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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-26662
PANACO, Inc.
(Exact name of registrant as specified in its charter)
Delaware 43 - 1593374
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
1050 West Blue Ridge Boulevard, PANACO Building,
Kansas City, MO 64145-1216
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (816) 942 - 6300
Securities registered pursuant to Section 12(d)
of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.01 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 the 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 the voting stock held by non-affiliates of the
registrant was approximately $87,559,090 as of March 31, 1998.
23,920,280 shares of the registrant's Common Stock were outstanding
as of March 31, 1998.
Documents Incorporated by Reference
None
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<PAGE>
GLOSSARY OF SELECTED OIL AND GAS TERMS
2-D Seismic. Seismic data and the related technology used to acquire and process
such data to yield a two-dimensional view of a "slice" of the subsurface.
3-D Seismic. Seismic data and the related technology used to acquire and process
such data to yield a three-dimensional picture of the subsurface. 3-D Seismic is
created by the propagation of sound waves through sedimentary rock layers, which
are then detected and recorded as they are reflected and refracted back to the
surface. By measuring the time taken for the sound to return and applying
computer technology to process the resulting data in volume, imagery of
significantly greater accuracy and usefulness than older-style 2-D Seismic can
be created.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalents converting one Bbl of
oil to six Mcf of natural gas.
Block. One offshore unit of lease acreage, generally 5,000 acres.
Btu. British Thermal Unit, the quantity of heat required to raise one pound of
water by one degree Fahrenheit.
Condensate. A hydrocarbon mixture that becomes liquid and separates from natural
gas when the gas is produced and is similar to crude oil.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole. A well found to be incapable of producing either oil or natural gas in
sufficient quantities to justify completion as an oil or natural gas well.
Estimated Future Net Revenues. Revenues from production of oil and natural gas,
net of all production-related taxes, lease operating expenses and capital costs.
Exploratory Well. A well drilled to find and produce oil or natural gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir.
Farmout. An agreement whereby the lease owner agrees to allow another to drill a
well or wells and thereby earn the right to an assignment of a portion or all of
the lease, with the original lease owner typically retaining an overriding
royalty interest and other rights to participate in the lease.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Group 3-D Seismic. Seismic procured by a group of parties or shot on a
speculative basis by a seismic company.
MBbl. One thousand Bbls of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalents converting one Bbl of
oil to six Mcf of natural gas.
Mcfe/d. Mcfe per day.
<PAGE>
MMbbl. One million Bbls of oil or other liquid hydrocarbons.
MMbtu. One million Btu.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalents converting one Bbl of
oil to six Mcf of natural gas.
Natural Gas Equivalent. The amount of natural gas having the same Btu content as
a given quantity of oil, with one Bbl of oil being converted to six Mcf of
natural gas.
Net Acres or Net Wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net Oil and Gas Sales. Oil and natural gas sales less oil and natural gas
production expenses.
Net Pay. The thickness of a productive reservoir capable of containing
hydrocarbons.
Net Production. Production that is owned by the Company after royalties and
production due others.
Net Revenue Interest. A share of the Working Interest that does not bear any
portion of the expense of drilling and completing a well and that represents the
holder's share of production after satisfaction of all royalty, overriding
royalty, oil payments and other non-operating interests.
Overriding Royalty Interest. An interest in an oil and natural gas property
entitling the owner to a share of oil and natural gas production free of costs
of exploration and production.
Payout. That point in time when a party has recovered monies out of the
production from a well equal to the cost of drilling and completing the well and
the cost of operating the well through that date.
Productive Well. A well that is producing oil or natural gas or that is capable
of production in paying quantities.
Proprietary 3-D Seismic. Seismic privately procured and owned by the procurer.
Proved Developed Non-Producing Reserves. Reserves that consist of (i) Proved
Reserves from wells which have been completed and tested but are not producing
due to lack of market or minor completion problems which are expected to be
corrected and (ii) Proved Reserves currently behind the pipe in existing wells
and which are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the wells.
Proved Developed Producing Reserves. Reserves that can be expected to be
recovered from currently producing zones under the continuation of present
operating methods.
Proved Developed Reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of oil, natural gas and natural gas
liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved Undeveloped Reserves. Proved reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
<PAGE>
Recompletion. The completion for production of an existing well bore in a
different formation or producing horizon from that in which the well was
previously completed.
Royalty Interest. An interest in an oil and natural gas property entitling the
owner to a share of oil and natural gas production free of costs of production.
SEC PV-10. The present value of proved reserves is an estimate of the discounted
future net cash flows from each of the properties at December 31, 1997, or as
otherwise indicated. Net cash flow is defined as net revenues less, after
deducting production and ad valorem taxes, future capital costs and operating
expenses, but before deducting federal income taxes. As required by rules of the
Commission, the future net cash flows have been discounted at an annual rate of
10% to determine their "present value." The present value is shown to indicate
the effect of time on the value of the revenue stream and should not be
construed as being the fair market value of the properties. In accordance with
Commission rules, estimates have been made using constant oil and natural gas
prices and operating costs, at December 31, 1997, or as otherwise indicated.
Shut-In. To close down a producing well or field temporarily for repair,
cleaning out, building up reservoir pressure, lack of a market or similar
conditions.
Sidetrack. A drilling operation involving the use of a portion of an existing
well to drill a second hole, in which a milling tool is used to grind out a
"window" through the side of a drill casing at some selected depth. The drilling
bit is then directed out of the window at a desired angle into previously
undrilled strata. From this directional start a new hole is drilled to the
desired formation depth and casing is set in the new hole and tied back into the
older casing, generally at a lower cost because of the utilization of a portion
of the original casing.
Tcf. One trillion cubic feet of natural gas.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Working Interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
<PAGE>
PART 1
Item 1. Business.
Unless the context otherwise requires, all references herein to
"PANACO" or the "Company" include PANACO, Inc., a Delaware corporation, its
consolidated subsidiaries and the Company's predecessor Pan Petroleum MLP.
Certain capitalized terms relating to the oil and natural gas business are
defined in the Glossary. The Company's website may be found at www.panaco.com.
PANACO, Inc. is in the business of acquiring, drilling and operating
offshore oil and natural gas properties in the Gulf of Mexico and onshore in the
Gulf Coast Region (collectively, the "GOM Region"). The Company is a Delaware
corporation that was organized in October 1991. Effective September 1, 1992, Pan
Petroleum MLP, the Company's predecessor, was merged into the Company. Between
1984 and 1988, this predecessor acquired a total of 114 limited partnerships
engaged in the onshore oil and natural gas business. With the acquisition of the
West Delta Fields in 1991, the Company shifted its emphasis offshore. Additional
offshore properties were acquired in 1994, 1995, 1996 and 1997. The Company has
experienced substantial growth as a result of the acquisition of offshore
properties from Amoco (the "Amoco Acquisition") and Gulf Coast properties, both
onshore and in Texas and Louisiana State waters, acquired as part of the
Goldking Companies, Inc. (the "Goldking Acquisition").
The Company's headquarters are located at 1050 West Blue Ridge
Boulevard, PANACO Building, Kansas City, Missouri 64145-1216, and its telephone
number at such offices is (816) 942-6300, FAX (816) 942-6305. The Houston office
is located at 1100 Louisiana, Suite 5100, Houston, Texas 77002-5220, and the
telephone number is (713) 970-3100, FAX (713) 970-3151.
Business Strategy
The Company's strategy is to systematically grow its reserves,
production, cash flow and earnings through a program focused on the GOM Region,
including (i) strategic acquisitions and mergers, (ii) exploitation and
development of acquired properties, (iii) marketing of existing infrastructure
and (iv) a selective exploration program. As a result of the Amoco Acquisition
and the Goldking Acquisition, described below, the Company has an inventory of
development and exploration projects that provide additional reserve potential.
The key elements of the Company's objectives are outlined as follows:
Strategic Acquisitions and Mergers
The Company has an acquisition strategy which focuses its efforts on
GOM Region properties that have a backlog of development and exploitation
projects, significant operating control, infrastructure value and opportunities
for cost reduction. The properties the Company seeks to acquire generally are
geologically complex with multiple reservoirs, have an established production
history and are candidates for exploitation. Geologically complex fields with
multiple reservoirs are fields in which there are multiple reservoirs at
different depths and wells which penetrate more than one reservoir and have the
potential for recompletion in more than one reservoir. In pursuing this
strategy, the Company identifies properties that may be acquired, preferably
through negotiated transactions or, where appropriate, sealed bid transactions.
Once properties are acquired, the Company focuses on reducing operating costs
and implementing production enhancements through the application of
technologically advanced production and recompletion techniques.
Over the past seven years, the Company has taken advantage of
opportunities to acquire interests in a number of producing properties which fit
its acquisition strategy. The historical success, through December 31, 1997, of
the Company's acquisition strategy is illustrated below:
<PAGE>
<TABLE>
<CAPTION>
Cumulative Cumulative
Purchase Purchase Capital Cash SEC
Acquisition Seller Date Price Expenditures(a) Flow(b) PV 10(c)
(dollars in millions)
<S> <C> <C> <C> <C> <C>
West Delta Fields(d) CATO(e) May 1991 $ 19.6 $ 18.8 $ 53.3 $ 17.4
Zapata Properties Zapata Jul 1995 2.7(f) 0.9 13.7 10.5
Bayou Sorrel(g) Shell Western Dec 1995 9.9 3.4 1.3 N/A
Amoco Properties Amoco Oct 1996 40.4 26.9 17.8 49.1
Goldking Shareholders Jul 1997 27.5(h) 1.7 1.4 48.4
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(a) Excludes exploration expenses for each acquisition subsequent to the date of acquisition.
(b) Defined as net revenues less direct operating expense.
(c) As of December 31, 1997.
(d) Excludes $4.0 million for repair of Tank Battery #3 in the West Delta Fields.
(e) Conoco, ARCO, Texaco and Oxy.
(f) Excludes a production payment and fee sharing agreement with the seller.
(g) The Company sold the Bayou Sorrel Field September 1, 1996 for $11.0 million.
(h) Excludes debt and liabilities of Goldking in the amount of $22.3 million.
</TABLE>
While the Company tends to focus on acquisitions of properties from
large integrated oil companies, it evaluates a broad range of acquisition and
merger opportunities. The Company has assembled a staff with significant
technical experience in evaluating, identifying and exploiting GOM Region
properties. In addition, the Company is regarded in the industry as a competent
buyer with the proven ability to close transactions in a timely manner. Based on
these factors, the Company is usually asked to bid on significant producing
property sales in the GOM Region.
Exploitation and Development of Acquired Properties
The Company has an inventory of exploitation projects including
development drilling, workovers, sidetrack drilling, recompletions and
artificial lift enhancements. As of December 31, 1997, 17% of the Company's
total SEC PV-10 relates to Proved Undeveloped Reserves. The Company uses
advanced technologies where appropriate in its development activities to convert
Proved Undeveloped Reserves to Proved Developed Producing Reserves. These
technologies include horizontal drilling and through tubing completion
techniques, new lower cost coiled tubing workover procedures and reprocessed 2-D
and 3-D Seismic interpretation. All of the identified capital projects can be
completed with the Company's existing platform and pipeline infrastructure,
thereby improving project economics.
Marketing of Existing Infrastructure
Along with its purchase of producing properties, the Company has
platform, pipeline and processing equipment infrastructure. The Company has
interests in 22 offshore platforms and 69 miles of offshore oil and natural gas
pipelines with diameters of 10" or larger. To enhance the value of these assets,
the Company has marketed this infrastructure to operators and leasehold owners
in adjacent fields. The Company currently has pipeline and processing agreements
relative to its West Delta Fields, East Cameron 359 Field, East Breaks 109 Field
and East Breaks 160 Field. The annual revenue received from these contracts for
use of the Company's infrastructure currently totals $3.2 million, which is
accounted for as a reduction of lease operating expense. The location of the
East Breaks facilities is strategic to deepwater development in the area, and
the replacement costs of the platforms, processing facilities and pipelines
exceed $100 million. As a result of the development costs, any operators with
discoveries in the surrounding deepwater area will have the incentive to use the
Company's East Breaks facilities, thus increasing the revenue potential of these
platforms and pipelines and extending their economic life.
<PAGE>
Selective Exploration Program
The Company participates in selective exploration projects for exposure
to additional reserve potential. The Company has farmed out the deep rights in
West Delta Blocks 52 through 56 to Ocean Energy, Inc. (formerly Flores & Rucks,
Inc.) in exchange for a new 3-D Seismic survey over these five Blocks and the
option to retain a 12.5% overriding royalty interest or a 50% working interest
in any proposed deep exploration wells. In addition, through the Goldking
Acquisition, the Company acquired an inventory of 15 diversified exploratory
drilling prospects with varying risk profiles. The Company is devoting a portion
of its capital expenditure budget to drilling exploratory wells.
Geographic Focus
The Company's reserve base is focused primarily in the GOM Region which
has historically been the most prolific basin in North America. The GOM Region
currently accounts for over 30% of the natural gas production in the United
States and continues to be the most active region in terms of capital
expenditures and new reserve additions. Because of upside potential, high
production rates, technological advances and acquisition opportunities, the
Company has focused its efforts in this region. The Company believes it has the
technical expertise and infrastructure in place to take advantage of the
inherent benefits of the GOM Region. In addition, as the integrated oil
companies move to deeper water, the Company believes it will continue to be well
positioned to use its expertise to acquire and exploit GOM Region properties.
Quality Reserve Base
Two of the Company's largest properties, the West Delta Fields and
Umbrella Point Field, are prolific fields with total cumulative production of
over one Tcf of natural gas and 50 MMbbls of oil. These fields typify the
Company's focused GOM Region asset base with multiple pay horizons and
significant recompletion and workover potential. The West Delta Fields were
developed without the benefit of 3-D Seismic and the Company is currently in the
process of acquiring and applying 3-D Seismic technology to identify additional
potential. The majority of the Company's properties have multiple reservoirs
providing a diverse set of opportunities for production rate acceleration and
value enhancement. The number of potential reservoirs also reduces the risk
associated with determining remaining reserves and forecasting future production
from the properties.
Inventory of Exploitation and Development Projects
The Company has identified development drilling locations and
recompletion and workover opportunities. The Company believes that the majority
of these opportunities have a moderate risk profile and could add incremental
reserves and production. In addition to these identified opportunities, the
Company believes that with the use of 3-D Seismic technology, additional
potential may be exploited in the known reservoirs as well as deeper undrilled
horizons.
Application of Advanced Technologies
The Company has been successful historically due to its use of 3-D
Seismic, horizontal drilling and coiled tubing technologies. As a result of its
acquisitions, the Company has a seismic database with a total of 2,424 linear
miles of 2-D Seismic data and 186 square miles of 3-D Seismic data. The Company
was also among the first offshore operators to drill and complete successful
horizontal wells offshore. The Company has drilled a total of four horizontal
wells in the West Delta Fields. The Company applies coiled tubing technology
where applicable to decrease workover costs and avoid using drilling and
workover rigs for recompletions. The Company uses existing inactive wellbores
whenever possible to sidetrack drill to decrease costs and receive production
tax benefits where applicable. Also, the Company has performed the less costly
through tubing recompletions in several of its existing fields.
Significant Operating Control
The Company operates 55% of its properties as measured by SEC PV-10
value. This level of operating control benefits the Company in numerous ways by
enabling the Company to (i) control the timing and nature of capital
expenditures, (ii) identify and implement cost control programs, (iii) respond
quickly to operating problems and (iv) receive overhead reimbursements from
other working interest owners. In addition to significant operating control, the
geographic focus of the Company allows it to operate a large value asset base
with relatively few employees, thereby decreasing lease-operating expense on a
unit of production basis.
<PAGE>
Goldking Acquisition
Effective July 31, 1997, the Company acquired Goldking, a privately
owned, Houston-based oil and natural gas company. Through this acquisition, the
Company obtained estimated additional Proved Reserves of 37.9 Bcfe from 234
wells located primarily in Texas and Louisiana, both onshore and in State
waters. Goldking also had a sizeable portfolio of exploration prospects
developed using 3-D Seismic data, an extensive development program and a staff
of people experienced in Gulf Coast oil and natural gas operations. As part of
the transaction, the Company also acquired three pipelines totaling 19 miles in
length. The acquisition provides the Company with attractive development
opportunities in the currently active Lower Frio/Vicksburg play in Trinity Bay,
Chambers County, Texas.
The Company acquired Goldking by merging its corporate parent, The
Union Companies, Inc. ("Union") into Goldking Acquisition Corp., a newly formed,
wholly-owned subsidiary of the Company. The individual shareholders of Union
received merger consideration consisting of $7.5 million in cash, $6.0 million
in notes (which were paid in October 1997) and 3,154,930 Company Common Shares,
valued for purposes of the transaction at $14.0 million. The Company also
assumed the debt and net liabilities of Goldking in the amount of $22.3 million.
Public Offering
On March 7, 1997, the Company received net proceeds of $22.0 million
from a public offering of its common shares. The proceeds were used to repay
certain subordinated indebtedness and to develop the Company's properties.
Well Operations
The Company operates 70 offshore wells and owns all of the working
interests in a majority of those wells. The Company's 96 remaining offshore
wells are operated by third party operators, including Unocal Corporation,
Coastal Oil & Gas Corp., Phillips Petroleum Company, Texaco, Anadarko Petroleum
Corporation and Burlington. The Company operates 76 onshore wells in which it
owns a majority or all of the working interest. In addition, it owns working
interests in 369 wells operated by others. Where properties are operated by
others, operations are conducted pursuant to joint operating agreements that
were in effect at the time the Company acquired its interest in these
properties. The Company considers these joint operating agreements to be on
terms customary within the industry. The operator of an oil and natural gas
property supervises production, maintains production records, employs field
personnel, and performs other functions required in the production and
administration of such property. The compensation paid to the operator for such
services customarily varies from property to property, depending on the nature,
depth, and location of the property being operated.
Acquisition, Development, and Other Activities
The Company utilizes its capital budget for (a) the acquisition of
interests in other producing properties, (b) recompletions of its existing
wells, and (c) the drilling of development and exploratory wells.
In recent years, major oil companies have been selling properties to
independent oil companies because they feel these properties do not have the
remaining reserve potential needed by a major oil company. Several independent
oil companies have acquired these properties and achieved significant success in
further exploitation. Even though a property does not meet the criteria for
further development by a major oil company, that does not mean it is lacking
further exploitation potential. The majors are simply moving further offshore
into deeper water and to other countries where they can find and produce the
super-fields that fit their criteria. Present day technology permits drilling
and completing wells in water in excess of 10,000'.
<PAGE>
Amoco Acquisition.
In October 1996, the Company acquired interests in six offshore fields
from Amoco Production Company for $40.4 million. In consideration for such
interests, the Company issued Amoco 2,000,000 Common Shares and paid the sum of
$32.0 million in cash. The interests acquired include (1) a 33a% working
interest in the East Breaks 160 Field (two Blocks) and a 33a% interest in the
High Island 302 Field, both operated by Unocal Corporation; (2) a 50% interest
in the High Island 309 Field (two Blocks), a 12% interest in the High Island 330
Field (three Blocks) both operated by Coastal Oil and Gas Corp., (3) a 12%
interest in the High Island 474 Field (four Blocks), operated by Phillips
Petroleum Company; and (4) a 12.5% interest in the West Cameron 180 Field (one
Block) operated by Texaco.
Future acquisitions of properties may include acquisitions of working
interests, royalty interests, net profits interests, production payments, and
other forms of direct or indirect ownership interest or interests in oil and
natural gas production. The Company may also acquire general or limited partner
interests in general or limited partnerships and interests in joint ventures,
corporations, or other entities that own, manage, or are formed to acquire,
explore for, or develop oil and natural gas properties or conduct other
activities associated with the ownership of oil and natural gas production. The
Company may also acquire or participate in the expansion of natural gas
processing plants and natural gas transportation or gathering systems.
