fair Book Fair
Value Value Value 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, is 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 requires the
counterparty 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.
43
<PAGE> 44
(6) COMMITMENTS AND CONTINGENCIES
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 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.
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 1996,
the Company exercised it's 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.
44
<PAGE> 45
(8) STOCK OPTION AND PURCHASE PLAN
The Company maintains a Stock Option Plan which authorizes the grant of
options of up to 2.0 million shares of Common Stock. However, no new options may
be granted which would result in their being outstanding aggregate 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 Per
1994 1995 1996 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 pricing 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 Corporation'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 to 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>
45
<PAGE> 46
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.
(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 employment 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>
46
<PAGE> 47
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 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.
47
<PAGE> 48
(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 his resignation in February 1997, was an
executive officer of SOCO. At December 31, 1996, Mr. Edelman owned 5.7% 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 third-party broker retained by SOCO. Subsequent
to the transaction, the Company and SOCO no longer hold 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.
48
<PAGE> 49
(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)
-------------- ----------------
Proved developed reserves 14,675 295,594
============== ================
December 31, 1994............................................. 6,430 97,251
============== ================
December 31, 1995............................................. 8,880 174,958
============== ================
December 31, 1996............................................. 10,703 207,601
============== ================
</TABLE>
49
<PAGE> 50
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>
As of 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 cost............. - (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>
50
<PAGE> 51
(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 pro forma 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 was reduced to $300 million upon
the consummation of the Offerings. The Amended Credit Facility provides for a
Borrowing Base which is subject to semi-annual determinations and certain other
redeterminations. Security obligations in place with the Credit Agreement were
released upon the consummation of the Offerings on March 14, 1997.
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 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. On March 14, 1997, the
Offerings were consummated with the Company receiving proceeds of approximately
$186 million, after deducting underwriting discounts and estimated expenses. The
proceeds from the Offerings were used to repay indebtedness incurred under the
Amended Credit Facility in connection with 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.
51
<PAGE> 52
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 by the Company of
certain oil and gas properties from Bannon Energy Incorporated, (ii) the private
placement of 600,000 shares of Common Stock and (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.
UNAUDITED PRO FORMA FINANCIAL INFORMATION-CONTINUED
<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 ...................................... 411,756
Stockholders' equity................................. 211,629
</TABLE>
52
<PAGE> 53
LOMAK PETROLEUM, INC.