The success of the Company's acquisitions will depend on (a) the
Company's ability to establish accurately the volumes of reserves and rates of
future production from producing properties being considered for acquisition and
the future net revenues attributable to reserves from such properties, taking
into account future operating costs, market prices for oil and natural gas,
rates of inflation, risks attendant to production of oil and natural gas, and a
suitable return on investment, and (b) the Company's ability to purchase
properties and produce and market oil and natural gas therefrom at prices and
rates that over time will generate cash flows resulting in an attractive return
on the initial investment. The Company's cash flow and return on investment will
vary to the extent that the Company's production from an acquired property is
greater or less than that estimated at the time of acquisition because of, for
example, the results of drilling or improved recovery programs, the demand for
oil and natural gas, or changes in the prices of oil and natural gas from the
prices used to calculate the purchase price for producing properties. The
Company will evaluate any economically feasible project that would enhance the
value of its properties. Such a project may involve both the acquisition of
developed and undeveloped properties and the drilling of infield wells.
The Company expects that its primary activities will continue to be
concentrated offshore in the Gulf of Mexico and onshore in the Gulf Coast
region. The Company can, if it so chooses, invest in any geographic area. The
number and type of wells drilled by the Company will vary from period to period
depending on the amount of the capital budget available for drilling, the cost
of each well, the Company's commitment to participate in the wells drilled on
properties operated by third parties, the size of the fractional working
interest acquired by the Company in each well and the estimated recoverable
reserves attributable to each well. Drilling on and production from offshore
properties often involves higher costs than does drilling on and production from
onshore properties, but the production achieved on successful wells is generally
much greater.
1996 Fire at West Delta
The Company experienced a fire on April 24, 1996 at Tank Battery #3 in
West Delta resulting in the fields being shut-in from April 24th, until being
returned to production on October 7, 1996. This resulted in lost revenues of
approximately $6.0 million. The fire was the principal contributor to the losses
in 1996. During 1996 the Company expensed $500,000 as a result of this fire,
which included $225,000 in deductibles under the Company's insurance. The
Company has repaired Tank Battery #3 at a cost of $8.5 million inclusive of the
$500,000 expensed during second quarter and has received reimbursement from its
insurance company of $3.9 million, after satisfaction of the $225,000 in
deductibles. The Company has filed suits against the employers of the persons
who caused the incidents for recovery of these costs and its lost profits. No
assurance can be given that the Company will successfully recover any amounts
sought in any such suits.
<PAGE>
Use of 3-D Seismic Technology
The use of 3-D Seismic and computer-aided exploration ("CAEX")
technology is an integral component of the Company's acquisition, exploitation,
drilling and business strategy. In general, 3-D Seismic is the process of
obtaining seismic data along multiple lines and grids within a large geographic
area. 3-D Seismic differs from 2-D Seismic in that it provides information with
respect to multiple horizontal and vertical points within a geological formation
instead of information on a single vertical line or multiple vertical lines
within the formation. By expanding the amount of data obtained with respect to a
geological formation, the user is better able to correlate the data and obtain a
greater understanding and image of the formation. While it is impossible to
predict with certainty the specific configuration or composition of any
underground geological formation, 3-D Seismic provides a mechanism by which
clearer and more accurate projected images of complex geological formations can
be obtained prior to drilling for hydrocarbons therein. In particular, 3-D
Seismic delineates smaller reservoirs with greater precision than can be
obtained with 2-D Seismic.
3-D Seismic and CAEX technology have been in existence since the mid
1970's; however, it was not until the late 1980's, with the development of
improved data acquisition equipment and techniques capable of gathering
significant amounts of data through a large number of channels and the
availability of improved computer technology at reasonable costs, that the
method became economically available to firms such as the Company. Prior to
that, it was the exclusive province of large multinational oil companies. The
Company owns its own processing equipment, but it also utilizes the services of
outside firms to process and interpret seismic data.
A new 3-D Seismic survey will be shot in 1998 by Ocean Energy, Inc.
(formerly Flores & Rucks, Inc.) on the Company's West Delta Fields. The Company
generated a prospect in the northern portion of West Delta Block 58 using 3-D
Seismic, which it farmed out to Tana Oil & Gas Corp. in 1996. Tana drilled a
successful well to 12,800' which encountered 85' of net pay and is currently
producing 12,300 Mcf per day. The Company retained an overriding royalty
interest that converted to a 25% working interest at Payout (September 26,
1997). Three of the fields in the Amoco Acquisition have proprietary 3-D
Seismic, while all of the Amoco Properties have Group 3-D Seismic. The Company
has experienced success in High Island 309 Field, acquired from Amoco, in the
drilling of new wells, sidetracks out of existing wells, and recompletions of
existing wells based upon an extensive reevaluation of the field using 3-D
Seismic.
Marketing of Production
Production from the Company's properties is marketed in accordance
with industry practices, which include the sale of oil at the wellhead to third
parties and the sale of natural gas to third parties at prices based on factors
normally considered in the industry, such as the spot price for natural gas or
the posted price for oil, and the quality of the oil and natural gas.
The Company markets all of its offshore oil production to Amoco, Citgo,
Conoco, Texaco, Unocal and Vastar. Citgo, Conoco, Texaco and Vastar each have
25% calls (exclusive rights to purchase) on the oil production from the West
Delta Fields at their average posted price for each month. Amoco has a call on
all of the oil production from the Amoco Properties at their posted prices. If
the Company has a bona fide offer from a crude oil purchaser at a higher price
than Amoco's posted price, then Amoco must match that price or release the call.
Oil from the Zapata Properties is currently being sold to Unocal and Amoco, but
can be sold to any crude oil purchaser of the Company's choice. Natural gas is
sold on the spot market. There are numerous potential purchasers for offshore
natural gas. Notwithstanding this, natural gas purchased by Tenneco Gas
Marketing Company (now El Paso Gas Marketing Co.) accounted for 69% of the
revenues in 1997. There are numerous natural gas purchasers doing business in
the areas involved as well as natural gas brokers and clearing houses.
Furthermore, the Company can contract to sell the natural gas directly to
end-users. The Company does not believe that it is dependent upon any one
customer or group of customers for the purchase of natural gas.
<PAGE>
The Company hedges the prices of its oil and natural gas production
through the use of oil and natural gas hedge and swap contracts within the
normal course of its business. The Company uses hedge and swap contracts to
reduce the effects of fluctuations in oil and natural gas prices. Changes in the
market value of these contracts are deferred and subsequent realized gains and
losses are recognized monthly as adjustments to revenues in the same production
period as the hedged item, based on the difference between the index price and
the contract price.
Starting in 1997 the Company's natural gas hedge transactions are based
upon published natural gas pipeline index prices and not the NYMEX. This change
has significantly reduced price differential risk due to transportation. The
Company has natural gas hedged in quantities ranging from 10,000 to 50,000
MMbtu's per day in each of the months in 1998 for a total of 11,980,000 MMbtu's,
at pipeline prices averaging approximately $2.05 per MMbtu, for a NYMEX
equivalent of approximately $2.20 per MMbtu. The Company has hedged 7,356 MMbtu
per day in 1999, all at an average pipeline index swap price of $1.89 per MMbtu.
The Company has hedged 218 MMbtu for each day in 2000 at an average pipeline
index swap price of $1.87. The Company hedged 1,268 Bbls of oil for each day in
1998 at an average swap price of $19.06 per Bbl, with a 40% participation above
$19.28 on 500 Bbls of the 1,268 Bbls. The Company has hedged 223 Bbls of oil for
each day in 1999 at an average price of $17.27 per Bbl. The Company has hedged
232 Bbls of oil for each day in 2000 at an average price of $17.28 per Bbl.
Plugging and Abandonment Escrows
Pursuant to existing agreements the Company is required to deposit
funds in escrow accounts to provide a reserve against satisfaction of its
eventual responsibility to plug and abandon wells and remove structures when
certain fields no longer produce oil and natural gas. The Company has entered
into an escrow agreement with Amoco Production Company under which the Company
will deposit, for the life of the fields, in a bank escrow account ten percent
(10%) of the net cash flow, as defined in the agreement, from the Amoco
Properties. These funds and interest earned thereon will be available for the
expenses of plugging wells and removing structures when that time comes. The
Company has established the "PANACO East Breaks 110 Platform Trust" at Bank One,
Texas, NA in favor of the Minerals Management Service of the U.S. Department of
the Interior. This trust was initially funded by deposit of $846,720 in December
1996, and remaining deposits of $244,320 due at the end of each quarter in 1999
and $144,000 due at the end of each quarter in 2000, for a total of $2,400,000.
In addition, the Company has $9,250,000 in surety bonds to secure its plugging
and abandonment obligations; including a $4,100,000 bond which was provided to
the original sellers of the West Delta Fields; a $2,400,000 supplemental bond
provided to the Minerals Management Service of the U.S. Department of the
Interior in connection with the plugging and structure removal obligations for
the Company's East Breaks Block 110 Platform and a $300,000 Pipeline
Right-of-Way Bond.
Insurance
The Company maintains insurance coverage as is customary for companies
of a similar size engaged in operations similar to the Company's. The Company's
insurance coverage includes comprehensive general liability insurance in the
amount of $50 million per occurrence for personal injury and property damage and
cost of control and operators extra expense insurance of $3 million on onshore
wells, $20 million on wells in Louisiana State waters and $50 million per
occurrence in Federal offshore waters, which limits are proportionately reduced
when the Company owns less than 100% of the respective property. The Company
maintains $77 million in property insurance on its offshore properties. There is
no assurance that such insurance will be adequate to cover all such costs or
that such insurance will continue to be available in the future or that such
insurance will be available at premium levels that justify its purchase. The
occurrence of a significant event not fully insured or indemnified against could
have a material adverse effect on the Company's financial condition and
operations.
<PAGE>
Funding of Business Activities
During 1997, the Company's capital expenditures were approximately
$80,000,000, for (1) construction of an offshore pipeline, (2) the development
of its oil and gas properties and (3) the Goldking Acquisition. The majority of
the development costs were incurred to drill exploratory and developmental wells
on the Amoco Properties, primarily the High Island 309 Field. The sources of
funds for capital expenditures were cash flow from operations, borrowings on the
Company's existing bank facility and proceeds of the issuances of Common Shares.
The cash flow generated by the Company's activities would decline in the absence
of the acquisition and development of other oil and natural gas properties or
increases in the Company's production of oil and natural gas resulting from
exploration or the development of its properties.
The Company may issue additional Common Shares or other securities for
cash, to the extent that market and other conditions permit, and use the
proceeds to fund its activities. During 1996 shareholders' equity increased by
$1,837,000, as a result of the exercise of warrants, and $8,400,000 as a result
of 2,000,000 shares being issued to Amoco Production Company as part of the
Amoco Acquisition. During 1997, shareholders' equity increased by $21,997,000 as
a result of the issuance of 6,000,000 Common Shares in the public offering,
$1,236,000 as a result of issuance and exercise of warrants, contributions to
the Company's ESOP and employee stock bonuses, and $14,414,000 as a result of
the issuance of 3,154,930 Common Shares to the beneficial owners of Goldking and
84,000 Common Shares as a finders fee, both in connection with the Goldking
Acquisition.
Senior Notes
On October 10, 1997 the Company issued $100,000,000 aggregate principal
amount of 10 5/8% Senior Notes due October 1, 2004. Interest on the Senior Notes
accrues from the date of original issuance and is payable semi-annually in
arrears on each April 1 and October 1, commencing April 1, 1998.
The Senior Notes are general unsecured obligations of the Company and
rank pari passu with any unsubordinated indebtedness of the Company and rank
senior in right of payment to all subordinated obligations of the Company. The
Senior Notes are effectively subordinated to all secured indebtedness of the
Company and of the Subsidiary Guarantors to the extent of the value of the
assets securing such indebtedness.
The Senior Notes are unconditionally guaranteed on a senior basis by
the Company's Subsidiary Guarantors. The Guarantees are general unsecured
obligations of the Subsidiary Guarantors and rank pari passu with any
unsubordinated indebtedness of the Subsidiary Guarantors and rank senior in
right of payment to all subordinated obligations of the Subsidiary Guarantors.
The Guarantees are effectively subordinated to all secured indebtedness of the
Subsidiary Guarantors to the extent of the value of the assets securing such
indebtedness.
The Senior Notes are redeemable, in whole or in part, at the option of
the Company on or after October 1, 2001, at set redemption prices, plus accrued
interest, if any, thereon to the date of redemption. In addition, at any time on
or prior to October 1, 2000, the Company may, at its option, redeem up to 35% of
the aggregate principal amount of the Senior Notes originally issued with the
net cash proceeds of one or more equity offerings, at a redemption price equal
to 110.625% of the aggregate principal amount of the Senior Notes to be redeemed
plus accrued interest, if any, thereon to the date of redemption; provided,
however, that, after giving effect to any such redemption, at least 65% of the
aggregate principal amount of the Senior Notes originally issued remains
outstanding.
Upon a Change of Control, each holder of the Senior Notes will have the
right to require the Company to repurchase such holder's Senior Notes at a price
equal to 101% of the principal amount thereof plus accrued interest, if any,
thereon to the date of repurchase.
The Indenture contains certain restrictive covenants that limit the
ability of the Company and its subsidiaries to, among other things, incur
additional indebtedness, pay dividends or make certain other restricted
payments, consummate certain asset sales, enter into certain transactions with
affiliates, incur liens, impose restrictions on the ability of a Restricted
Subsidiary to pay dividends or make certain payments to the Company and its
Restricted Subsidiaries, merge or consolidate with any other person or sell,
assign, transfer, lease, convey or otherwise dispose of all or substantially all
of the assets of the Company. In addition, under certain circumstances, the
Company will be required to offer to purchase the Senior Notes, in whole or in
part, at a purchase price equal to 100% of the principal amount thereof plus
accrued interest to the date of repurchase, with the proceeds of certain Asset
Sales.
<PAGE>
New Credit Facility
The Company has a $75 million revolving credit facility (the "New
Credit Facility") from First Union National Bank of North Carolina, as
Administrative Agent and Banque Paribas (collectively, the "Lenders"). The
purpose of the New Credit Facility is to provide funds for working capital
support and general corporate purposes and to have available letters of credit.
The New Credit Facility is a revolving credit subject to a borrowing
base determination made April 1 and October 1 of each year by the Lenders. At
present the borrowing base is $40 million. However, the only borrowing under the
New Credit Facility is a $1 million letter of credit. If at any time the
borrowing base is determined to be less than the current loan balance, the
Company will be required to pay down the excess in two equal payments due three
and six months after notification from the Administrative Agent.
Under the terms of the New Credit Facility, the Company must maintain a
ratio of EBITDA to consolidated interest expense of not less than 2.0 to 1 until
December 31, 1998 and 2.5 to 1 thereafter. The Company must also maintain
current assets of not less than current liabilities.
The Company may elect to pay interest on the New Credit Facility at
either the Bank's prime rate or at LIBOR plus 1 to 1.75%, depending upon the
percentage of utilization of borrowing base. LIBOR is the London Interbank
Offered Rate on Eurodollar loans. Eurodollar loans can be for terms of one, two,
three or six months and interest on such loans is due at the expiration of the
terms of such loans, but no less frequently than every three months.
The New Credit Facility has a maturity of five years with no required
principal payments until maturity, provided that the outstanding principal
balance does not exceed the borrowing base determinations established from time
to time by the Lenders. Indebtedness under the New Credit Facility constitutes
senior indebtedness with respect to the Senior Notes. Outstanding indebtedness
is secured by first priority mortgages and security interests taken by the
lenders in substantially all properties and assets owned by the Company. All of
the capital stock of all subsidiaries of the Company is pledged pursuant to the
New Credit Facility. Each of the Company's wholly owned subsidiaries guarantees
the New Credit Facility.
The New Credit Facility also contains certain covenants, including a
minimum tangible net worth test, and negative covenants imposing limitations on
mergers, additional indebtedness, and pledges and sales of assets.
Competition, Markets, Seasonality and Environmental and Other Regulation
Competition. There are a large number of companies and individuals
engaged in the exploration for and development of oil and natural gas
properties. Competition is particularly intense with respect to the acquisition
of oil and natural gas producing properties and securing experienced personnel.
The Company encounters competition from various independent oil companies in
raising capital and in acquiring producing properties. Many of the Company's
competitors have financial resources and staffs considerably larger than the
Company.
Markets. The ability of the Company to produce and market oil and
natural gas profitably depends on numerous factors beyond the control of the
Company. The effect of these factors cannot be accurately predicted or
anticipated. These factors include the availability of other domestic and
foreign production, the marketing of competitive fuels, the proximity and
capacity of pipelines, fluctuations in supply and demand, the availability of a
ready market, the effect of federal and state regulation of production,
refining, transportation, and sales of oil and natural gas, political
instability or armed conflict in oil-producing regions, and general national and
worldwide economic conditions. In recent years, worldwide oil production
capacity and natural gas production capacity in the United States exceeded
demand and resulted in a substantial decline in the price of oil and natural gas
in the United States.
Since early 1986, certain members of the Organization of Petroleum
Exporting Countries ("OPEC") have, at various times, dramatically increased
their production of oil, causing a significant decline in the price of oil in
the world market. The Company cannot predict future levels of production by the
OPEC nations, the prospects for war or peace in the Middle East, or the degree
to which oil and natural gas prices will be affected, and it is possible that
prices for any oil, natural gas liquids, or natural gas produced by the Company
will be lower than those currently available.
The demand for natural gas in the United States has fluctuated in
recent years due to economic factors, a deliverability surplus, conservation and
other factors. This lack of demand has resulted in increased competitive
pressure on producers. However, environmental legislation is requiring certain
markets to shift consumption from fuel oils to natural gas, thereby increasing
demand for this cleaner burning fuel.
<PAGE>
In view of the many uncertainties affecting the supply and demand for
oil, natural gas, and refined petroleum products, the Company is unable to
predict future oil and natural gas prices. In order to minimize these
uncertainties the Company, from time to time, hedges prices on a portion of its
production.
Seasonality. Historically the nature of the demand for natural gas
caused prices and demand to vary on a seasonal basis. Prices and production
volumes were generally higher during the first and fourth quarters of each
calendar year. For example, during 1991 the price the Company receives for its
natural gas fell from a high of $1.78 per Mcf in January to a low of $1.09 in
July and then climbed to a new high of $1.95 in December, averaging $1.49 for
the year. However, the substantial amount of natural gas storage becoming
available in the U.S. is altering this seasonality. During 1993, 1994 and 1995
the Company's natural gas prices ranged from $2.78 to $1.64, $2.43 to $1.39 and
$2.37 to $1.37, averaging $2.13, $1.88 and $1.58, respectively, in each case,
per Mcf. Gas prices averaged $2.17 per Mcf during 1996. The Company sells its
natural gas on the spot market based upon published index prices for each
pipeline. Historically the net price received by the Company for its natural gas
has averaged about $.10 per MMbtu below the NYMEX Henry Hub index price, due to
transportation differentials. Fields that are located further offshore, such as
the Amoco Properties, will generally sell their natural gas for as much as
$.1244 below that index price. Early 1997 pipeline index prices were at
historical highs, moderated during the late winter and spring only to rebound in
the last half of the year. During 1997 the Company sold its natural gas for an
average of $2.49 per Mcf.
Environmental and Other Regulation. The Company's business is affected
by governmental laws and regulations, including price control, energy,
environmental, conservation, tax and other laws and regulations relating to the
petroleum industry. For example, state and federal agencies have issued rules
and regulations that require permits for the drilling of wells, regulate the
spacing of wells, prevent the waste of natural gas and crude oil reserves, and
regulate environmental and safety matters including restrictions on the types,
quantities and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limits or
prohibitions on drilling activities on certain lands lying within wetlands and
other protected areas, and remedial measures to prevent pollution from current
and former operations. Changes in any of these laws, rules and regulations could
have a material adverse effect on the Company's business. In view of the many
uncertainties with respect to current law and regulations, including their
applicability to the Company, the Company cannot predict the overall effect of
such laws and regulations on future operations.
The Company believes that its operations comply in all material
respects with all applicable laws and regulations and that the existence of such
laws and regulations have no more restrictive effect on the Company's method of
operations than on other similar companies in the industry. The following
discussion contains summaries of certain laws and regulations and is qualified
in its entirety by reference thereto.
Various aspects of the Company's oil and natural gas operations are
regulated by administrative agencies under statutory provisions of the states
where such operations are conducted and by certain agencies of the federal
government for operations of federal leases. The Federal Energy Regulatory
Commission (the "FERC") regulates the transportation and sale for resale of
natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the
ANGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). In the past, the
federal government has regulated the prices at which oil and natural gas could
be sold. Currently, sales by producers of natural gas, and all sales of crude
oil, condensate and natural gas liquids can be made at uncontrolled market
prices, but Congress could reenact price controls at any time. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA
in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act which
removed all NGA and NGPA price and nonprice controls affecting wellhead sales of
natural gas effective January 1, 1993.
Sales of crude oil, condensate and natural gas liquids by the Company
are not regulated and are made at market prices. The price the Company receives
from the sale of these products is affected by the cost of transporting the
products to market. Effective as of January 1, 1995, the FERC implemented
regulations establishing an indexing system for transportation rates for oil
pipelines, which would generally index such rates to inflation, subject to
certain conditions and limitations. These regulations could increase the cost of
transporting crude oil, liquids and condensates by pipeline. These regulations
are subject to pending petitions for judicial review. The Company is not able to
predict with certainty what effect, if any, these regulations will have on it,
but other factors being equal, the regulations may tend to increase
transportation costs or reduce wellhead prices for such conditions.
<PAGE>
Additional proposals and proceedings that might affect the oil and
natural gas industry are pending before Congress, the FERC and the courts. The
Company cannot predict when or whether any such proposals may become effective.
In the past, the natural gas industry historically has been very heavily
regulated. There is no assurance that the current regulatory approach pursued by
the FERC will continue indefinitely into the future. Notwithstanding the
foregoing, it is not anticipated that compliance with existing federal, state
and local laws, rules and regulations will have a material or significantly
adverse effect upon the capital expenditures, earnings or competitive position
of the Company.
Extensive federal, state and local laws and regulations govern oil and
natural gas operations regulating the discharge of materials into the
environment or otherwise relating to the protection of the environment. Numerous
governmental departments issue rules and regulations to implement and enforce
such laws which change frequently, are often difficult and costly to comply with
and which carry substantial civil and/or criminal penalties for failure to
comply. Some laws, rules and regulations to which the Company is subject
relating to protection of the environment may, in certain circumstances, impose
"strict liability" for environmental contamination, rendering a person liable
for environmental damages and response costs without regard to negligence or
fault on the part of such person. For example, the federal Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended, also
known as the "Superfund" law, imposes strict, joint and several liability on an
owner and operator of a facility or site where a release of hazardous substances
into the environment has occurred and on companies that disposed or arranged for
the disposal of the hazardous substances released at the facility or site.
Similarly, the Oil Pollution Act of 1990 ("OPA") imposes strict liability for
remediation and natural resource damages in the event of an oil spill. In
addition to other requirements, the OPA requires operators of oil and natural
gas leases on or near navigable waterways to provide $35 million in "financial
responsibility", as defined in the Act. At present the Company is satisfying the
financial responsibility requirement with insurance coverage. The regulatory
burden on the oil and natural gas industry increases its cost of doing business
and consequently affects its profitability. These laws, rules and regulations
affect the operations and costs of the Company. Furthermore, the Company cannot
guarantee that such laws as they apply to oil and natural gas operations will
not change in the future in such a manner as to impose substantial costs on the
Company. While compliance with environmental requirements generally could have a
material adverse effect upon the capital expenditures, earnings or competitive
position of the Company, the Company believes that other independent energy
companies in the oil and natural gas industry likely would be similarly
affected. The Company believes that it is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on the Company.
Offshore operations of the Company are conducted on both federal and
state lease blocks of the Gulf of Mexico. In all offshore areas the more
stringent regulation of the federal system, as implemented by the Mineral
Management Service of the Department of the Interior, will ultimately be
applicable to state as well as federal leases, which could impose additional
compliance costs on the Company. While there can be no guarantee, the Company
does not expect these costs to be material. See "Risk Factors - Environmental
and Other Regulations."
Employees
The Company has 28 full time employees, eight of whom are officers. The
Company utilizes an additional 43 contract personnel in the operation of the
offshore properties, and uses numerous outside geologists, production engineers,
reservoir engineers, geophysicists and other professionals on a consulting
basis.
Year 2000 Issue
The Company utilizes accounting and other software that has been
modified to accommodate the transition to the year 2000 and beyond. No material
expenditures are anticipated.
Office Facilities
The Company's headquarters are located at 1050 West Blue Ridge
Boulevard, Panaco Building, Kansas City, Missouri 64145-1216, and its telephone
number is (816) 942-6300, FAX (816) 942-6305. The Houston, Texas office is
located at 1100 Louisiana, Suite 5100, Houston, Texas 77002-5220, telephone
(713) 970-3100, FAX (713) 970-3151.
<PAGE>
Risk Factors
Information contained or incorporated by reference in this Annual
Report may contain "forward-looking statements" within the meaning of the
Private Securities Litigation Reform Act of 1995, which can be identified by the
use of forward-looking terminology such as "may," "expect," "intend,"
"anticipate," "estimate" or "continue" or the negative thereof or other
variations thereon or comparable terminology. The following matters and certain
other factors noted throughout this Annual Report constitute cautionary
statements identifying important factors with respect to any such
forward-looking statements, including certain risks and uncertainties, that
could cause actual results to differ materially from those in such
forward-looking statements.
Finding and Acquiring Additional Reserves; Depletion
The Company's future success depends upon its ability to find or
acquire additional oil and natural gas reserves that are economically
recoverable. Except to the extent the Company conducts successful exploration or
development activities or acquires properties containing Proved Reserves, the
Proved Reserves of the Company will generally decline as they are produced. The
decline rate varies depending upon reservoir characteristics and other factors.
The Company's future oil and natural gas reserves and production, and,
therefore, cash flow and income are highly dependent upon the Company's level of
success in exploiting its current reserves and acquiring or finding additional
reserves. The business of exploring for, developing or acquiring reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investments to maintain or expand its asset base
of oil and natural gas reserves could be impaired. There can be no assurance
that the Company's planned development projects and acquisition activities will
result in significant additional reserves or that the Company will have success
drilling productive wells at economic returns to replace its current and future
production.
Substantial Leverage; Ability to Service Debt
The Company is significantly leveraged, with outstanding long-term
indebtedness of approximately $101.7 million and stockholders' equity of $55.2
million as of December 31, 1997. The Company's level of indebtedness has several
important effects on its future operations, including (i) a substantial portion
of the Company's cash flow from operations is dedicated to the payment of
interest on its indebtedness and is not available for other purposes, (ii) the
covenants contained in the New Credit Facility and the Senior Notes require the
Company to meet certain financial tests and limit the Company's ability to
borrow additional funds or to acquire or dispose of assets, and (iii) the
Company's ability to obtain additional financing in the future may be impaired.
Additionally, the senior status of the Senior Notes, the Company's high debt to
equity ratio, and the use of substantially all of the Company's assets as
collateral for the New Credit Facility will for the present time make it
difficult for the Company to obtain financing on an unsecured basis or to obtain
secured financing other than certain "purchase money" indebtedness
collateralized by the acquired assets.
The Company's ability to meet its financial covenants and to make
scheduled payments of principal and interest to repay its indebtedness,
including the Senior Notes, is dependent upon its operating results and its
ability to obtain financing. However, there can be no assurance that the
Company's business will generate sufficient cash flow from operations or that
future bank credit will be available in an amount sufficient to enable the
Company to service its indebtedness, including the Senior Notes, or make
necessary capital expenditures. In such event, the Company would be required to
obtain such financing from the sale of equity securities or other debt
financing. There can be no assurance that any such financing will be available
on terms acceptable to the Company if at all. Should sufficient capital not be
available, the Company may not be able to continue to implement its strategy.
The New Credit Facility limits the Company's borrowings to amounts
determined by the lenders, in their sole discretion, based upon a variety of
factors including the amount of indebtedness which can be adequately supported
by the value of oil and natural gas reserves and assets owned by the Company
(the "Borrowing Base"). The Company presently has $40.0 million in borrowing
availability under the Borrowing Base of the New Credit Facility. If oil or
natural gas prices decline below their current levels, the availability of funds
under the New Credit Facility could be materially adversely affected.
<PAGE>
The New Credit Facility requires the Company to satisfy certain
financial ratios in the future. The failure to satisfy these covenants or any of
the other covenants in the New Credit Facility would constitute an event of
default thereunder and, subject to certain grace periods, may permit the lenders
to accelerate the indebtedness then outstanding under the New Credit Facility
and demand immediate repayment thereof. See "New Credit Facility."
Volatility of Oil and Natural Gas Prices
The Company's revenues, profitability and the carrying value of its oil
and natural gas properties are substantially dependent upon prevailing prices
of, and demand for, oil and natural gas and the costs of acquiring, finding,
developing and producing reserves. The Company's ability to maintain or increase
its borrowing capacity, to repay the Senior Notes and outstanding indebtedness
under any current or future credit facility, and to obtain additional capital on
attractive terms is also substantially dependent upon oil and natural gas
prices. Historically, the markets for oil and natural gas have been volatile and
are likely to continue to be volatile in the future. Prices for oil and natural
gas are subject to wide fluctuations in response to: (i) relatively minor
changes in the supply of, and demand for, oil and natural gas; (ii) market
uncertainty; and (iii) a variety of additional factors, all of which are beyond
the Company's control. These factors include domestic and foreign political
conditions, the price and availability of domestic and imported oil and natural
gas, the level of consumer and industrial demand, weather, domestic and foreign
government relations, the price and availability of alternative fuels and
overall economic conditions. The Company's production is weighted toward natural
gas, making earnings and cash flow more sensitive to natural gas price
fluctuations. Historically, the Company has attempted to mitigate these risks by
oil and natural gas hedging transactions. See "Business - Marketing of
Production."
Uncertainty of Estimates of Reserves and Future Net Cash Flows
This Annual Report contains estimates of the Company's oil and natural
gas reserves and the future net cash flows from those reserves, which have been
prepared by certain independent petroleum consultants. There are numerous
uncertainties inherent in estimating quantities of Proved Reserves of oil and
natural gas and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the Company's control.
The estimates herein are based on various assumptions, including, for example,
constant oil and natural gas prices, operating expenses, capital expenditures
and the availability of funds, and, therefore, are inherently imprecise
indications of future net cash flows. Actual future production, cash flows,
taxes, operating expenses, development expenditures and quantities of
recoverable oil and natural gas reserves may vary substantially from those
assumed in the estimates. Any significant variance in these assumptions could
materially affect the estimated quantity and value of reserves set forth herein.
Additionally, the Company's reserves may be subject to downward or upward
revision based upon actual production performance, results of future development
and exploration, prevailing oil and natural gas prices and other factors, many
of which are beyond the Company's control. See "Properties - Oil and Gas
Information."
The SEC PV-10 of Proved Reserves referred to herein should not be
construed as the current market value of the estimated Proved Reserves of oil
and natural gas attributable to the Company's properties. In accordance with
applicable requirements of the Commission, the estimated discounted future net
cash flows from Proved Reserves are generally based on prices and costs as of
the date of the estimate, whereas actual future prices and costs may be
materially higher or lower. The calculation of the SEC PV-10 of the Company's
oil and natural gas reserves at December 31, 1997 is based on prices of $2.48
per Mcf of natural gas and $17.50 per Bbl of oil. Actual future net cash flows
also will be affected by (i) the timing of both production and related expenses;
(ii) changes in consumption levels and (iii) governmental regulations or
taxation. In addition, the calculation of the present value of the future net
cash flows using a 10% discount as required by the Commission is not necessarily
the most appropriate discount factor based on interest rates in effect from time
to time and risks associated with the Company's reserves or the oil and natural
gas industry in general. Furthermore, the Company's reserves may be subject to
downward or upward revision based upon actual production, results of future
development, supply and demand for oil and natural gas, prevailing oil and
natural gas prices and other factors. See "Properties - Oil and Gas
Information."
<PAGE>
Acquisition Risks
The Company has grown primarily through acquisitions and intends to
continue acquiring oil and natural gas properties. Although the Company performs
an extensive review of the properties proposed to be acquired, such reviews are
subject to uncertainties. Consistent with industry practice, it is not feasible
to review less significant properties involved in such acquisitions. However,
even a detailed review may not reveal existing or potential problems; nor will
it permit the Company to become sufficiently familiar with the properties to
assess fully their deficiencies and capabilities.
The Company has recently begun to focus its acquisition efforts on
larger packages of oil and natural gas properties, such as the properties
involved in the Amoco Acquisition. The acquisition of larger oil and natural gas
properties may involve substantially higher costs and may pose additional issues
regarding operations and management. There can be no assurance that oil and
natural gas properties acquired by the Company will be successfully integrated
into the Company's operations or will achieve desired profitability objectives.
See "Business - Acquisition, Development, and Other Activities."
Exploration and Development Risks
The Company may increase its development and exploration activities.
Exploration drilling and, to a lesser extent, development drilling of oil and
natural gas reserves involve a high degree of risk that no commercial production
will be obtained and/or that production will be insufficient to recover drilling
and completion costs. The cost of drilling, completing and operating wells is
often uncertain. The Company's drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, including title problems, weather
conditions, compliance with governmental requirements and shortages or delays in
the delivery of equipment. The drilling of exploratory and development wells
involves risks such as encountering unusual or unexpected formations, pressures,
and other conditions that could result in the Company's incurring substantial
losses. Furthermore, completion of a well does not assure a profit on the
investment or a recovery of drilling, completion and operating costs.
Operating Hazards and Uninsured Risks
The Company's oil and natural gas business involves a variety of
operating risks, including, but not limited to, unexpected formations or
pressures, uncontrollable flows of oil, natural gas, brine or well fluids into
the environment (including groundwater contamination), blowouts, fires,
explosions, pollution and other risks, any of which could result in personal
injuries, loss of life, damage to properties and substantial losses. Although
the Company carries insurance at levels which it believes are reasonable, it is
not fully insured against all risks. The Company does not carry business
interruption insurance. Losses and liabilities arising from uninsured or
under-insured events could have a material adverse effect on the financial
condition and operations of the Company.
Marketing Risks
Substantially all of the Company's natural gas production is currently
sold to gas marketing firms or end users either on the spot market on a
month-to-month basis at prevailing spot market prices. For the year ended
December 31, 1997, one purchaser accounted for approximately 62% of the
Company's revenues. The Company does not believe that discontinuation of its
sales arrangement with such firm would be in any way disruptive to the Company's
natural gas marketing operations. See "Business - Competition, Markets,
Seasonality and Environmental and Other Regulation."
Hedging Risks
Historically, the Company has reduced its exposure to the volatility of
crude oil and natural gas prices by hedging a portion of its production. In a
typical hedge transaction, the Company will have the right to receive from the
counterparty to the hedge the excess of the fixed price specified in the hedge
over a floating price. If the floating price exceeds the fixed price, the
Company is required to pay the counter party all or a portion of this difference
multiplied by the quantity hedged, regardless of whether the Company has
sufficient production to cover the quantities specified in the hedge.
Significant reductions in production at times when the floating price exceeds
the fixed price could require the Company to make payments under the hedge
agreements even though such payments are not offset by sales of production. In
the past, the Company has hedged up to, but not more than, 50% of its
anticipated oil and natural gas production. Hedging also prevents the Company
from receiving the full advantage of increases in crude oil or natural gas
prices above the fixed amount specified in the hedge.
<PAGE>
Abandonment Costs
Due to the Company's number of offshore properties and production
facilities, government regulations and lease terms will require the Company to
incur substantial abandonment costs. As of December 31, 1997, total abandonment
costs for the Company's offshore properties estimated to be incurred through
2012 were approximately $11.3 million, net of restricted cash, described below.
Estimated abandonment costs have been included in determining estimates of the
Company's future net revenues from Proved Reserves included herein, and the
Company accounts for such costs through its provision for depreciation,
depletion and amortization. Under the terms of various agreements, the Company
is required to fund restricted cash accounts as a reserve for abandonment costs
on most of its offshore properties. See "Business - Plugging and Abandonment
Escrows."
Environmental and Other Regulations
The Company's operations are affected by extensive regulation pursuant
to various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering and marketing of oil and
natural gas. Matters subject to regulation include discharge permits for
drilling operations, drilling and abandonment bonds or other financial
responsibility requirements, reports concerning operations, the spacing of
wells, unitization and pooling of properties, and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting the rate of flow of oil and natural gas wells below actual
production capacity in order to conserve supplies of oil and natural gas.
Operations of the Company are also subject to numerous environmental
laws, including but not limited to, those governing management of waste,
protection of water, air quality, the discharge of materials into the
environment, and preservation of natural resources. Non-compliance with
environmental laws and the discharge of oil, natural gas, or other materials
into the air, soil or water may give rise to liabilities to the government and
third parties, including civil and criminal penalties, and may require the
Company to incur costs to remedy the discharge. Oil and gas may be discharged in
many ways, including from a well or drilling equipment at a drill site, leakage
from pipelines or other gathering and transportation facilities, leakage from
storage tanks, and sudden discharges from oil and gas wells or explosion at
processing plants. Hydrocarbons tend to degrade slowly in soil and water, which
makes remediation costly, and discharged hydrocarbons may migrate through soil
and water supplies or adjoining property, giving rise to additional liabilities.
Laws and regulations protecting the environment have become more stringent in
recent years, and may in certain circumstances impose retroactive, strict, and
joint and several liabilities rendering entities liable for environmental damage
without regard to negligence or fault. From time to time, the Company has agreed
to indemnify sellers of producing properties from whom the Company has acquired
reserves against certain liabilities for environmental claims associated with
such properties. There can be no assurance that new laws or regulations, or
modifications of or new interpretations of existing laws and regulations, will
not increase substantially the cost of compliance or otherwise adversely affect
the Company's oil and natural gas operations and financial condition or that
material indemnity claims will not arise against the Company with respect to
properties acquired by the Company. While the Company does not anticipate
incurring material costs in connection with environmental compliance and
remediation, it cannot guarantee that material costs will not be incurred. See
"Business - Competition, Markets, Seasonality and Environmental and Other
Regulation."
Competition
There are many companies and individuals engaged in the exploration for
and development of oil and natural gas properties. Competition is particularly
intense with respect to the acquisition of oil and natural gas producing
properties and securing experienced personnel. The Company encounters
competition from various independent oil companies in raising capital and in
acquiring producing properties. Many of the Company's competitors have financial
resources and staffs considerably larger than the Company. See "Business
Competition, Markets, Seasonality and Environmental and Other Regulation."
<PAGE>
Dependence Upon Key Personnel
The success of the Company will depend almost entirely upon the ability
of a small group of key executives to manage the business of the Company. Should
one or more of these executives leave the Company or become unable to perform
his duties, no assurance can be given that the Company will be able to attract
competent new management. The key executives do not have employment contracts.
See "Directors and Executive Officers of the Registrant."
Item 2. Properties.
The Company has grown through the acquisition of producing properties
and the subsequent application of advanced technology such as 3-D Seismic to
exploit potential producing zones which have been overlooked or bypassed by
previous operators.
Since 1990, the Company has made five acquisitions of producing
properties for a total of $98.0 million, which properties had Proved Reserves of
approximately 116 Bcfe as of their respective acquisition dates. As of December
31, 1997, the Company had Proved Reserves of 100.7 Bcfe with a SEC PV-10 of
$129.0 million. Approximately 83% of the Company's total SEC PV-10 are
classified as Proved Developed Reserves and approximately 73% of the Company's
total Proved Reserves are natural gas.
The Company's primary producing properties are located along the Gulf
Coast in Texas and Louisiana and offshore in the federal and state waters of the
Gulf of Mexico. The Company owns interests in a total of 255 oil wells and 356
natural gas wells. The Company owns interests in 20 federal blocks in the Gulf
of Mexico and nine state water blocks and operates 55% of the 166 offshore
wells, based upon the SEC PV-10 value as of December 31, 1997. The Company's
non-operated offshore properties are operated by large independents and major
oil companies, including Unocal, Phillips, Texaco, Coastal, Anadarko and
Burlington. The 445 onshore wells account for 14.5% of the Company's total SEC
PV-10 value as of December 31, 1997. The Company operates 55% of the onshore
wells, based upon such SEC PV-10 value. The Company also owns interests in 22
offshore production platforms and 69 miles of offshore oil and natural gas
pipelines with diameters of 10" or larger.
The following table sets forth certain information with respect to the
Company's significant properties as of December 31, 1997. These properties
represent 83% of the aggregate SEC PV-10 value of the Company.