INDEX TO EXHIBITS
(Item 14[a 3])
Exhibit No. Description
- ----------- -----------
3.1(a) Certificate of Incorporation of Lomak dated March 24,
1980.(1)
3.1(b) Certificate of Amendment of Certificate of Incorporation
dated July 22, 1981.(1)
3.1(c) Certificate of Amendment of Certificate of Incorporation
dated September 8, 1982.(1)
3.1(d) Certificate of Amendment of Certificate of Incorporation
dated December 28, 1988.(1)
3.1(e) Certificate of Amendment of Certificate of Incorporation
dated August 31, 1989.(1)
3.2 Current By-Laws of Lomak.(1)
4 Specimen certificate of Lomak Petroleum, Inc. Common
Stock.(1)
10.1(a) Financial Restructuring Agreement dated September 29, 1988
between Lomak and Snyder Oil Corporation ("SOCO").(1)
10.1(b) Loan Agreement dated September 29, 1988 between Lomak
Petroleum (Ohio), Inc., SOCO and MBank Fort Worth N.A. and
Second Amendments thereto.(1)
10.1(c) Purchase and Sale Agreement dated February 28, 1989 between
Lomak Petroleum (Ohio), Inc., Snyder Operating Partnership
L.P. and Snyder Oil Partners L.P.(1)
10.1(d) Incentive and Non-Qualified Stock Option Plan dated March
13, 1989.(1)
10.1(e) Advisory Agreement dated September 29, 1988 between Lomak
and SOCO.(1)
10.1(f) 401(k) Plan Document and Trust Agreement effective January
1, 1989.(1)
10.1(g) 1989 Stock Purchase Plan.(1)
10.1(h) Purchase Agreement dated as of May 31, 1990 by and between
Ameritrust Company National Association and Lomak
[Incorporated by reference to Lomak's Form 8-K dated May
31, 1990].(2)
10.1(i) Securities Purchase Agreement dated February 21, 1991 by
and among the Company, Latoka and the selling securities
holders of Latoka. (3)
10.1(j) Asset Purchase Agreement dated February 28, 1991 between
the Company and Latoka. (1)
53
<PAGE> 54
10.1(k) Proxies from Latoka Shareholders.(1)
10.1(l) Lease Agreement dated September 1, 1986 between Three
Lincoln Centre - A Joint Venture and Strong Corporation.(4)
10.1(m) Strong 1986-A Ltd., Agreement of Limited Partnership.(4)
10.1(n) Strong 1986-A Ltd. Certificate of Limited Partnership.(4)
10.1(o) Letter Agreement dated December 4, 1987 regarding
$600,000.00 loan by Latoka, Inc., as borrower, to Premier
Bank, as lender.(4)
10.1(p) Promissory Note dated December 4, 1987 regarding
$600,000.00 loan by Latoka, Inc., as borrower, to Premier
Bank, as lender.(4)
10.1(q) Estoppel Certificate of Borrower dated December 4, 1987
regarding $600,000.00 loan by Latoka, Inc., as borrower, to
Premier Bank, as lender.(4)
10.1(r) Collateral Mortgage and Collateral Chattel Mortgage Note,
Pledge Agreement and Collateral Mortgage and Collateral
Mortgage dated December 4, 1987 regarding $600,000.00 loan
by Latoka, Inc., as borrower, to Premier Bank, as
lender.(4)
10.1(s) Form for Deed of Trust, Security Agreement and Financing
Statement (with Assignment of Production) dated December 4,
1987 regarding $600,000.00 loan by Latoka, Inc., as
borrower, to Premier Bank, as lender.(4)
10.1(t) Modification Agreement dated June 24, 1988 between Premier
Bank, N.A. and Latoka, Inc.(4)
10.1(u) Form of Warrant Agreement issued by Xenda Corporation.(5)
10.1(v) Underwriters Warrant dated as of February 25, 1988 between
Xenda Corporation and Capital First Securities, Inc. (5)
10.1(w) Selling and Agency Agreement effective May 15, 1989 between
MLB Investments, Ltd., and Latoka.(6)
10.1(x) Letter Agreement dated September 20, 1989 between MLB
Investments, Ltd., and Latoka.(6)
10.1(y) Letter Agreement dated May 17, 1989 between the Company and
SOCO extending option period.(7)
10.1(z) Purchase and Sale Agreement, dated as of June 20, 1991,
between the Company and Taconic.(7)
10.1(aa) Amended and Restated Stock Purchase Agreement, dated as of
November 20, 1990, between Sparton Corporation, SOCO and
the Company.(7)
10.1(bb) Purchase and Sale Agreement, dated as of March 14, 1991,
between Michigan Oil Company and Albercan Oil Corporation
("Albercan").(7)
10.1(cc) Share Purchase and Sale Agreement, dated March 14, 1991,