<TABLE>
<CAPTION>
Total Proved % of
Working Reserves SEC PV-10 Total
Field Interests Wells Operator MBbls Bcf Value(000s) SEC PV-10
<S> <C> <C> <C> <C> <C> <C>
Umbrella Point 80-100% 19 PANACO 1,858 20.8 $ 33,304 26%
High Island 309 50% 16 Coastal 122 14.2 23,149 18%
East Breaks 160 33.3% 15 Unocal 1,143 9.8 23,062 18%
West Delta Fields 100% 35 PANACO 278 10.8 17,447 14%
East Breaks 109 100% 9 PANACO 6 4.5 8,375 7%
- ---------------------- ------------------ --------- ---------------- ------- ------- --------------- --------------
Total 94 3,407 60.1 $105,337 83%
</TABLE>
<PAGE>
Umbrella Point Field
Since its discovery in 1957 by Sun Oil, the Umbrella Point Field has
produced over 17 MMbbls of oil and 100 Bcf of natural gas from 35 wells. The
Company owns 100% of the working interest in Texas State Leases 73,74,87 and 88
in Trinity Bay, Chambers County, Texas, that encompass the field. Field
production is gathered on a small platform complex in approximately 10' of water
and transported via a Company owned 5 mile oil pipeline to the Company's onshore
production facility at Cedar Point. Gas production is transported through a
Midcon Pipeline Co. of Texas pipeline.
The Umbrella Point Field consists of multiple stacked reservoirs.
Production is from 13 main reservoirs from 7,700' to 9,000'. Prior to Goldking's
control of the field, it was developed and produced by two different operators
each controlling two state leases which created a competitive drainage
situation. This situation resulted in several reservoirs that were abandoned
prematurely as the former operators tried to accelerate production in uphole
reservoirs. Consequently, significant development work remains to sufficiently
drain the abandoned reservoirs. On January 21, 1998 the Company announced the
successful completion of its first well in the Umbrella Point Field. The well
flowed 11.5 MMcf and 220 barrels of condensate per day through a 20/64ths choke
with flowing tubing pressure of 5,600 PSIG. The Company owns an 80% working
interest in the well. The remaining 20% is owned by Midcon Gas Services Corp.
High Island 309 Field
The Company purchased its interest in the High Island Block A-309 Field
from Amoco in October of 1996 and has a 50% working interest. The field consists
of the High Island blocks A-309 and A-310 in approximately 200' of water.
Production is from three faulted anticlines with 18 productive reservoirs.
Coastal Oil and Gas Corp. operates this property and has conducted an evaluation
of reprocessed proprietary 3-D Seismic surveys resulting in significant drilling
activity in 1997. The Company has drilled new wells, sidetracked existing wells
into new formations and recompleted existing wells in new formations. The field
is currently producing 60 MMcf per day of natural gas and 77 Bbl per day of
condensate compared to 15 MMcf per day and 6 Bbl per day of condensate at the
beginning of 1997. The Company believes that continued review of the 3-D Seismic
may result in additional development.
East Breaks 160 Field
The Company acquired a 33.3% interest in this field as part of the Amoco
Acquisition in October 1996. The field consists of two federal offshore blocks,
East Breaks 160 and 161, with a production platform set in 925' of water placing
this production facility on the edge of deep water. The field is operated by
Unocal and production is from 12 separate reservoirs. Unocal acquired
proprietary 3-D Seismic over the field in 1990 and has identified the
undeveloped locations. The Proved Developed Producing Reserve value is
proportionately dispersed among eleven producing wells decreasing the risk to
some degree. The undeveloped locations included are based on seismic
interpretation of attic reserves. The facility also receives processing fees
from Mobil Oil Corp. related to a subsea well drilled in Block 117. Because of
the strategic location of the platform on the edge of deepwater, the facility
has potential for additional processing and handling fees as more nearby
discoveries are made and tied into the platform. In addition to the property
interests acquired, the Company purchased a 33.3% interest in a 12.67 mile 12"
natural gas pipeline connecting the East Breaks Block 160 platform to the High
Island Offshore System ("HIOS") a natural gas pipeline system in the Gulf of
Mexico and a 33.3% interest in a 17.47 mile 10" oil pipeline connecting the
platform to the High Island Pipeline System ("HIPS"), a crude oil pipeline
system in the Gulf of Mexico. Currently such firms as Exxon, Reading and Bates
and Santa Fe Energy are actively exploring in the East Breaks Area and the
Company believes that, due to the ongoing deepwater exploration in the Area, the
Company's platform and pipelines will become long term strategic revenue
generating assets after the field reserves are depleted.
<PAGE>
West Delta Fields
These properties consist of 13,565 acres in Blocks 52 through 56 and Block
58 in the West Delta Area, offshore Louisiana. The West Delta Fields were
acquired from Conoco, Inc., Atlantic Richfield Company (now Vastar Resources,
Inc.), OXY USA, Inc. and Texaco Exploration and Production, Inc. in May 1991.
The Company has an 87.5% net revenue interest in the field, subject to a
5% net profits interest on the shallower reservoirs in favor of the Company's
former lenders and a 4.166% overriding royalty interest on the deeper reservoirs
in favor of Conoco and OXY. The Company is the operator and generally owns 100%
of the working interest in these wells. Presently, the properties have 36 wells,
five of which were recently drilled, which produce from depths ranging from
1,200' to 12,500'. Because of the existing surface structures and production
equipment, additional wells can be added on the properties with lower completion
costs.
The main production facility on the West Delta Fields is a four platform
complex designated as Tank Battery #3. There are three ancillary platforms and
one three well production platform in the eastern portion of the properties
connected to Tank Battery #3. In the western portion there is one production
platform designated as Platform "D" in Block 58, with three wells. The remaining
30 wells are located on satellite structures connected to Tank Battery #3 or one
of its ancillary platforms. Eight wells produce oil and natural gas, with the
remaining wells producing only natural gas. In 1997 the Company replaced the
pipeline connecting "D" Platform in Block 58 with Tank Battery #3 in Block 54
with two new 6" pipelines, and installed a new 4" pipeline connected "C"
Platform with "D" Platform.
The field is characterized by multiple reservoirs with significant
workover and recompletion potential. Proved producing reserves are based on an
established consistent production history. The behind pipe reserves are
generally uphole recompletions with reserves based on volumetric estimates.
Currently there are no Proved Undeveloped Reserves assigned to the field. The
Company has been historically successful increasing rates and reserves through
the use of horizontal wells and coiled tubing operations. In 1994 the company
drilled 4 horizontal wells in the field increasing production 34% and
accelerating reserves. The Company is also using coiled tubing technology with
increasing frequency to avoid costly rig workovers.
The Company has farmed out the deep rights in West Delta Blocks 53
through 56 to Ocean Energy, Inc. (formerly Flores & Rucks, Inc.) which has
committed to fund a new 3-D Seismic survey. The Company retains all presently
producing reservoirs and shallow horizons. The Company will have the option of
retaining a 12 1/2% overriding royalty interest or participating up to 50% as a
working interest owner in any wells drilled by Ocean Energy. Due to the
complexity of the geology and the long history of production, the Company
believes that the evaluation of the 3-D Seismic over the produced reservoirs
will create significant additional development and exploitation opportunities.
In addition the Company believes that evaluation of the deeper potential by
Ocean Energy will create exploration opportunities with the Company having the
option to limit capital exposure.
During 1994 the Company farmed out the deep rights (below 11,300') to an
1,875 acre parcel in Block 58 and sold "C" Platform to Energy Development
Corporation which drilled a successful well to 16,500'. Production commenced in
April, 1995. The Company has a 15% overriding royalty interest in that acreage.
The well is currently producing 9,800 Mcf per day and 835 Bbls of condensate per
day. Energy Development Corporation was subsequently acquired by Samedan Oil
Corporation.
The Company generated a prospect in the northern portion of West Delta
Block 58 using 3-D Seismic, which it farmed out to Tana Oil & Gas Corporation in
1996. Tana drilled a successful well to 12,800' which encountered 85' of net pay
and is currently producing 12,300 Mcf per day. The Company retained an
overriding royalty interest in the farmout, which was converted to a 25% working
interest at payout on September 26, 1997.
In connection with the acquisition of the West Delta offshore properties
the Company provides the sellers with a $4,100,000 plugging and abandonment bond
collateralized in part with a bank escrow account. See "The Company - Plugging
and Abandonment Escrows".
<PAGE>
East Breaks 109 Field
The Company acquired a 100% interest in the East Breaks 109 Field from
Zapata in July of 1995. The field consists of East Breaks Blocks 109 and 110.
The Company operates this field which produces from six wellbores. There are no
proved behind pipe or undeveloped reserves associated with the field. Over 90%
of the field value are in the A-2 well completed in the TW-3 sand. This well is
the last remaining producer in a large reservoir that has produced over 50 BCF.
The A-2 well is currently making approximately 4,400 Mcf per day with no
reported water production.
In addition to the mineral interests acquired, the Company purchased
the 100% interest in a 31 mile 10" natural gas pipeline connecting the East
Breaks 110 platform to the High Island Offshore System and a 22 mile 4" oil
pipeline which connects the East Breaks 110 platform with the High Island
Pipeline System. The HIOS and HIPS systems are the primary oil and natural gas
pipelines in this region of the Gulf of Mexico.
The Company's East Breaks 110 platform has significant excess capacity
for both crude oil and natural gas. Prior to the Company acquiring the property,
Zapata had entered into a Facilities Sharing Agreement with AGIP Petroleum
Company, Inc. ("AGIP") to operate and process for AGIP's subsea wells in Blocks
112 and 157. Under the agreement AGIP pays certain fees to the Company and split
the cost of operating the East Breaks 110 platform with the Company, based on
each company's proportion of the production. A portion, not to exceed $6
million, of the monies earned pursuant to this agreement is being paid to Zapata
as part of the acquisition of the properties.
The purchase price for the Zapata properties included a production
payment to Zapata based upon future production from the East Breaks 109 Field
after production of 12 Bcfe gross (10 Bcfe net) measured from October 1, 1994.
The Company will pay to Zapata $.4167 per Mcfe on the next 27 Bcfe of gross
production, if that much is produced. The Company's oil and natural gas reserves
are stated net of this production payment.
Other Properties
Great River/Fort St. Phillips Fields. The Company acquired the Great
River (33 1/3% working interest) and Fort St. Phillips (43 1/3% working
interest) Fields as part of the Goldking acquisition. The Company operates both
properties, which total 1,688 acres and are geologically located on the same
fault and only two miles apart. These fields are low relief anticlinal
structures with stacked reservoirs from 7,600' to 10,000'. The reserves are
spread over three active completions in two zones. Behind pipe reserves were
assigned to four sands considering analogous performance. The Proved Undeveloped
reserves that have been identified in the fields represent attic gas
accumulations. New shallow sands and deeper pay were encountered with the SL
#14645 #1 re-entry well. More wells are being considered to further develop the
shallow and deep pay sands.
High Island A-302 Field. High Island Block A-302 acquired from Amoco in
1996 is in approximately 200' of water. The Company owns a 33.3% working
interest and Unocal Corporation is the operator. Production is from four
producing horizons on a faulted anticlinal structure. A speculative 3-D survey
was shot in 1991 and processed in 1992.
High Island A-330 Field. The field consists of three blocks, High
Island A-330, High Island A-349 and West Cameron 613, located in 280' of water.
The Company owns a 12% working interest , which it acquired from Amoco in 1996.
Coastal Oil and Gas Corporation is the operator. Three wells were recompleted in
1996. This field produces from a faulted anticline with 24 productive horizons.
Significant upside potential was delineated by a recently shot 3-D Seismic
survey. A well in West Cameron Block 613 has been proposed by the operator for
1998 to offset a field operated by Shell Offshore in Block A-350.
High Island A-474 Field. This field consists of three full blocks in
the High Island Area, A-474, A-489, A-499, and part of Block A- 475. The water
depth is 250' to 285' and Phillips Petroleum Company is the operator. In 1996
the Company acquired from Amoco a 12% working interest in Blocks A-474 and
A-489, a 13.1% working interest in Block A-499, and a 12% working interest in
Block A-475. There are 23 productive horizons in this faulted anticline. A
proprietary 3-D Seismic survey was shot in 1991 and processed in 1993.
West Cameron 180 Field. This field consists of a single block, West
Cameron 144, in 40' of water. Texaco is the operator. The Company acquired its
12.5% working interest from Amoco in 1996. The producing feature is a
north-plunging faulted anticline that underlies West Cameron Blocks 173 and 180.
There are three productive horizons. A new well was completed in January 1998
and is producing 17 MMcf and 250 barrels of condensate per day.
<PAGE>
East Cameron Block 359. The Company acquired its 30.7% working interest in
this field from Zapata in 1995. Anadarko Petroleum Corp. is the operator. The
property has eight wells and is in 330' of water. The platform also handles
production for a nearby field owned by others.
Eugene Island Block 372. This field was acquired in 1995 from Zapata.
Unocal Corp. is the operator and the Company owns a 25% working interest. The
property has seven wells and is in 414' of water.
South Timbalier 185. The Company acquired this field in 1995 from
Zapata. The Company owns a 7.7% working interest and Burlington Resources, Inc.
is the operator. The property has eleven wells and is in 180' of water. One of
the partners, Hall-Houston Oil Co., has proposed a 14,500' exploratory well on
the block, to be drilled in 1998.
West Cameron Block 538. This field is operated by the Company and it owns a
35.3% working interest. The property was acquired from Zapata in 1995. It has
six wells and is located in 194' of water.
Oil and Gas Information
Oil and Gas Information
The following tables set forth selected oil and natural gas information
for the Company, and certain forward-looking information about its properties.
Future results may vary significantly from the amounts reflected in the
information set forth herein because of normal production declines and future
acquisitions. See "Risk Factors - Uncertainty of Estimates of Reserves and
Future Net Cash Flows" and "Finding and Acquiring Additional Reserves;
Depletion." The following information on Proved Reserves, future net cash flows
from Proved Reserves and the SEC PV-10 value of such estimated future net cash
flows for the Company's properties as of December 31, 1997 were prepared by
independent petroleum engineers, Ryder Scott Company, W.D Von Gonten & Co. and
McCune Engingeering, P.E.
Proved Reserves (a)
The following table sets forth information as of December 31, 1997 as
to the estimated Proved Reserves attributable to the Company's properties.
Oil and liquids (Bbl):
Proved Developed Reserves ...................3,194,436
Proved Undeveloped Reserves..................1,311,927
Total Proved Reserves...................4,506,363
Natural gas (Mcf):
Proved Developed Reserves ..................55,689,723
Proved Undeveloped Reserves.................17,942,400
Total Proved Reserves..................73,632,123
- -------------
(a) Calculated by the Company in accordance with the rules and regulations of
the SEC, based upon December 31, 1997 prices of $17.50 per Bbl of oil and
$2.48 per Mcf of natural gas, adjusted for basis differentials, Btu
content of natural gas and specific gravity of oil. The Company's
independent reservoir engineers prepare a reserve report as of the end of
each calendar year.
<TABLE>
<CAPTION>
<PAGE>
Estimated Future Net Revenues
from Proved Reserves (a)
The following table sets forth information as of December 31, 1997 as
to the estimated future net revenues (before deduction of income taxes) from the
production and sale of the Proved Reserves attributable to the Company's
properties.
Proved Total
Developed Proved
Reserves Reserves
---------- -----------
Estimated Future net revenues (b):
<S> <C> <C> <C>
1998 ..........................................$ 42,820,856 $ 43,147,160
1999 .......................................... 36,309,311 38,311,113
2000 .......................................... 18,707,049 26,064,936
2001 .......................................... 12,804,861 19,221,261
Thereafter..................................... 20,431,036 40,282,108
Total.......................................... $ 131,073,113 $ 167,026,578
Present value (10%) of estimated future net
revenues (SEC PV-10)...................... $ 121,922,266 $ 129,032,279
- ---------------
</TABLE>
(a) Calculated by the Company in accordance with the rules and regulations
of the SEC, based upon December 31, 1997 prices of $17.50 per Bbl of
oil and $2.48 per Mcf of offshore natural gas, adjusted for basis
differentials, Btu content of natural gas and specific gravity of oil.
The Company's independent reservoir engineers prepare a reserve report
as of the end of each calendar year.
(b) Estimated future net revenues represent estimated future gross revenues
from the production and sale of Proved Reserves, net of estimated
operating costs, future development costs estimated to be required to
achieve estimated future production and estimated future costs of
plugging offshore wells and removing offshore structures.
<TABLE>
<CAPTION>
Production, Price, and Cost Data
The following table sets forth certain production, price, and cost
data with respect to the Company's properties for the three years ended December
31, 1997, 1996 and 1995.
For the year ended December 31,
1995 1996(a) 1997
------------- ------------- -----------
Oil and Condensate:
<S> <C> <C> <C>
Net Production (Bbls)(b) 170,000 276,000 515,000
Revenue $ 2,853,000 $ 5,356,000 $ 9,287,000
Average net Bbl per day 466 756 1,411
Average price per Bbl $ 16.78 $ 19.42 $ 18.04
Natural Gas:
Net Production (Mcf)(b) 9,850,000 6,788,000 11,468,000
Revenue $ 15,594,000 $ 14,707,000 $ 28,554,000
Average net Mcf per day 27,000 18,600 31,400
Average price per Mcf $ 1.58 $ 2.17 $ 2.49
Total Revenues $ 18,477,000 $ 20,063,000 $ 37,841,000
Production Cost:
Production cost $ 8,055,000 $ 8,477,000 $ 11,305,000
Mcfe(c) 10,870,000 8,444,000 14,557,000
Production cost per Mcfe(c) $ .74 $ 1.00 $ .78
- --------------
</TABLE>
(a) The information shown for 1996 was impacted by the fire on April 24th at
West Delta Tank Battery #3, which resulted in those fields being off
production until October 7, 1996. For that reason management would not
consider this data to be indicative of the future. Also this information
includes Bayou Sorrel Field through September 1, the date of its sale, and
includes information with respect to the Amoco Properties only from October
8, 1996.
(b) Production information is net of all royalty interests, overriding royalty
interest and the net profits interest in the West Delta Fields owned by the
Company's former lenders.
(c) Oil production is converted to Mcfe at the rate of 6 Mcf per Bbl,
representing the estimated relative energy content of natural gas to oil.
<PAGE>
Productive Wells (a)
The following table sets forth the number of productive oil and
natural gas wells, as of December 31, 1997, attributable to the Company's
properties.
Productive Wells Company Operated
Gross productive offshore wells (b):
Oil ........................ 50 24
Natural Gas ................. 116 46
Total ................... 166 70
Net productive offshore wells (c):
Oil ........................ 30 24
Natural Gas ................. 59 42
Total ................... 89 66
Gross productive onshore wells (b):
Oil ........................ 205 62
Natural Gas ................. 240 14
Total ................... 445 76
Net productive onshore wells (c):
Oil .................... 69 57
Natural Gas ............. 12 7
Total ............... 81 64
- ----------
(a)Productive wells consist of producing wells and wells capable of
production, including shut-in wells and water disposal and injection
wells. One or more completions in the same borehole are counted as one
well.
(b) A "gross well" is a well in which a working interest is owned. The
number of gross wells represents the sum of the wells in which a
working interest is owned.
(c) A "net well" is deemed to exist when the sum of the fractional working
interests in gross wells equals one. The number of net wells is the
sum of the fractional working interests in gross wells.
Leasehold Acreage
The following table sets forth the developed acreage as of December 31,
1997, attributable to the Company's properties.
Developed onshore acreage (a):
Gross acres (b)................................. 82,513
Net acres (c)................................... 6,354
Undeveloped onshore acreage (a):
Gross acres (b)................................. 4,212
Net acres (c)................................... 1,105
Developed offshore acreage (a):
Gross acres (b)................................. 113,537
Net acres (c)................................... 46,849
Undeveloped offshore acreage (a)(d):
Gross acres (b)................................. 57,380
Net acres (c)................................... 7,280
- ----------
(a) Developed acreage is acreage assignable to productive wells.
(b) A "gross acre" is an acre in which a working interest is owned. The
number of gross acres represents the sum of the acres in which a
working interest is owned.
(c) A "net acre" is deemed to exist when the sum of the fractional working
interests in gross acres equals one. The number of net acres is the
sum of the fractional working interests in gross
acres
(d) In addition to these acres, the Company's undeveloped offshore
potential exists at greater depths beneath existing producing
reservoirs.