among SOCO, the Company and Albercan.(7)
54
<PAGE> 55
10.1(dd) Purchase and Sale Agreement, date March 15, 1993 between
the Company and Valley Resources, Inc.(8)
10.1(ee) Purchase and Sale Agreement, dated March 15, 1993 between
the Company and Valley Oil and Gas, a Partnership.(8)
10.1(ff) Loan Agreement dated May 25, 1993 between the Company and
Bank One, Texas, N.A.(9)
10.1(gg) Amendment dated August 8, 1993 to Loan Agreement dated May
25, 1993 between the Company and Bank One, Texas, N.A.(9)
10.1(hh) Letter of Intent, dated September 20, 1993 between the
Company and Mark Resources Corporation.(9)
10.1(ii) Acquisition Agreement, dated October 16, 1993, among the
Company, the Shareholders and Option Holders named therein,
and Mark Resources Corporation.(10)
10.1(jj) Form of Consulting Agreement between the Company and Peter
M. Mark.(11)
10.1(kk) Amendment dated November 12, 1993 to Loan Agreement dated
May 25, 1993 between the Company and Bank One, Texas,
N.A.(11)
10.1(ll) Form of Directors Indemnification Agreement (12)
10.1(mm) Acquisition Agreement dated as of February 8, 1994 among
the Company, the Shareholders named therein and Grand Banks
Energy Company (13)
10.1(nn) Amendment dated March 7, 1994 to Loan May 25, 1993
Agreement dated between the Company and Bank One, Texas,
N.A. (14)
10.1(oo) 1994 Outside Directors Stock Option Plan. (15)
10.1(pp) 1994 Stock Option Plan. (15)
10.1(qq) Amended and Restated Revolving Credit and Term Loan
Agreement dated July 6, 1994 between Lomak Petroleum, Inc.
and Bank One, Texas N.A. and Texas Commerce Bank National
Association. (16)
10.1(rr) First Amendment to Amended and Restated Revolving Credit
and Term Loan Agreement dated October 20, 1994 between
Lomak Petroleum, Inc. and Bank One Texas, N.A. and Texas
Commerce Bank National Association. (16)
10.1(ss) Agreement and Plan of Merger dated as of October 28, 1994
between Registrant and Red Acquisition Corp. and Red Eagle
Resources Corporation. (16)
10.1(tt) Second Amendment to Amended and Restated Revolving Credit
and Term Loan Agreement dated December 30, 1994 between
Lomak Petroleum, Inc. and Bank One Texas, N.A. and Texas
Commerce Bank National Association. (17)
10.1(uu) Third Amendment to Amended and Restated Revolving Credit
and Term Loan Agreement dated January 25, 1995 between
Lomak Petroleum, Inc. and Bank One Texas, N.A. and Texas
Commerce Bank National Association. (17)
55
<PAGE> 56
10.1(vv) Second Amended and Restated Revolving Credit and Term Loan
Agreement dated December 20, 1995 between Lomak Petroleum,
Inc., Lomak Operating Company, Lomak Production Company,
Lomak Resources Company and Red Eagle Resources
Corporation; Bank One, Texas N.A., Texas Commerce Bank
National Association, Nationsbank of Texas, N.A. and PNC
Bank, National Association.
11.1* Computation of earnings per common and common equivalent
shares.
22* Subsidiaries of the Registrant.
23.1* Consent of Independent Public Accountants.
27* Financial Data Schedule.
- ---------------
(1) Previously filed as Exhibit to Company's Registration Statement,
Registration Statement No. 33-31558.
(2) Incorporated by reference to the Company's Form 8-K dated May 31, 1990.
(3) Incorporated by reference to the Company's Form 8-K dated March 15,
1990.
(4) Previously filed as exhibit to Xenda Corporation Form S-4 filed July
26, 1988, as amended, and incorporated herein by reference.
(5) Previously filed as exhibit to Xenda Corporation Form S-18 filed
January 26, 1988, as amended, and incorporated herein by reference.
(6) Previously filed as exhibit to Latoka, Inc. Form 10-Q for the quarter
ended September 30, 1989, and incorporated herein by reference.
(7) Incorporated by reference to the Company's Form 8-K dated August 5,
1991.
(8) Incorporated by reference to the Company's Form 8-K dated April 26,
1993 as amended by Form 8 dated June 23, 1993.
(9) Incorporated by reference to the Company's Registration Statement No.
33-70462 filed on October 18, 1993.