<PAGE>
Drilling Activities
The following table sets forth the number of gross productive and dry wells
in which the Company had an interest, that were drilled and completed during the
five years ended December 31, 1997. Such information should not be considered
indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled and
the oil and natural gas reserves generated thereby or the costs to the Company
of productive wells compared to the costs to the Company of dry wells.
Developmental Wells Exploratory Wells
Completed Dry Completed Dry
Oil Gas Oil Gas Oil Gas Oil Gas
1993 3 -- -- -- -- -- -- --
1994 5 4 -- -- -- 1 -- --
1995 -- -- -- -- -- -- -- 3
1996 -- -- 2 -- -- -- -- --
1997 6 13 -- 1 -- -- -- --
Total 14 17 2 1 -- 1 -- 3
Title to Oil and Gas Properties
In the case of acquired properties title opinions are obtained for the
more significant properties. Prior to the commencement of drilling operations a
thorough drill site title examination is conducted and curative work performed
with respect to significant defects.
Unproved Properties
The Company retained a 3% overriding royalty interest in depths that
are below 11,000' when it sold the Bayou Sorrel Field to National Energy Group,
Inc. Two successful wells were drilled to these depths from which the company
derives revenue. In connection with the Amoco and Goldking acquisitions, the
Company acquired what management believes to be further reserve potential, not
quantified in its proved reserve evaluations, generally at greater depths than
previously developed. A portion of the respective purchase prices was allocated
to these unproved properties.
Gas Plant
The Company owns an approximate 1% interest in the Yscloskey Gas Plant,
a joint venture operation with Warren Petroleum serving as operator for 30
producer/owners. The plant is located in St. Bernard Parish, Louisiana, on state
highway 46. It is a steam plant of refrigerated absorption oil design with a
rated gas throughput of 1,850 million cubic feet of gas per day. It generates
its own power with four 2,500-kilowatt steam driven generators. Inlet gas is
transported from field delivery points throughout southeastern Louisiana and
offshore Gulf of Mexico by Tennessee Gas Pipeline and residue is returned back
to the pipeline. Sixty percent of the liquid production, plus all the ethane, is
delivered by pipeline to Shell Norco Fractionation Plant. The remaining forty
percent, less ethane, is delivered by pipeline to the Western Gas Resources
Plant at Toca for fractionation.
The original plant was built in 1962 with a design throughput of 650
million cubic feet per day. In 1970 a second complete new plant was built with a
design of 1,850 million cubic feet per day. In 1975 an extension process was
added to the new plant and the ethane recovery unit was put in Plant "B." The
plant is processing about 1.5 billion cubic feet per day with an average
production of 29,000 barrels per day of total liquids.
Forward-looking Statements
Forward-looking statements in this Form 10-K, future filings by the
Company with the Securities and Exchange Commission, the Company's press
releases and oral statements by authorized officers of the Company are intended
to be subject to the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995. Investors are cautioned that all forward-looking statements
involve risks and uncertainty, including without limitation, the risk of a
significant natural disaster, the inability of the Company to insure against
certain risks, the adequacy of its loss reserves, fluctuations in commodity
prices, the inherent limitations in the ability to estimate oil and gas
reserves, changing government regulations, as well as general market conditions,
competition and pricing. The Company believes that forward-looking statements
made by it are based on reasonable expectations. However, no assurances can be
given that actual results will not differ materially from those contained in
such forward-looking statements. The words "estimate", "anticipate", "expect",
"predict", "believe" and similar expressions are intended to identify
forward-looking statements.
<PAGE>
Item 3. Legal Proceedings.
The Company is presently a party to several legal proceedings, which it
considers to be routine and in the ordinary course of its business. Management
has no knowledge of any pending or threatened claims that could give rise to any
litigation which management believes would be material to the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5. Market for Common Stock and Related Shareholder Matters.
The authorized capital shares of the Company consist of 40,000,000
Common Shares, par value $.01 per share, and 5,000,000 preferred shares, par
value $.01 per share. The following description of the capital shares of the
Company does not purport to be complete or to give full effect to the provisions
of statutory or common law and is subject in all respects to the applicable
provisions of the Company's Certificate of Incorporation and the information
herein is qualified in its entirety by this reference.
Common Shares
The Company is authorized by its Certificate of Incorporation, as
amended, to issue 40,000,000 Common Shares, of which 23,920,282 shares are
issued and outstanding as of the date hereof and are held by over 6,700
shareholders, based upon information available on individual security position
listings.
The holders of Common Shares are entitled to one vote for each share
held on all matters submitted to a vote of common holders. The Common Shares
have no cumulative voting rights, which means that the holders of a majority of
the Common Shares outstanding can elect all the directors if they choose to do
so. In that event, the holders of the remaining shares will not be able to elect
any directors.
Each Common Share is entitled to participate equally in dividends, as
and when declared by the Board of Directors, and in the distribution of assets
in the event of liquidation, subject in all cases to any prior rights of
outstanding preferred shares. The Common Shares have no preemptive or conversion
rights, redemption rights, or sinking fund provisions. The outstanding Common
Shares are duly authorized, validly issued, fully paid, and nonassessable.
During forth quarter the Company issued 834 Common Shares to a former
director as a directors fee and 2,315 Common Shares as a restricted stock award
to a new director for coming on the board. The exemption from registration
relied upon was that of Section 4(2) of the Securities Act of 1933.
Warrants & Options
The Company has outstanding options to acquire 1,190,000 Common Shares
at a price of $4.45 per share, expiring June 20, 2000. These options are all
held by employees of the Company. They contain limited provisions for adjustment
of the number of shares in the event of a subdivision, combination or
reclassification of Common Shares. They do not have any rights to demand
registration or "piggy back" rights in the event of a registration of Common
Shares.
A group of the Company's former lenders, were issued warrants to
acquire 2,060,606 Common Shares at $4.125 per share, expiring December 31, 1998,
which Common Shares would be restricted securities within the meaning of the
Securities Act of 1933 and can only be sold pursuant to an exemption from
registration or an offering which is the subject of an effective registration
statement. The holders of these shares, after exercise, will have the right to
demand registration of the shares or "piggy back" in the event the Company
registers an offering of its Common Shares.
Preferred Shares
Pursuant to the Company's Certificate of Incorporation, the Company is
authorized to issue 5,000,000 preferred shares, and the Company's Board of
Directors, by resolution, may establish one or more classes or series of
preferred shares having the number of shares, designations, relative voting
rights, dividend rates, liquidation and other rights preferences, and
limitations that the Board of Directors fixes without any shareholder approval.
<PAGE>
A number of preferred shares equal to one share for every one hundredth
of one Common Share outstanding has been reserved for issuance pursuant to the
Company's Shareholder Rights Plan, and designated as Series A Preferred Shares.
No shares of this Series A Preferred Shares have been issued or are outstanding.
Other than the designation as Series A, the Series A Preferred Shares have not
had designations, preferences and rights established by the Board of Directors.
See "Shareholder Rights Plan," below. The designations, preferences and rights
will be established if and when any of the Series A Preferred Shares are to be
issued.
Transfer Agent
The transfer agent, registrar and dividend disbursing agent for the
Common Shares is American Stock Transfer and Trust Company, 6201 15th Avenue,
Brooklyn, New York 11204.
Price Range of Common Shares
The Common Shares are quoted on the National Association of Securities
Dealers, Inc. Automated Quotation System ("NASDAQ") - National Market, under the
symbol "PANA". They commenced trading September 21, 1989. The following table
sets forth, for the periods indicated, the high asked and low bid prices for the
Common Shares.
1996
======
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
High 5 4 1/2 6 6 3/8
Low 3 7/16 3 11/16 3 3/8 4 3/8
1997
======
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
High 5 1/4 4 5/8 5 5 9/16
Low 3 5/8 3 3/4 3 7/8 3 9/16
On March 31, 1998, the last sale price of the Common Shares as reported on
the NASDAQ-NM was $ 4.44 per share.
Dividend Policy
The Company has not paid any cash dividends on the Common Shares. The
Delaware General Corporation Law, to which the Company is subject, permits the
Company to pay dividends only out of its capital surplus (the excess of net
assets over the aggregate par value of all outstanding capital shares) or out of
net profits for the fiscal year in which the dividend is declared or the
preceding fiscal year. The New Credit Facility and the Senior Notes contain
restrictions on any dividends or distributions by the Company and on any
purchases by the Company of Common Shares. The Company retains its earnings and
cash flow to finance the expansion and development of its business and currently
does not intend to pay dividends on the Common Shares. Any future payments of
dividends will depend on, among other factors, the earnings, cash flow,
financial condition, and capital requirements of the Company.
Shareholder Rights Plan
On August 2, 1995, the Board of Directors declared a dividend
distribution of one Right for each outstanding Common Share of the Company to
the shareholders of record on August 3, 1995, (the "Record Date"). Each Right
entitles the registered holder to purchase from the Company one one-hundredth of
one share of the Series A Preferred Shares (the "Preferred Shares"), or in some
circumstances, Common Shares, other securities, cash or other assets as
summarized below, at a price of $30.00 per share (the "Purchase Price"), subject
to adjustment. The description and terms of the Rights are set forth in a Rights
Agreement (the "Rights Agreement") between the Company and American Stock
Transfer and Trust Company, as Rights Agent.
The Shareholder Rights Plan was designed to reduce the likelihood of
inadequate bids, partial bids, market accumulations and front-end loaded offers
to acquire the Company's Common Shares, which are not in the best interest of
all the Company's shareholders. The adoption of the Plan communicates the
Company's intention to resist such actions as are not in the best interest of
all shareholders and provides time for the Board of Directors to consider any
offer and seek alternative transactions to maximize shareholder value. The Plan
was adopted upon the advice of the Company's investment bankers in 1995.
<PAGE>
Until the earlier to occur of (i) the date of a public announcement
that a person or group of affiliated or associated persons (an "Acquiring
Person") acquired, or obtained the right to acquire, beneficial ownership of 20%
or more of the outstanding Common Shares or (ii) ten days following the
commencement or announcement of an intention to make a tender offer or exchange
offer that would result in a Person or group beneficially owning 20% or more of
such outstanding Common Shares (the earlier of such dates being called the
"Distribution Date"), the Rights will be evidenced, with respect to any of the
Company's Common Share certificates outstanding as of the Record Date, by such
Common Share certificate. The Rights Agreement provides that, until the
Distribution Date, the Rights will be transferred with and only with the Common
Shares. Until the Distribution Date (or earlier redemption or expiration of the
Rights), new Common Share certificates issued after the Record Date upon
transfer or new issuance of the Common Shares will contain a notation
incorporating the Rights Agreement by reference. Until the Distribution Date (or
earlier redemption or expiration of the Rights), the surrender for transfer of
any of the Company's Common Share certificates outstanding as of the Record,
will also constitute the transfer of the Rights associated with the Common
Shares represented by such certificate. As soon as practicable following the
Distribution Date, separate certificates evidencing the Rights ("Rights
Certificates") will be mailed to holders of record of the Common Shares as of
the close of business on the Distribution Date and such separate Rights
Certificates alone will evidence the Rights.
The Rights are not exercisable until the Distribution Date. The Rights
will expire on August 4, 2005, unless earlier redeemed by the Company as
described below.
The Purchase Price payable, and the number of Preferred Shares (or
Common Shares, other securities, cash or other assets, as may be necessary)
issuable upon exercise of the Rights are subject to adjustment from time to time
to prevent dilution (i) in the event of a stock dividend on, or a subdivision,
combination or reclassification of the Preferred Shares, (ii) upon the grant to
holders of the Preferred Shares of certain rights or warrants to subscribe for
Preferred Shares or convertible securities at less than the current market price
of the Preferred Shares or (iii) upon the distribution to holders of the
Preferred Shares of evidences of indebtedness or assets (excluding regular
periodic cash dividends out of earnings or retained earnings or dividends
payable in the Preferred Shares) or of subscription rights or warrants (other
than those referred to above).
In the event that the Company were acquired in a merger or other
business combination transaction of 50% or more of its assets or earning power
were sold, proper provision shall be made so that each holder of a Right, other
than of Rights that are or were beneficially owned by an Acquiring Person (which
will thereafter be void) shall thereafter have the right to receive, upon the
exercise thereof at the then current exercise price of the Right, that number of
common shares of the acquiring company which at the time of such transaction
would have a market value of two times the exercise price of the Right. In the
event that an Acquiring Person becomes the beneficial owner of 20% or more of
the outstanding Common Shares, proper provision shall be made so that each
holder of a Right, other than of Rights that are or were beneficially owned by
the Acquiring Person (which will thereafter be void), will thereafter have the
right to receive upon exercise that number of the Common Shares (or in certain
other circumstances, assets or other securities) having a market value of two
times the exercise price of the Right.
With certain exceptions, no adjustment in the Purchase Price will be
required until cumulative adjustments require an adjustment of at least 1% in
such Purchase Price. No fractional shares will be issued (other than fractional
shares which are integral multiples of one one-hundredth of one Preferred Share)
and, in lieu thereof, an adjustment in cash will be made based on the market
price of the Preferred Shares on the last Trading Date prior to the date of
exercise.
At any time prior to 5:00 P.M. Kansas City, Missouri time on the tenth
calendar day after the first date after the public announcement that a person or
group of affiliated or associated persons has acquired beneficial ownership of
20% or more of the outstanding Common Shares of the Company (the "Share
Acquisition Date"), the Company may redeem the Rights in whole, but not in part,
at a price of $0.005 per Right (the "Redemption Price"). Following the Share
Acquisition Date, but prior to an event listed in Section 13(a) of the Rights
Agreement, the Company may redeem the Rights in connection with any event
specified in Section 13(a) in which all shareholders are treated alike and which
does not include the Acquiring Person or his Affiliates or Associates.
Thereafter, the Company's right of redemption may be reinstated if an Acquiring
Person reduces his beneficial ownership to 10% or less of the outstanding Common
Shares in a transaction or series of transactions not involving the Company.
Immediately upon the action of the Board of Directors of the Company electing to
redeem the Rights, the Company shall make announcement thereof, and upon such
election, the right to exercise the Rights will terminate and the only right of
the holders of Rights will be to receive the Redemption Price.
<PAGE>
Until a Right is exercised, the holder thereof, as such, will have no
rights as a shareholder of the Company, including, without limitation, the right
to vote or to receive dividends.
The provisions of the Rights Agreement may be amended by the Board of
Directors in order to cure any ambiguity or correct any defect or inconsistency,
extend the Redemption Period and, prior to the Distribution Date, to make
changes deemed to be in the best interests of the holders of the Rights or,
after the Distribution Date, to make such other changes which do not adversely
affect the interests of the holders of the Rights (excluding the interests of
any Acquiring Person and its affiliates and associates).
Certain Anti-takeover Provisions
The provisions of the Company's Certificate of Incorporation and
By-laws summarized in the following paragraphs may be deemed to have an
anti-takeover effect and may delay, defer, or prevent a tender offer or takeover
attempt that a shareholder might consider to be in that shareholder's best
interests, including attempts that might result in a premium over the market
price for the shares held by shareholders. In addition, certain provisions of
Delaware law and the Company's Long-Term Incentive Plan may be deemed to have a
similar effect.
Certificate of Incorporation and By-laws. The Board of Directors of the
Company is divided into three classes. The term of office of one class of
directors expires at each annual meeting of shareholders, when their successors
are elected and qualified. Directors are elected for three-year terms.
Shareholders may remove a director only for cause. In general, the Board of
Directors, not the Company's shareholders, has the right to appoint persons to
fill vacancies on the Board of Directors.
Pursuant to the Company's Certificate of Incorporation, the Company's
Board of Directors, by resolution, may establish one or more classes or series
of preferred shares having the number of shares, designation, relative voting
rights, dividend rates, liquidation and other rights, preferences, and
limitations that the Board of Directors fixes without any shareholder approval.
Any rights, preferences, privileges, and limitations that are established could
have the effect of impeding or discouraging the acquisition of control of the
Company.
The Company's Certificate of Incorporation contains a "fair price"
provision that requires the affirmative vote of the holders of at least 80% of
the voting shares of the Company and the affirmative vote of at least two-thirds
of the voting shares of the Company not owned, directly or indirectly, by the
Related Person (hereafter defined) to approve any merger, consolidation, sale or
lease of all or substantially all of the assets of the Company, or certain other
transactions involving any Related Person. For purposes of the fair price
provision, a "Related Person" is any person beneficially owning 10% or more of
the voting shares of the Company who is a party to the Transaction at issue, a
director who is also an officer of the Company and is a party to the Transaction
at issue, an affiliate of either such person, and certain transferees of those
persons. The voting requirement is not applicable to certain transactions,
including those that are approved by the Company's Continuing Directors (as
defined in the Certificate of Incorporation) or that meet certain "fair price"
criteria contained in the Certificate of Incorporation.
The Company's Certificate of Incorporation further provides that
shareholders may act only at an annual or special meeting of shareholders and
not by written consent, that special meetings of shareholders may be called only
by the Board of Directors, and that only business proposed by the Board of
Directors may be considered at special meetings of shareholders.
The Company's Certificate of Incorporation also provides that the only
business (including election of directors) that may be considered at an annual
meeting of shareholders, in addition to business proposed (or persons nominated
to be directors) by the directors of the Company, is business proposed (or
persons nominated to be directors) by shareholders who comply with the notice
and disclosure requirements of the Certificate of Incorporation. In general, the
Certificate of Incorporation requires that a shareholder give the Company notice
of proposed business or nominations no later than 60 days before the annual
meeting of shareholders (meaning the date on which the meeting is first
scheduled and not postponements or adjournments thereof) or (if later) 10 days
after the first public notice of the annual meeting is sent to common
shareholders. In general, the notice must also contain certain information about
the shareholder proposing the business or nomination, his interest in the
business, and (with respect to nominations for director) information about the
nominee of the nature ordinarily required to be disclosed in public proxy
solicitations. The shareholder must also submit a notarized letter from each of
his nominees stating the nominee's acceptance of the nomination and indicating
the nominee's intention to serve as director if elected.
<PAGE>
The Certificate of Incorporation also restricts the ability of
shareholders to interfere with the powers of the Board of Directors in certain
specified ways, including the constitution and composition of committees and the
election and removal of officers.
The Certificate of Incorporation provides that approval by the holders
of at least two-thirds of the outstanding voting shares is required to amend the
provisions of the Certificate of Incorporation discussed in the preceding
paragraphs and certain other provisions, except that approval by the holders of
at least 80% of the outstanding voting shares of the Company, together with
approval by the holders of at least two-thirds of the outstanding voting shares
not owned, directly or indirectly, by the Related Person, is required to amend
the fair price provisions and except that approval of the holders of at least
80% of the outstanding voting shares is required to amend the provisions
prohibiting shareholders from acting by written consent.
Delaware Anti-takeover Statute. The Company is a Delaware corporation
and is subject to Section 203 of the Delaware General Corporation Law. In
general, Section 203 prevents an "interested shareholder" (defined generally as
a person owning 15% or more of the Company's outstanding voting shares) from
engaging in a "business combination" (as defined in Section 203) with the
Company for three years following the date that person became an interested
shareholder unless (a) before that person became an interested shareholder, the
Board of Directors of the Company approved the transaction in which the
interested shareholder became an interested shareholder or approved the business
combination, (b) upon consummation of the transaction that resulted in the
interested shareholder's becoming an interested shareholder, the interested
shareholder owns at least 85% of the voting shares of the Company outstanding at
the time the transaction commenced (excluding shares held by directors who are
also officers of the Company and by employee stock plans that do not provide
employees with the right to determine confidentially whether shares held subject
to the plan will be tendered in a tender or exchange offer), or (c) following
the transaction in which that person became an interested shareholder, the
business combination is approved by the Board of Directors of the Company and
authorized at a meeting of shareholders by the affirmative vote of the holders
of at least two-thirds of the outstanding voting shares of the Company not owned
by the interested shareholder.
Under Section 203, these restrictions also do not apply to certain
business combinations proposed by an interested shareholder following the
announcement or notification of one of certain extraordinary transactions
involving the Company and a person who was not an interested shareholder during
the previous three years or who became an interested shareholder with the
approval of a majority of the Company's directors, if that extraordinary
transaction is approved or not opposed by a majority of the directors who were
directors before any person became an interested shareholder in the previous
three years or who were recommended for election or elected to succeed such
directors by a majority of such directors then in office.
Long-Term Incentive Plan. Awards granted pursuant to the Company's
Long-Term Incentive Plan may provide that, upon a change in control of the
Company, (a) each holder of an option will be granted a corresponding stock
appreciation right, (b) all outstanding stock appreciation rights and stock
options become immediately and fully vested and exercisable in full, and (c) the
restriction period on any restricted stock award shall be accelerated and the
restrictions shall expire.
Debt. Certain provisions in the New Credit Facility and Senior Notes
may also impede a change in control, in that they provide that the Bank loans
and Senior Notes become due if there is a change in the management of the
Company or a merger with another company.
Item 6. Selected Financial Data.
The following historical selected consolidated financial data of the
Company are derived from, and qualified by reference to, the Company's
Consolidated Financial Statements and the notes thereto. The historical selected
financial data for the five years ended December 31, 1997 were derived from the
Company's audited consolidated financial statements. The information contained
in this table should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations," and the Consolidated
Financial Statements of the Company and the notes thereto included elsewhere
herein.
<PAGE>
<TABLE>
<CAPTION>
For the year ended December 31,
1993 1994 1995 1996 1997
======================================================
Summary of Operating Data: (dollars in thousands, except per share data)
<S> <C> <C> <C> <C>
Oil and natural gas sales $ 12,605 $ 17,338 $ 18,447 $ 20,063 $ 37,841
Depreciation, depletion & amortization
expense 4,288 6,038 8,064 9,022 18,866
Lease operating expense 5,297 5,231 8,055 8,477 11,305
Production and ad valorem taxes 754 1,006 1,078 559 721
Geological and geophysical expense -- -- -- -- 286
Exploratory dry hole expense -- -- 8,112 -- 67
General and administrative expense 542 587 690 772 1,764
Provision for losses on disposition
and write-downs of assets 3,824 1,202 751 -- --
West Delta fire loss -- -- -- 500 --
Net operating income (loss) $ (2,100) $ 3,274 $(8,303) $ 733 $ 4,832
Interest expense (net) 1,886 1,623 987 2,514 3,930
Gain (loss) on investment in
Common stock -- -- -- (258) 75
Extraordinary item- loss on early
retirement of debt -- (536) -- -- (934)
--------- ------- -------- -------- --------
Net income (loss) $ (3,986) $ 1,115 $ (9,290) $ (2,039) $ 43
========= ======= ======== ======== ========
Net income (loss) per Common Share $ (0.53) $ 0.11 $ (0.81) $ (0.16) $ --
Summary Balance Sheet Data:
Oil and gas properties (net) $ 19,183 $ 23,945 $ 29,485 $ 50,540 $112,548
Total assets 24,432 29,095 36,169 73,768 179,629
Long-term debt 12,465 12,500 22,390 49,500 101,700
Stockholders' equity 8,744 14,882 9,174 17,498 55,188
Dividends per Common Share -- -- -- -- --
Other Data:
EBITDA(a) $ 6,012 $ 10,514 $ 8,624 $ 10,255 $ 23,840
Capital expenditures(b) 842 12,128 21,841 43,050 41,997
- -----------
</TABLE>
(a) EBITDA is defined as net income (loss) before income taxes plus the
sum of depletion, depreciation and amortization, provisions for losses
and gains on disposition and write-down of assets, exploratory dry
hole expenses, interest expense and non-recurring charges. EBITDA is
not a measure of cash flow as determined by generally accepted
accounting principles. The Company has included information concerning
EBITDA because EBITDA is a measure used by certain investors in
determining the Company's historical ability to service its
indebtedness. EBITDA should not be considered as an alternative to, or
more meaningful than, net income or cash flows as determined in
accordance with generally accepted accounting principles or as an
indicator of the Company's operating performance or liquidity.
(b) Capital expenditures include cash expended for acquisitions plus
additions to oil and natural gas properties and other fixed assets,
without taking into consideration sales of capital assets.
<PAGE>
The following discussion should be read in conjunction with the
Company's Consolidated Financial Statements, "Selected Consolidated Financial
Data" and respective notes thereto, included elsewhere herein. The information
below should not be construed to imply that the results discussed herein will
necessarily continue into the future or that any conclusion reached herein will
necessarily be indicative of actual operating results in the future. Such
discussion represents only the best present assessment of management of the
Company. Because of the size and scope of the Company's recent acquisitions, the
results of operations from period to period are not necessarily comparative.
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
General
The oil and natural gas industry has experienced significant volatility
in recent years because of the fluctuatory relationship of the supply of most
fossil fuels relative to the demand for such products and other uncertainties in
the world energy markets. These industry conditions should be considered when
this analysis of the Company's operations is read.
The Company experienced a fire on April 24, 1996 at Tank Battery #3 in
the West Delta Fields resulting in these fields being shut-in from April 24th
until being returned to production on October 7, 1996. The fire resulted in lost
revenues estimated by management to be approximately $6,000,000.
The Company has spent $8,500,000 on Tank Battery #3 inclusive of the
$500,000 expensed during 1996 and has received reimbursement from its insurance
company of $3,900,000, after satisfaction of the $225,000 in deductibles. The
excess of expenditures over insurance reimbursement has been capitalized. The
Company has filed suits against the employers of the persons who caused the
incidents for recovery of these costs and its lost profits. No assurance can be
given that the Company will successfully recover any amounts sought in any such
suits.
Year 2000 Compliance
The Company does not expect that the cost to modify and replace its
information technology infrastructure to be Year 2000 compliant will be material
to its results of operations. The Company does not anticipate any material
disruption in its operations as a result of any failure by the Company to be in
compliance.
Liquidity and Capital Resources
On October 9, 1997, the Company issued $100 million principal amount of
10.625% Senior Notes due October 1, 2004. Interest on the Notes is payable
semi-annually in arrears on each April 1 and October 1, commencing April 1,
1998. Of the $96.2 million net proceeds, $54.7 million was used to repay
substantially all of the Company's outstanding indebtedness with the remaining
$41.5 million to be used for capital expenditures. At December 31, 1997 the
Company had $36.9 million in cash and $27.2 million in working capital.
On March 5, 1997, the Company completed an offering of 8,403,305 common
shares at $4.00 per share, $3.728 net of the underwriter's commission. The
offering consisted of 6,000,000 shares sold by the Company and 2,403,305 shares
sold by shareholders, primarily Amoco Production Company (2,000,000 shares) and
lenders advised by Kayne, Anderson Investment Management, Inc. (373,305 shares).
The Company's net proceeds of $22,000,000 from the offering were used to prepay
$13,500,000 of its 12% subordinated debt and the remainder was used to reduce
borrowings under the Company's bank facility.
In October 1997, the Company amended its bank facility. See "New Credit
Facility." The loan is a reducing revolver designed to provide the Company up to
$75 million depending on the Company's borrowing base, as determined by the
lenders. The Company's borrowing base at December 31, 1997 was $40 million, with
availability under the revolver of $39 million. The principal amount of the loan
is due October 22, 2002. However, at no time may the Company have outstanding
borrowings in excess of its borrowing base. Interest on the loan is computed at
the bank's prime rate or at 1 to 1 3/4% (depending upon the percentage of the
facility being used) over the applicable London Interbank Offered Rate ("LIBOR")
on Eurodollar loans. Eurodollar loans can be for terms of one, two, three or six
months and interest on such loans is due at the expiration of the terms of such
loans, but no less frequently than every three months. The bank facility is
collateralized by a first mortgage on the Company's offshore properties. The
loan agreement contains certain covenants including a requirement to maintain a
positive indebtedness to cash flow ratio, a positive working capital ratio, a
certain tangible net worth, as well as limitations on future debt, guarantees,
liens, dividends, mergers, material change in ownership by management, and sale
of assets.
<PAGE>
From time to time the Company has borrowed funds from institutional
lenders. In each case these loans were due at a stated maturity, required
payments of interest only at 12% per annum and were secured by a second mortgage
on the Company's offshore oil and gas properties. At December 31, 1996 such
loans totaled $22 million. The loans were all repaid during 1997.
At December 31, 1997, 70% of the Company's total assets were
represented by oil and natural gas properties, pipelines and equipment, net of
depreciation, depletion and amortization.
The product prices received by the Company, net of the impact
of hedge transactions discussed below, averaged $2.49 per Mcf for natural gas
and $18.04 per Bbl for oil for the year ended December 31, 1997. In 1997, the
Company's natural gas hedge transactions were based upon published gas pipeline
index prices instead of the NYMEX. This change mitigated the risk of the price
differential due to transportation. In 1997, 14,000 MMbtu per day was hedged, at
a swap price of $1.80 per MMbtu with varying levels of participation (93% in
January to 40% in September) in settlement prices above the $1.80 per MMbtu swap
price level. The Company has natural gas hedged in quantities ranging from
10,000 to 50,000 MMbtu's per day in each of the months in 1998 for a total of
11,980,000 MMbtu's, at pipeline prices averaging approximately $2.05 per MMbtu,
for a NYMEX equivalent of approximately $2.20 per MMbtu. The Company has hedged
7,356 MMbtu per day in 1999, all at an average pipeline index swap price of
$1.89 per MMbtu. The Company has hedged 218 MMbtu for each day in 2000 at an
average pipeline index swap price of $1.87. In 1997 the Company also hedged its
oil prices by selling the equivalent of 720 Bbls of oil per day at $20.00, with
a 40% participation in prices above the $20.00 swap price level. The Company
hedged 1,268 Bbls of oil for each day in 1998 at an average swap price of $19.06
per Bbl, with a 40% participation above $19.28 on 500 of the 1,268 Bbls. The
Company has hedged 223 Bbls of oil for each day in 1999 at an average price of
$17.27 per Bbl. The Company has hedged 232 Bbls of oil for each day in 2000 at
an average price of $17.28 per Bbl. Management has generally used hedge
transactions to protect its cash flows when the Company's levels of long-term
debt have been higher and refrained from hedge transactions when long-term debt
has been lower. For accounting purposes, gains or losses on hedge transactions
are recognized in the production month to which a hedge contract relates.
Pursuant to existing agreements, the Company is required to deposit
funds in bank trust and escrow accounts to provide a reserve against
satisfaction of its eventual responsibility to plug and abandon wells and remove
structures when certain fields no longer produce oil and natural gas. The
Company has entered into an escrow agreement with Amoco Production Company under
which the Company deposits, for the life of the fields, in a bank escrow account
ten percent (10%) of the net cash flow, as defined in the agreement, for the
Amoco properties. The Company has established the "PANACO East Breaks 110
Platform Trust" in favor of the Minerals Management Service of the U.S.
Department of the Interior. This trust required an initial funding of $846,720
in December 1996, and remaining deposits of $244,320 due at the end of each
quarter in 1999 and $144,000 due at the end of each quarter in 2000 for a total
of $2,400,000. In addition, the Company has $9,250,000 in surety bonds to secure
its plugging and abandonment operations.
In 1997, the Company spent $41,997,000 in cash for capital
expenditures, approximately $2,300,000 of which was for the completion of an oil
and natural gas pipeline in the West Delta Fields and the remainder was for
property acquisitions and development of its oil and natural gas properties.
For the years ended December 31, 1997 and 1996:
Results of Operations
Production. Natural gas production increased 69% to 11,468,000 Mcf in
1997 from 6,788,000 Mcf in 1996. Oil production increased 87% in 1997 to 515,000
Bbls, from 275,000 Bbls in 1996. Results for 1997 include production from the
former Amoco and Goldking properties, purchased in October 1996 and July 1997,
respectively. Results for 1997 also included increased production from the West
Delta Fields, which were shut-in from April 24, 1996 until October 1996. They do
not include production from the Bayou Sorrel Field which was sold September 1,
1996.
In March, 1997 the federal production from the West Delta Block 58 was
brought back on-line for the first time since April 1996 with the completion of
a dual six inch, eight mile pipeline to the West Delta central processing
facility, Tank Battery #3. This pipeline also allowed Samedan Corporation to
resume production from their well, drilled on a farm-out from the Company, on
which the Company receives overriding royalty revenue and fees for processing
the oil and low pressure natural gas.
<PAGE>
Prices. Natural gas prices, net of the impacts of hedging transactions,
increased from $2.17 per Mcf in 1996 to $2.49 in 1997. The 1997 natural gas
hedge program had the effect of reducing natural gas prices by only ($.10) per
Mcf in 1997, compared to ($.58) per Mcf in 1996. The 1997 hedge program allowed
the Company more participation in increases in market prices for natural gas,
while providing the price stability of no less than $1.80 per MMbtu on 14,000
MMbtu per day. Oil prices decreased in 1997 to $18.04 per Bbl from $19.42 per
Bbl in 1996.
"Oil and natural gas sales" increased 89% in 1997. Significant
increases in both natural gas and oil production were the primary factor in the
increase in revenues. The former Amoco and Goldking properties, acquired in
October 1996 and July 1997, respectively, coupled with the resumption of
production from the West Delta Fields, and the Company's development program on
the former Amoco properties has significantly increased production.
"Depletion, depreciation and amortization expense" increased
$9,844,000, or 109% also in part due to the purchase of the former Amoco
properties in October 1996. The amount per Mcf equivalent also increased from
$1.07 in 1996 to $1.30 in 1997, due to several factors. Downward engineering
revisions, in the West Delta and East Breaks 110 Fields at year-end 1996 were a
significant part of the increase. Also, $4,000,000 in capital expenditures made
during 1996 (over and above insurance reimbursement) to rebuild Tank Battery #3,
the central processing facility for the West Delta Fields, increased the
depletion cost per Mcf equivalent for those fields.
"Lease operating expense" increased $2,827,000, or 33% in 1997 with the
addition of interests in thirteen offshore blocks acquired in October 1996 from
Amoco and the interests in the properties acquired in the Goldking acquisition
in July 1997. As a percent of oil and natural gas sales, lease-operating
expenses decreased to 30% in 1997 from 42% in 1996.
"Production and ad valorem taxes" increased 29% in 1997, however, as a
percentage of oil and natural gas sales they decreased to 2%, from 3% of oil and
natural gas sales in 1996. The decrease is due to the Company's shift to federal
offshore waters where there are no state severance taxes.
"Geological and geophysical expense" in 1997 resulted from the
non-drilling exploratory costs incurred in the fourth quarter.
"Exploratory dry hole expense" incurred in 1997 resulted from an option
paid to participate in an exploratory well in the High Island Area, offshore
Texas which was condemned before the well was drilled because of a dry hole
drilled by another company on an adjacent block. There will be no further
exploration expenses associated with this prospect.
"General and administrative expense" increased $992,00 primarily as a
result of the Goldking acquisition. As a percentage of oil and natural gas
sales, general and administrative expenses increased to 5% in 1997 from 4% in
1996.
"Interest expense (net)" increased 56% in 1997 primarily due to the
increased average borrowing levels from the debt assumed in the Goldking
acquisition and to a lesser extent the offering of 10.625% $100,000,000 Senior
Notes in October 1997.
"Gain(loss) on investment in common stock" is the gain on the sale of the
Company's 477,612 shares of National Energy Group, Inc. common stock realized in
1997.
<PAGE>
For the years ended December 31, 1996 and 1995:
Capital Spending
In 1996, the Company made $43,000,000 in capital expenditures,
including $32,000,000 on the purchase of oil and natural gas assets from Amoco
Production Company, $4,000,000 for repair and rebuilding of the West Delta Tank
Battery #3, net of insurance reimbursements, and the remainder for development
of its oil and natural gas properties. The majority of the development costs
were incurred to drill two unsuccessful development wells in the Bayou Sorrel
Field and for the Company's share of successfully recompleting two wells on
Eugene Island Block 372, which is operated by Unocal Corporation.
Results of Operations
Production. Natural gas production decreased 31% to 6,788,000 Mcf in
1996 from 9,850,000 Mcf in 1995. Natural gas production from the West Delta
Fields decreased from 7,825,000 Mcf in 1995 to 2,058,000 Mcf in 1996, primarily
as a result of the fire on April 24, 1996. The Company's production would have
been much lower were it not for the Zapata acquisition in 1995 and the Amoco
acquisition in 1996.
Likewise, oil production from the West Delta Fields also decreased in
1996 when compared to 1995, from 132,000 Bbls to 57,000 Bbls. However, as with
natural gas, acquisitions offset the decrease from West Delta. The Bayou Sorrel
Field, which produces primarily oil, produced 93,000 Bbls in 1996 which, along
with the Amoco properties more than offsetting the decrease from West Delta.
Also, oil production from the Zapata Properties is included for the full year in
1996, with only the period of July 27 to December 31 included in 1995, also
offsetting the decrease from West Delta. These factors resulted in a 62%
increase in oil production, from 170,000 Bbls in 1995 to 276,000 Bbls in 1996.
On a Mcf equivalent basis, total oil and natural gas production decreased
22% in 1996 when compared to 1995
Prices. Natural gas prices increased in 1996 to $2.75 per Mcf compared
to $1.58 in 1995. The Company entered into a natural gas swap agreement
beginning January 1, 1996 for the sale of 15,000 MMbtu of natural gas each day
in 1996, with contract prices ranging from $1.75 per MMbtu to $2.25 per MMbtu. A
swap loss for the year ended December 31, 1996 of $3,900,000, decreased the net
price received by the Company to $2.17 per Mcf for the year. Oil prices also
increased, from $ $16.78 per Bbl in 1995 to $19.42 per Bbl in 1996.
"Oil and natural gas sales" increased 8% for 1996 when compared with
1995, in spite of the fire at West Delta. The fire substantially reduced oil and
natural gas production for 1996, as production from the West Delta Fields was
shut-in from April 24, 1996 until October 7, 1996. However, the decrease in
production from West Delta was offset by production from properties acquired.
The Amoco properties, acquired on October 8, 1996, and the Bayou Sorrel Field,
acquired on December 28, 1995 had no production realized by the Company in 1995.
The offshore properties of Zapata Exploration Company were acquired on July 26,
1995 with the production from these properties being included in the Company's
results of operations from July 27 through December 31, 1995.
"Depletion, depreciation and amortization expense" increased 12% in
1996 despite the reduced production from the West Delta Fields. While the
production from properties acquired accounted for a part of the 12% increase,
depletion, depreciation and amortization per Mcf equivalent also increased, from
$0.74 in 1995 to $1.07 in 1996, due to year-end 1996 engineering revisions on
the West Delta and East Breaks 109 Fields, and production from the Amoco
properties in the fourth quarter of 1996, which had higher depletion rates per
Mcf equivalent than previously owned properties.
<PAGE>
"Lease operating expense" increased $422,000 in 1996 primarily due to
the Amoco, Zapata and Bayou Sorrel Field acquisitions. With the Zapata
properties, the Company acquired interests in five offshore producing
properties. Since the acquisition of the Zapata Properties closed on July 26,
1995, only the lease operating expenses from July 27, to December 31, 1995 are
included in the 1995 results of operations, while the 1996 period includes these
expenses for the full year. Also 1996 includes eight months of lease operating
expenses for the Bayou Sorrel Field (sold September 1) and almost three months
(October 8 - December 31) of the Amoco properties, with none of these expenses
included in 1995. West Delta lease operating expenses did decrease in 1996
($805,000 from expected levels) with the fields being shut-in from April 25
through October 7, however, a part of these lease operating expenses are fixed
in nature and continued.
"Production and ad valorem taxes" decreased to 2.8% of oil and natural
gas sales in 1996 from 5.8% of oil and natural gas sales in 1995.The decrease is
primarily due to the shift in the Company's production volumes from properties
subject to severance taxes to properties in federal offshore waters (the Amoco
and Zapata properties) that are not subject to such taxes. A part of the
decrease ($178,000 from expected levels) is also due to the lost production from
the West Delta Fields due to the fire. A large percentage of this production is
in Louisiana State waters, which are subject to severance taxes.
"Exploratory dry hole expense" in 1995 consisted of costs of $796,000
on Eugene Island Block 50, $1,378,000 on South Timbalier Block 33, and
$5,938,000 on West Delta Block 54.
"Provision for losses on disposition and write-downs of assets" in 1995
relates to the write-down of a group of onshore properties acquired in the early
1980's.
"West Delta fire loss" is the expense of the fire at Tank Battery #3,
the central processing facility for the West Delta Fields. Included in this
expense are the insurance deductibles and the cost of non-reimbursed
expenditures, which were not capitalized.