(10) Incorporated by reference to the Company's Pre-Effective Amendment No.
1 dated November 9, 1993, to the Company's Registration Statement No.
33-70462.
(11) Incorporated by reference to the Company's Post-Effective Amendment No.
1 dated December 10, 1993, to the Company's Registration Statement No.
33-70462.
(12) Incorporated by reference to the Company's Post-Effective Amendment No.
2 dated January 27, 1994.
(13) Incorporated by reference to the Company's Form 8-K dated February 11,
1994.
(14) Incorporated be reference to the Company's Form 10K for the year ended
December 31, 1993, and incorporated herein by reference.
(15) Incorporated by reference to the Company's Post-Effective Amendment No.
4 dated May 3, 1994.
(16) Incorporated by reference to the Company's Form S-4 dated December 13,
1994
(17) Incorporated be reference to the Company's Form 10K for the year ended
December 31, 1994, and incorporated herein by reference.
* Filed herewith.
56
<PAGE> 1
EXHIBIT 11.1
LOMAK PETROLEUM, INC.
COMPUTATION OF EARNINGS PER COMMON
AND COMMON EQUIVALENT SHARES
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
1994 1995 1996
--------------- --------------- ---------------
(In thousands, except per share data)
<S> <C> <C> <C>
Average shares outstanding 8,902 11,674 14,334
Net effect of conversion of warrants and stock options 149 167 478
--------------- --------------- ---------------
Total primary and fully diluted shares 9,051 11,841 14,812
=============== =============== ===============
Net income $ 2,619 $ 4,390 $ 12,615
Less preferred stock dividends (375) (731) (2,454)
--------------- ---------------- ----------------
Net income applicable to common shares $ 2,244 $ 3,659 $ 10,161
=============== =============== ===============
Earnings per common share $ 0.25 $ 0.31 $ 0.69
=============== =============== ===============
</TABLE>
57
<PAGE> 1
EXHIBIT 22
LOMAK PETROLEUM, INC.
SUBSIDIARIES OF REGISTRANT
<TABLE>
<CAPTION>
Percentage of Voting
Securities Owned by
Name Jurisdiction of Incorporation Immediate Parent
- ------------------------------------- ----------------------------- ---------------------
<S> <C> <C>
Lomak Operating Company Ohio 100%
Lomak Production Company Delaware 100%
Buffalo Oilfield Services, Inc. Ohio 100%
Lomak Energy Services Company Delaware 100%
Lomak Resources Company Delaware 100%
Eastern Petroleum Company Ohio 100%
</TABLE>
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report dated February 14, 1997, included in this Form 10-K, into the
Company's previously filed Registration Statements on Form S-8 File No.
33-66322, Form S-3 File No. 33-64303 and on Form S-3 File No. 333-20257.
Arthur Andersen LLP
Cleveland, Ohio
March 21, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<CURRENCY> DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<EXCHANGE-RATE> 1
<CASH> 8,625
<SECURITIES> 7,658
<RECEIVABLES> 18,121
<ALLOWANCES> 0
<INVENTORY> 799
<CURRENT-ASSETS> 35,203
<PP&E> 303,658
<DEPRECIATION> (58,099)
<TOTAL-ASSETS> 282,547
<CURRENT-LIABILITIES> 22,307
<BONDS> 0
<COMMON> 148
0
1,150
<OTHER-SE> 116,231
<TOTAL-LIABILITY-AND-EQUITY> 282,547
<SALES> 68,054
<TOTAL-REVENUES> 91,238
<CGS> 24,456
<TOTAL-COSTS> 38,033
<OTHER-EXPENSES> 33,756
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7,487
<INCOME-PRETAX> 19,449
<INCOME-TAX> 6,834
<INCOME-CONTINUING> 12,615
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 12,615
<EPS-PRIMARY> 0.69
<EPS-DILUTED> 0.69
</TABLE>