"Interest expense (net)" increased $1,500,000, or 155% in 1996 when
compared to 1995. Average Long-Term Debt levels increased from $11,000,000 in
1995 to $28,000,000 for 1996, as a result of debt incurred in connection with
acquisitions.
"Gain (loss) on investment in common stock" in 1996 was a result of an
unrealized decrease in the market value at December 31, 1996 of 477,612 shares
of National Energy Group, Inc. common stock received in connection with the sale
of the Bayou Sorrel Field.
"Net operating income (loss)" increased significantly in 1996 in relation
to the $8,100,000 exploration expenses and the $751,000 onshore property
write-down in 1995.
Sale of Bayou Sorrel Field
Effective September 1, 1996, the Company sold its Bayou Sorrel Field to
National Energy Group, Inc. for $9,000,000 in cash and 477,612 shares of
National Energy Group, Inc. common stock. The Company also retained an
overriding royalty interest in the deep rights of the field for depths below
11,000'. The field was acquired by the Company from Shell Western E.P., Inc. for
$10,500,000 on December 28, 1995. During the eight months the Company owned the
field two wells were drilled which did not result in production in commercial
quantities. After having made the Amoco acquisition, management believed that
the Company's resources could be better utilized elsewhere.
<PAGE>
Item 7a. Qualitative and Quantitative Disclosure About Market Risks.
The Company follows a conservative hedging strategy designed to protect
against the possibility of severe price declines due to unusual market
conditions. Decisions are usually made so as to assure a payout of a specific
acquisition or development project or to take advantage of unusual strength in
the market.
The Company enters into commodity hedge agreements to reduce its exposure
to price risk for oil and natural gas. Pursuant to these hedge agreements,
either the Company or the counterparty is required to make payment to the other
each month. The natural gas hedge agreement in 1997 provided a minimum price of
$1.80 on 14,000 MMBtu per day of natural gas, with participations varying
between 40% and 93% above $1.80. A loss of $1,203,000 was incurred on this hedge
in 1997.
The oil hedge agreement in 1997 provided the Company with a minimum of $20.00 on
720 Bbls of oil per day, based upon the arithmetic average of the daily
settlement prices for the New York Mercantile Exchange (NYMEX) with a
participation of 40% above $20.00. A loss of $67,000 was incurred on this hedge
in 1997.
The Company currently has hedge agreements involving the following provisions
for the periods shown:
<TABLE>
<CAPTION>
OIL
==========================================================================================================
Average
Notional quantity Fixed Price Market Company participation
Per day (Bbl) Price above fixed
Period (Bbls) price
<S> <C> <C> <C> <C>
1998 500 $19.80 NYMEX 0%
1998 500 $19.28 NYMEX 40%
1998 268 $17.28 NYMEX 0%
1999 223 $17.27 NYMEX 0%
2000 232 $17.35 NYMEX 0%
NATURAL GAS
==========================================================================================================
Notional quantity Average Fixed Market Company participation
Per day (MMBtu) Price (MMBtu) Price above fixed
Period price
1998 10,000 $ 1.89 Pipeline Prices 0%
1998 (February to 10,000 $ 2.10 Pipeline Prices 0%
September)
1998 (February to 10,000 $ 2.04 Pipeline Prices 50%
September)
1998 (April to 20,000 $ 2.22 Pipeline Prices 0%
September)
1999 7,356 $ 1.89 Pipeline Prices 0%
2000 218 $ 1.87 Pipeline Prices 0%
</TABLE>
These hedge agreements provide for the counterparty to make payments to the
Company to the extent the market prices (as determined in accordance with the
agreement) are less than the fixed prices for the notional amount hedged, and
the Company to make payments to the counterparty to the extent market prices are
greater than the fixed prices. For oil "market prices and fixed prices" are
referenced to NYMEX. However, for natural gas, "market prices" and "fixed
prices" are referenced to published pipeline index prices, which are also the
prices at which the Company sells its natural gas on the spot market. The
Company accounts for the gains and losses in oil and natural gas revenue in the
month of hedged production. The annual notional quantity of oil and natural gas
under the hedge agreements in 1998 is equal to approximately 68% and 61%,
respectively, of its anticipated 1998 production based upon the year end reserve
reports. At December 31, 1997, the estimated fair market value of the hedge
agreements was a loss of $61,000.
<PAGE>
Item 8. Financial Statement and Supplementary Data.
The financial statements are included herein beginning at page F-1. The
table of contents at the front of the financial statements lists the financial
statements and schedules included therein.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
Item 10. Directors and Executive Officers of the Registrant.
The Company has a classified Board of Directors, consisting of four
Class I directors, three Class II directors, and four Class III directors. The
directors are elected to serve for three-year terms and until their successors
are elected and qualified. The directors stand for election each year as their
terms expire by class. The Board of Directors consists of three employees of the
Company and eight independent directors.
Officers are elected by and serve at the discretion of the Board of
Directors.
Set forth below are the names, ages, and positions of the persons who
are executive officers and directors of the Company, and the committees of the
Board on which they serve.
<TABLE>
<CAPTION>
Director
Name Age Since Position
<S> <C> <C>
H. James Maxwell 53 1992 Chairman of the Board, Chief Executive Officer, and Director(a)
Larry M. Wright 53 1992 President, Chief Operating Officer and Director (b)
Robert Wonish 44 --- Sr. Vice President-Operations
Edward A. Bush, Jr. 54 --- Sr. Vice President-Geology/Geophysics
William J. Doyle 46 --- Vice President-Exploitation
Barbara A. Whitton 35 --- Vice President-Marketing/Planning
Todd R. Bart 33 1997 Chief Financial Officer, Secretary and Director(a)
Larry W. Miller 48 --- Treasurer
A. Theodore Stautberg, Jr. 51 1993 Director(c)-Compensation Committee
Donald W. Chesser 58 1992 Director(a)-Audit Committee
Leonard C. Tallerine, Jr. 47 1997 Director(c)
Mark C. Licata 47 1997 Director (a)
James B. Kreamer 58 1993 Director(c)-Compensation Committee
Mark C. Barrett 47 1996 Director(b)-Audit and Compensation Committees
Michael Springs 47 1996 Director(c)
Harold First 61 1997 Director(b)-Audit and Compensation Committee
- --------------------------------
</TABLE>
(a) These persons are designated as Class III directors, with their term of
office expiring at the annual meeting of shareholders in 1998.
(b) These persons are designated as Class II directors, with their term of
office expiring at the annual meeting of shareholders in 2000.
(c) These persons are designated as Class I directors, with their term of
office expiring at the annual meeting of shareholders in 1999.
<PAGE>
Set forth below are descriptions of the principal occupations, during at
least the past five years, of the directors and executive officers of the
Company.
H. James Maxwell received a B.A. degree in Economics from the University
of Missouri-Kansas City and received his Law Degree from that same university in
1972. Mr. Maxwell practiced securities law from 1972 to 1984, and was a frequent
author and speaker on oil and natural gas tax and securities law. He served as a
General Partner of Castle Royalty Limited Partnership from 1984 to 1988,
Managing General Partner of PAN Petroleum MLP from 1987 to 1992, both of which
were predecessors of the Company, President of the Company from 1992 to 1997 and
Chief Executive Officer and Chairman of the Board of the Company from 1992 to
date.
Larry M. Wright received his B.S. Degree in Chemical Engineering from the
University of Oklahoma in 1966. From 1966 to 1976 he was with Union Oil Company
of California (UNOCAL). From 1976 to 1980, he was with Texas International
Petroleum Corporation, ultimately as division operations manager. From 1980 to
1981, he was with what is now Transamerica Natural Gas Company as Vice
President-Exploration and Production. From 1981-1982, he was Senior Vice
President of Operations for Texas International Petroleum Corporation, and, from
1983 to 1985, he was Executive Vice President of Funk Fuels Corp., a subsidiary
of Funk Exploration. From 1985 to 1993, Mr. Wright was an independent consultant
to the Company and its predecessors. From 1993 to 1997, he served as Executive
Vice President of the Company and since October 1997, has served as President
and Chief Operating Officer.
Robert G. Wonish received his B.S. in Mechanical Engineering in 1975 from
the University of Missouri-Rolla. He was a production engineer with Amoco from
1975 to 1977, Napeco, Inc. from 1977 to 1979; Division Operation Engineer with
Texas International from 1979 to 1980; Production Manager with Cliffs Drilling
Company from 1980 to 1984 and District Superintendent with Ladd Petroleum
Corporation from 1985 to 1991. He then worked as a consultant, starting with the
Company in 1992, and became an employee in 1993, serving as Senior Vice
President - Operations.
Edward A. Bush, Jr., received his B.S. Degree in Geology from Baldwin
Wallace College in 1964 and his M.A. in Geology from Bowling Green State
University in 1966. He served in various geological and exploration capacities
with Exxon (1968-75), Union Texas Petroleum (1975-79), Home Petroleum Corp.
(1979-81), Traverse Oil Co. (1981-83) and Sohio Petroleum Co. (1983-85). From
1985 to 1995 he served first as Exploration Manager, then Vice President of
Exploration and later Vice President of Operations for Columbia Gas Dev. Corp.
From 1995 to 1996 he served as Vice President-Exploration and President of
Howell Petroleum Corp. He presently serves with the Company as Senior Vice
President-Geology/Geophysics.
William J. Doyle received his Masters in Geology in 1975 from Texas A&M
University and his B.S. in Earth Sciences from the University of New Orleans in
1973. From 1975 to 1978 he was a geologist with Mobil Oil focusing on offshore
Gulf of Mexico projects. From 1978 to the present he has worked as an employee
and consultant for various oil and natural gas exploration companies operating
in the Gulf Coast. He joined the Company as a consulting geologist in 1992 and
became a Vice President in 1995.
Barbara A. Whitton joined Goldking in 1993 as the Manager of Revenue
Accounting and was appointed Vice President-Marketing/Planning in 1997. Prior to
Goldking, Ms. Whitton had experience in accounting, finance and marketing with
Hall-Houston Oil Company (1991-1993), UMC Petroleum Corporation (1987-1989),
Energy Assets International (1984-1987) and Sohio Petroleum (1982-1984). She was
made Vice-President-Marketing/Planning following the acquisition of Goldking.
Todd R. Bart received his B.B.A. in Accounting from Abilene Christian
University in 1987. He worked in the energy industry with Pennzoil Company from
1987 to 1990 and the public accounting firm of Arthur Andersen and Company from
1990 until 1992. From 1992 to 1995 he worked for Yellow Freight System, Inc., a
trucking company, in financial accounting and reporting. He joined the Company
as Controller in 1995 and was elected Chief Financial Officer and Secretary in
1996. He received his C.P.A. designation in Texas in 1990 and in Kansas in 1993,
and is a member of the A.I.C.P.A.
<PAGE>
Larry W. Miller received his B.S. Degree in Business
Administration/Accounting from Central Missouri State University in 1971. He
received his MBA Degree from Rockhurst College in Kansas City in 1982. From 1971
to 1975 he worked for Seaboard Allied Milling Corp., a grain company, as Manager
of the grain accounting department. From 1975 to 1998 he worked for Petroleum
Production Management Inc., a privately owned independent oil & gas operator, in
various accounting positions ultimately as Vice President and Chief Financial
Officer. He joined the Company in 1998 and was elected Treasurer in 1998. He
received his C.P.A. designation in Missouri in 1987 and is currently a member of
the A.I.C. P. A.
A. Theodore Stautberg, Jr. has since 1981 been the President and a director
of Triumph Resources Corporation and its parent company, Triumph Oil and Gas
Corporation of New York. Triumph engages in the oil and natural gas business,
assists others in financing energy transactions, and serves as general partner
of Triumph Production L.P. Mr. Stautberg is also the president of Triumph
Securities Corporation and BT Energy Corporation. Prior to forming Triumph in
1981, Mr. Stautberg was a Vice President of Butcher & Singer, Inc., an
investment-banking firm, from 1977 to 1981. From 1972 to 1977, Mr. Stautberg was
an attorney with the Securities and Exchange Commission. Mr. Stautberg is a
graduate of the University of Texas and the University of Texas School of Law.
Donald W. Chesser received his B.B.A. in Accounting from Texas Tech
University in 1963 and has served with several certified public accounting firms
since that time, including eight years with Elmer Fox and Company. From 1977 to
1981, he was with IMCO Enterprises, Inc. Since 1982 he has been a shareholder
and President of Chesser & Company, P.A., a certified public accounting firm. He
is also President of Financial Advisors, Inc., a registered investment advisor.
Leonard C. Tallerine, Jr., graduated from Rice University's Advanced
Management Institute and holds undergraduate and graduate degrees in accounting
from the University of Houston. Mr. Tallerine practiced as a CPA with Price
Waterhouse and KPMG from 1972 through 1980, specializing in oil and natural gas
tax issues. From 1981 through 1986, he served as co-managing and general partner
of Paso Grande Investment, Ltd., an oil and natural gas real estate holding
company and served as Chairman of the Texas Guarantee National Bank from 1983 to
1986. In 1987, he founded the Union Companies and in 1991 became Chairman and
Chief Executive Officer of Goldking. In July 1997 Mr. Tallerine was appointed a
Director, following the Company's acquisition of Goldking.
Mark C. Licata received a Bachelor of Business Administration and
Accounting (1972) and a law degree (1976) from the University of Texas. He was
employed in the private practice of law from 1976 through 1985 and then served
as President and Chief Operating Officer of Vista Host, Inc. and later as
President and Chief Operating Officer of the publicly held McFaddin Ventures,
Inc. In 1988, Mr. Licata returned to the practice of law in Houston with Looper,
Reed, Mark & McGraw, where he remained until he joined Goldking as President in
1996. In July 1997 Mr. Licata was appointed a Director, following the Company's
acquisition of Goldking.
James B. Kreamer received his B.S. Degree in Business from the University
of Kansas in 1963 and has been active in investment banking since that time.
Since 1982 he has managed his personal investments.
Mark C. Barrett received his B.S. Degree in Business
Administration/Accounting in 1972 and is licensed to practice as a Certified
Public Accountant in both Kansas and Missouri. He was a partner in the firm
Drees Dunn Lubow and Company from 1974 until 1981. He founded Barrett &
Associates, a certified public accounting firm, in 1981 and is the president and
majority shareholder in that firm. His firm served as the Company's independent
public accountants from 1985 to 1995.
Michael Springs graduated from the Medical Field Service School, Brooke
Hospital, San Antonio, Texas in 1971 and the University of Missouri, Kansas
City, in 1969 with a degree in Business. He is the President and founder of
Ortho-Care, Inc. of Kansas City, Missouri and Ortho-Care Southeast of Charlotte,
North Carolina. Ortho-Care, Inc. is a manufacturer of orthopedic fracture
management and sports medicine products, and holds a number of patents in the
field. Mr. Springs is also controlling partner in Ortho-Implants, a distributor
of total joint replacement prosthesis.
Harold First has been self-employed as a financial consultant since 1993.
From 1990 to 1993 he was Chief Financial Officer of Icahn Holding Corp. and also
served as Senior Vice President of Trans World Airlines, Inc. from 1992 to 1993.
Mr. First is currently a director of Marvel Entertainment Group, Inc., Toy Biz,
Inc., Cadus Pharmaceutical Corp. and Tele-Save Holdings, Inc. He was nominated
for election to the Board of Directors pursuant to an agreement with shareholder
Carl C. Icahn.
None of the officers or directors serve pursuant to employment agreements.
<PAGE>
The Board of Directors
The Board of Directors has the responsibility for establishing broad
corporate policies and for the overall performance and governance of the
Company, although it is not involved in day-to-day operating details. Directors
are kept informed of the Company's business by various reports and documents, as
well as by operating and financial reports presented at Board and committee
meetings by the Chairman and other officers.
Meetings of the Board of Directors are regularly held each quarter and
following the annual meeting of the shareholders. Additional meetings, including
meetings by telephone conference call, of the Board may be called whenever
needed. The Board of Directors of the Company held eleven meetings in 1997, six
of which were meetings by telephone conference call.
Committees of the Board
The committees established by the Board of Directors to assist it in
the discharge of its responsibilities are described below. The previous table
identifies the committee memberships currently held.
The Audit Committee has three members, none of whom is an employee of
the Company. The Committee meets with management to consider the adequacy of the
internal controls of the Company and the objectivity of its financial reporting;
the Committee also meets with the independent accountants concerning these
matters. The Committee recommends to the Board the appointment of the
independent accountants, subject to ratification by the shareholders at the
annual meeting. The independent accountants periodically meet alone with the
Committee and have unrestricted access to the Committee. The Committee met once
in 1997.
The Compensation Committee has three members, none of whom is an
employee of the Company. It makes recommendations to the Board with respect to
the compensation of Senior management of the Company and the Company's Long-Term
Incentive Plan. The Committee met once in 1997.
Beneficial Ownership Reporting Compliance
Based solely upon a review of copies of Forms 3 and 4 and amendments
thereto furnished to the Company during the fiscal year ended December 31, 1997
and Forms 5 and amendments thereto with respect to such year and certain written
representations that no Form 5 is required, the Company is not aware of any
failure on the part of any person subject to Section 16 of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), with respect to the
Company during fiscal 1996 to file on a timely basis any form or report required
by Section 16(a) of the Exchange Act during such fiscal year or prior fiscal
years.
Item 11. Executive Compensation.
Summary Compensation Table. The following table sets forth certain information
concerning the annual compensation paid to the Company's Chief Executive Officer
and each executive officer whose compensation exceeded $100,000 during 1997.
<TABLE>
<CAPTION>
Long-Term Incentive Plan
-------------------------------------------
Annual Compensation Awards Payouts
------------------------------------
Restricted Securities All
Stock Underlying LTIP Other
Position Year Salary ($) Bonus ($) Award(s)($) Options (#) Payouts($) Comp.($)
- ---------------------- ----- ------------ ------------ ------------ -------------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
H. James Maxwell 1997 215,100 21,400 0 600,000 0 22,500
Chairman and Chief 1996 166,900 0 0 0 0 22,500
Executive Officer 1995 153,500 0 0 24,615 0 22,500
Larry M. Wright 1997 205,500 20,500 0 400,000 0 22,500
President 1996 160,300 0 0 0 0 22,500
1995 147,300 0 0 0 0 22,100
Edward A. Bush(b) 1997 121,523 0 0 20,000 0 18,200
Senior Vice President 1996 9,231 0 0 0 0 0
Robert G. Wonish 1997 117,100 12,800 20,000 40,000 0 19,500
Senior Vice President 1996 100,200 0 0 0 0 15,000
1995 92,100 0 0 0 0 13,800
- ----------
(a) The "other compensation" represents contributions to the accounts of the
employees under the Company's Employee Stock Ownership Plan.
(b) Mr. Bush joined the Company in December 1996.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Option Grants in Last Fiscal Year
Number of Percent of
Securities total options
Underlying granted to Exercise or Market price Per Share
Options employees Base price at date Expiration Grant Date
Name Granted in fiscal year ($/Share) of grant($) Date Value($)(a)
- ------------------ ---------- -------------- ----------- ------------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
H. James Maxwell 600,000 50% $4.45 $4.38 6/20/00 $1.42
Larry M. Wright 400,000 33% $4.45 $4.38 6/20/00 $1.42
Edward A. Bush 20,000 2% $4.45 $4.38 6/20/00 $1.42
Robert G. Wonish 40,000 3% $4.45 $4.38 6/20/00 $1.42
</TABLE>
- ------
(a) The per share grant date value was calculated on the date of the grant
using the Black-Scholes Modified American Option Pricing Model. This model
uses historical data to forecast future trends and economic research has
shown that it may not be indicative of future results. The following
assumptions were used in the model for calculating the value: expected
volatility-38.4%, risk free rate of return-6.1%, dividend yield-0%, term to
exercise-date of expiration (3 years).
Aggregate Option and Warrant Exercises. The following table provides information
relating to the number and value of Common Shares subject to options exercised
during 1997 or held by the named executive officers as of December 31, 1997.
Aggregated Warrant and Option Exercises in Last Fiscal Year and Fiscal Year
End Option Values
<TABLE>
<CAPTION>
Number of
Securities underlying Value of unexercised
Shares Unexercised options In-the-money
Acquired Value At fiscal yearend (#) At fiscal year-end ($)
Name On Exercise(#) Realized($)(a) Exercisable/Unexercisable Exercisable/Unexercisable
- ------------------ --------------- --------------- --------------------------- ---------------------------
<S> <C> <C> <C> <C> <C>
H. James Maxwell 0 0 600,000/0 0/0
Larry M. Wright 250,000 568,000 400,000/0 0/0
Edward A. Bush 0 0 20,000/0 0/0
Robert G. Wonish 0 0 40,000/0 0/0
</TABLE>
(a) Value realized is calculated based upon the difference between the
options exercise price and the market price of the Common Shares on the
date of exercise multiplied by the number of shares to which the
exercise price relates.
Objectives and Approach. The overall goals of the Company's executive
compensation program are: (i) to encourage and provide an incentive to its
executive officers to achieve the Company's strategic business and financial
goals, both short-term and long-term, and thereby enhance shareholder value,
(ii) to attract and retain well-qualified executive officers and (iii) to reward
individuals for outstanding job performance in a fair and equitable manner when
measured not only with respect to the Company's internal performance goals but
also the Company's performance in comparison to its peers. The components of the
Company's executive compensation are salary, incentive bonuses and awards under
its Long Term Incentive Plan and Employee Stock Ownership Plan, each of which
assists in achieving the program's goals.
Long Term Incentive Plan. The Company's Long-Term Incentive Plan provides for
the granting, to certain officers and key employees of the Company and its
participating subsidiaries, of incentive awards in the form of stock options,
stock appreciation rights ("SARs"), stock, and cash awards. The Long-Term
Incentive Plan is administered by a committee of independent members of the
Board of Directors (the "Plan Committee") with respect to awards to certain
executive officers of the Company but may be administered by the Board of
Directors with respect to any other awards. Except for certain automatic awards,
the Plan Committee has discretion to select the employees to be granted awards,
to determine the type, size, and terms of the awards, to determine when awards
will be granted, and to prescribe the form of the instruments evidencing awards.
<PAGE>
Options, which include nonqualified stock options and incentive stock
options, are rights to purchase a specified number of Common Shares at a price
fixed at the time the option is granted. Payment may be made with cash or other
Common Shares owned by the optionee or a combination of both. Options are
exercisable at the time and on the terms that the Plan Committee determines. The
payment of the option price can be made either in cash or by the person
exercising the option turning in to the Company, Common Shares presently owned
by him, which would be valued at the then current market price. SARs are rights
to receive a payment, in cash or Common Shares or both, based on the value of
the Common Shares. A stock award is an award of Common Shares or denominated in
Common Shares. Cash awards are generally based on the extent to which
pre-established performance goals are achieved over a pre-established period but
may also include individual bonuses paid for previous, exemplary performance.
The Plan Committee determines performance objectives and award levels before the
beginning of each plan year.
The Long-Term Incentive Plan allows for the satisfaction of a
participant's tax withholding with respect to an award by the withholding of
Common Shares issuable pursuant to the award or the delivery by the participant
of previously owned Common Shares, in either case valued at the fair market
value, subject to limitations the Plan Committee may adopt.
Awards granted pursuant to the Long-Term Incentive Plan may provide
that, upon a change of control of the Company, (a) each holder of an option will
be granted a corresponding SAR (b) all outstanding SARs and stock options become
immediately and fully vested and exercisable in full, and (c) the restriction
period on any restricted stock award shall be accelerated and the restriction
shall expire.
The Long-Term Incentive Plan provides for the issuance of a maximum
number of Common Shares equal to 20% of the total number of Common Shares
outstanding from time to time. Unexercised SARs, unexercised options, restricted
stock, and performance units under the Long-Term Incentive Plan are subject to
adjustment in the event of a stock dividend, stock split, recapitalization or
combination of the Company, merger or similar transaction and are not
transferable except by will and by the laws of descent and distribution. Except
when a participant's employment terminates as a result of death, disability, or
retirement under an approved retirement plan or following a change in control in
certain circumstances, an award generally may be exercised (or the restriction
thereon may lapse) only if the participant is an officer, employee, or director
of the Company, or subsidiary at the time of exercise or lapse or, in certain
circumstance, if the exercise or lapse occurs within 180 days after employment
is terminated.
Under the Company's Long-Term Incentive Plan all full time employees
share a bonus equal to 1% of the Company's cash flow, in accordance with GAAP,
exclusive of extraordinary and non-recurring items. The bonuses are paid to all
full time (1,000+ hours) employees at the time of delivery of the independent
audit. The bonuses are allocated to the full time employees based upon their
salary at December 31. Former Goldking employees received proportionate
participation for 1997, based upon their five months employment with the
Company.
The Long-Term Incentive Plan may be amended by the Board of Directors.
No grants or awards may be made under the Long-Term Incentive Plan after the
tenth anniversary of the plan. No shareholder approval will be sought for
amendments to the Long-Term Incentive Plan except as required by law (including
Rule 16b-3 under the Exchange Act) or the rules of any national securities
exchange on which the Common Shares are then listed.
Each non-employee director of the Company who becomes a director will,
on the day after the first meeting of the Board of Directors at which that
director is in attendance, automatically be granted a restricted stock award of
the number of Common Shares that have a value of $10,000, which will be
calculated based on the average trading price of the Common Shares during the 60
days immediately preceding the date of grant. These restricted stock awards will
vest over two years, with one-third vesting six months following the date of
grant, another one-third vesting on the first anniversary of the date of grant,
and the last one-third vesting on the second anniversary of the date of grant so
long as the non-employee director remains a director of the Company through
those vesting dates.
Each non-employee director will be entitled to vote each share subject
to these restricted stock awards from the date of grant until the shares are
forfeited, if ever. The Long-Term Incentive Plan requires each non-employee
director to make an election under Section 83(b) of the Code to include the
value of the restricted stock in his income in the year of grant and provides
for cash awards to the non-employee directors in amounts sufficient to pay the
federal income taxes due with respect to the award.
<PAGE>
Employee Stock Ownership Plan. In 1994, the Company adopted the PANACO, Inc.
Employee Stock Ownership Plan ("ESOP"). Pursuant to the terms of the ESOP, the
Company may contribute up to fifteen percent (15%) of the participant's annual
compensation to the ESOP. ESOP assets are allocated in accordance with a formula
based on participant compensation. In order to participate in the ESOP, a
participant must complete at least one thousand hours of service to the Company
within twelve consecutive months. Former Goldking employees will receive
proportionate participation for 1997, based upon their five months employment
with the Company. A participant's interest in the ESOP becomes one hundred
percent vested after three years of service to the Company. Benefits are
distributed from the ESOP at such time as a participant retires, dies or
terminates service with the Company in accordance with the terms and conditions
of the ESOP. Benefits may be distributed in cash or in shares of the Company's
common stock. No participant contributions are allowed to be made to the ESOP.
Company contributions to the ESOP may be in the form of Common Shares
or cash. Cash contributions may be used, at the discretion of the Board of
Directors, to purchase Common Shares in the open market or from the Company at
prevailing prices. The allocation of ESOP assets is determined by a formula
based on participant compensation. Participation in the ESOP requires completion
of more than one thousand (1,000) hours of service to the Company. The ESOP is
intended to satisfy any applicable requirements of the Internal Revenue Code of
1986 and the Employee Retirement and Income Security Act of 1974. The Company
has been advised that its contributions to the ESOP will be deductible for
Federal Income Tax purposes, and the participants will not recognize income on
their allocated share of ESOP assets until such assets are distributed. As of
December 31, 1997, the ESOP owned of record 77,618 Common Shares. Such Common
Shares are owned beneficially by the employees of the Company.
Compensation of Directors
In order to align the interests of the Company's shareholders and its
directors, directors do not receive cash compensation. Non-employee directors
are compensated for their services with shares of the Company's common stock,
receiving $1,000 in Common Shares for attending Board of Directors meetings,
$500 in Common Shares for attending committee meetings and $200 in Common Shares
for participating in telephone meetings. Officers of the Company who serve as
directors do not receive additional compensation for serving on the Board of
Directors or a committee thereof. Directors are reimbursed for travel expenses
incurred in attending Board of Directors or committee meetings.
The following table shows information with respect to restricted stock
awards owned by non-employee directors.
Name Date of Grant Shares Price
- ---------------- ------------------ -------- -------
Michael Springs September 4, 1996 2,447 $4.09
Mark C. Barrett September 4, 1996 2,447 4.09
Harold First October 8, 1997 2,315 4.32
Total 7,209
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth information with respect to beneficial
ownership of the Company's Common Stock by (a) each officer and director of the
Company, (b) all officers and directors of the Company as a group, and (c) for
each person who beneficially owns 5% or more of the Common Stock as of March 24,
1998. Except as set forth in footnote (c) below, each shareholder has sole
voting and sole investment power over all shares.
<TABLE>
<CAPTION>
Shares Owned Beneficially(a)
Directors and Executive Officers Number Percent
- ------------------------------------------------------------------------------ ---------- ---------
<S> <C> <C>
H. James Maxwell; Chief Executive Officer and Chairman of the Board......... 897,586 3.75%
Larry M. Wright; President, Chief Operating Officer and Director............ 1,061,614 4.44
Robert G. Wonish; Sr. Vice President-Operations............................. 66,410 .28
Edward A. Bush, Jr.; Sr. Vice President-Geology/Geophysics.................. 21,000 .09
William J. Doyle; Vice President-Exploitation............................... 16,288 .07
Todd R. Bart; Chief Financial Officer , Secretary and Director.............. 33,997 .14
Larry W. Miller, Treasurer.................................................. -- --
A. Theodore Stautberg, Jr.; Director........................................ 17,447 .07
Donald W. Chesser; Director................................................. 2,235 .01
Leonard C. Tallerine, Jr.; Director......................................... 1,548,784 6.48
Mark C. Licata; Director.................................................... 1,606,146 6.70
James B. Kreamer; Director.................................................. 52,251 .22
Michael Springs; Director................................................... 4,292 .02
Mark C. Barrett; Director................................................... 3,824 .02
Harold First; Director...................................................... 2,791 .01
All Directors and Officers as a group (15 persons).......................... 5,334,665 22.30%
</TABLE>
<TABLE>
<CAPTION>
Shares Owned Beneficially
Beneficial Owners of 5% or more (excluding persons named above) Number Percent
- ------------------------------------------------------------------------------ ----------- ------------
<S> <C> <C>
Carl C. Icahn (b)........................................................... 3,030,000 12.67%
% Icahn Associates Corp.
767 Fifth Avenue, 47th Floor
New York, NY 10153
R. B. Haave Associates, Inc. ............................................... 1,887,600 7.89
36 Grove Street
New Canaan, CT 06840
Richard A. Kayne (c)........................................................ 1,757,576 7.35
% Kayne Anderson Investment Management, Inc.
1800 Avenue of the Stars, #200
Los Angeles, CA 90067
Croft-Leominster, Inc....................................................... 1,617,000 6.76
207 East Redwood Street, Suite 802
Baltimore, Maryland 21202
</TABLE>
- --------------
(a) Includes 1,100,000 currently exercisable options to purchase shares,
at $4.45 per share, held by the following: Mr. Maxwell-600,000; Mr.
Wright-400,000; Mr. Wonish-40,000; Mr. Bush-20,000; Mr. Doyle-10,000
and Mr. Bart-30,000. These options are exercisable any time before
June 20, 2000. However, the holder may not dispose of the shares
acquired upon exercise for a period of three years and must remain an
employee of PANACO during that three-year period. Otherwise, the
shares may be reacquired by PANACO at the person's cost, thereby
denying them the benefit of the option.
(b) Mr. Icahn is the sole stockholder of Riverdale Investors Corp. Inc.,
the general partner of High River Limited Partnership, the record
holder of these shares.
(c) The reported shares are owned by seven investment accounts (including
four investment limited partnerships, two insurance companies and an
offshore corporation), managed, with discretion to purchase or sell
securities, by KAIM Non-Traditional, L.P., a registered investment
adviser. The four investment limited partnerships beneficially own
1,466,667 shares that are issuable upon the exercise of warrants which
expire on December 31, 1998. KAIM Non-Traditional, L.P. is the sole or
managing general partner of three of the limited partnerships and a
co-general partner of the fourth. Richard A. Kayne is the controlling
shareholder of the corporate owner of Kayne, Anderson Investment
Management, Inc., the sole general partner of KAIM Non-Traditional,
L.P. Mr. Kayne is also the managing general partner of one of the
limited partnerships and a limited partner of each of the limited
partnerships. KAIM Non-Traditional, L.P. is an investment manager of
the offshore corporation. Mr. Kayne is a director of one of the
insurance companies. All shares have shared voting and investment
power.
KAIM Non-Traditional, L.P. disclaims beneficial ownership of the shares
reported, except for those shares attributable to it by virtue of its general
partner interests in the limited partnerships. Mr. Kayne disclaims beneficial
ownership of the shares reported, except those shares held by him or
attributable to him by virtue of his limited and general partner interests in
the limited partnerships and by virtue of his indirect interest in the interest
of KAIM Non-Traditional, L.P. in the limited partnerships.
<PAGE>
Item 13. Certain Relationships and Related Transactions.
A. Theodore Stautberg, Jr., is an officer, director and beneficial
shareholder of Triumph Securities Corporation ("Triumph Securities"), which
provided certain services in connection with the 1996 offering of Common Shares.
In connection with the services so provided, Triumph Securities received
$268,906, representing .8% of the 6.8% underwriters discount.
Mark C. Barrett's CPA firm, Barrett and Associates, served as the
Company's independent accountants for the years 1985 through 1995. During 1996
his CPA firm was paid $53,400 for accounting services related to the audit of
the fiscal year 1995. Mr. Barrett's firm has provided advice on tax matters
during 1997.
H. James Maxwell and Bob F. Mallory are the partners in 1050 Blue Ridge
Building Partnership, which owns a 5,200 square foot office building at 1050
West Blue Ridge Boulevard, Kansas City, Missouri, which it leases to the Company
on a triple net basis for $4,000 per month for a term of ten years, expiring in
2003. Mr. Mallory recently resigned from his positions as Executive Vice
President and Director of the Company. The lease was approved by the Board of
Directors, which determined that the rate was as good or better than that which
could be obtained from a non-affiliated party.
Larry M. Wright exercised warrants to purchase 90,000 Common Shares in
July 1997, at an exercise price of $2.00 per share and 160,000 common shares in
October 1997 at an exercise price of $2.375 per share, for an aggregate of
$560,000. The warrants were originally granted to Mr. Wright in 1991.
Michael Springs and Mark C. Barrett, were each issued restricted stock
awards of 2,447 Common Shares upon their election to the Board of Directors in
1996. Harold First was likewise issued 2,315 Common Shares upon his election to
the Board of Directors in October 1997.
In connection with the Goldking Acquisition, Mark C. Licata and Leonard C.
Tallerine, Jr. were paid a total of $27,539,000, including 1,606,146 and
1,548,784 restricted Common Shares respectively, issued at the closing on July
31, 1997. Messrs. Licata and Tallerine have certain rights to require the
Company to register such Common Shares for resale. Messrs. Licata and Tallerine
were the sole beneficial owners of Goldking. See "Business - Goldking
Acquisition." After the Senior Note offering, $6,000,000 in promissory notes,
received by Messrs. Licata and Tallerine as a portion of the acquisition
consideration, were paid by the Company.
On October 8, 1996 the Company borrowed $17,000,000 from lenders
advised by Kayne, Anderson Investment Management, Inc. ("Kayne Anderson"). Of
this amount, $8,500,000 was repaid on March 6, 1997 from the proceeds of the
Company's public offering of common stock. The Company paid certain expenses,
including legal fees, of those lenders in 1996 and 1997. During the first
quarter of 1996, lenders advised by Kayne Anderson exercised warrants issued to
them in connection with the 1993 subordinated notes, and receiving 816,526
Common Shares. Those shares were sold during 1997. In October 1997, $8,500,000
in 1996 Tranche A Convertible Subordinated Notes due October 8, 2003,
convertible into 2,060,606 common shares on the basis of $4.125 per share, were
prepaid by the Company. Warrants to purchase 2,060,606 common shares at a price
of $4.125 per share, which may be exercised until December 31,1998, were issued
as part of the terms of the prepayment.
H. James Maxwell and former officer and Director Bob F. Mallory are
personal guarantors of the Company's obligation to plug the wells and remove the
platforms on the West Delta properties acquired from Conoco, Arco (now Vastar),
Texaco and Oxy in 1991.
Employees of the Company are eligible to receive stock awards, stock
options, stock appreciation rights, and performance units pursuant to the
Company's Long-Term Incentive Plan.
The Company has several procedures, provisions, and plans designed to
reduce the likelihood of a change in the management or voting control of the
Company without the consent of the incumbent Board of Directors. These
provisions may have the effect of strengthening the ability of officers and
directors of the Company to continue as officers and directors of the Company
despite changes in share ownership of the Company.
<PAGE>
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) See Index to Financial Statements, Page F-1.
(b) Reports on Form 8-K. The following reports on Form 8-K were filed during
the last quarter of the period covered by this report:
October 7, 1997 Amendment to Form 8-K on Acquisition of Properties
October 10, 1997 Amendment to Form 8-K on Acquisition of Properties
(c) Exhibits and Financial Statement Schedules.
Exhibit
Number Description
-------- -------------
3.1* Certificate of Incorporation of the Company.
3.2* Amendment to Certificate of Incorporation dated November 19, 1991.
3.3* By-laws of the Company.
3.4 Amendment to Certificate of Incorporation of the Company dated
September 24, 1996 filed as an exhibit to the Amended Current Report
on Form 8-K/A, filed with the Commission on November 18, 1996, and
incorporated herein by this reference.
4.1* Article Fifth of the Certificate of Incorporation of the Company in
Exhibit 3.1.
4.2* Form of Certificate of Common Shares par value $.01 per share, of the
Company.
4.3 Rights Agreement, dated as of August 3, 1995, between PANACO, Inc.,
and American Stock Transfer and Trust Company, which includes as
Exhibit A the Form of Certificate of Designation of Series A Preferred
Stock, Exhibit B the Form of Rights Certificate and Exhibit C the
Summary of Rights to Purchase Preferred Stock was filed as Exhibit 1
to the Registration Statement on Form 8-A, filed with the Commission
on August 21, 1995, and incorporated herein by this reference.
4.4*** Indenture dated October 9, 1997, among the Company and UMB Bank,
N.A., as trustee.
4.5*** Registration Rights Agreement, dated as of October 9, 1997, among
PANACO, Inc., and BT Alex Brown, First Union Capital Markets Corp,
A.G. Edwards & Sons Inc. and Gaines, Berland Inc.
4.6*** Form of 10 5/8 % Series B Senior Note due 2004
10.1* PANACO, Inc. Long-Term Incentive Plan.
10.13** PANACO, Inc. Employee Stock Ownership Plan & Trust.
10.13.1 Amendment to PANACO, Inc. Employee Stock Ownership Plan.
10.14Purchase and Sale Agreement, dated August 26, 1996, between Amoco
Production Company and PANACO, Inc., filed as an exhibit to the
Current Report on Form 8-K, filed with the Commission on October 28,
1996, and incorporated herein by this reference.
10.17Purchase and Sale Agreement, dated November 11, 1996 between National
Energy Group, Inc. and PANACO, Inc., filed as an exhibit to the
Current Report on Form 8-K filed with the Commission on January 29,
1997, and incorporated herein by this reference.
10.18Restated Merger Agreement dated July 30, 1997 between PANACO, Inc.,
The Union Companies, Inc., Leonard C. Tallerine, Jr. and Mark C.
Licata, filed with the Commission as an exhibit to the Current Report
on Form 8-K on August 15, 1997, and incorporated herein by this
reference.
<PAGE>
10.19Form of Executive Officer and Director Indemnification Agreement,
filed with the Commission as an exhibit to the Company's Form 10-Q on
August 15, 1997, and incorporated herein by this reference.
10.20***Form of Warrant to Purchase Shares of Common Stock of PANACO, Inc.
issued by the Company on October 9, 1997 to Offense Group Associates,
L.P., Kayne, Anderson Non-Traditional Investments, L.P., ARBCO
Associates, L.P., Opportunity Associates, L.P., Kayne, Anderson
Offshore Limited, Foremost Insurance Company, TOPA Insurance Company,
and EOS Partners, L.P., with respect to an aggregate of 2,060,606
shares.
10.21***Amended and Restated Credit Agreement, dated October 9, 1997, among
First Union National Bank of North Carolina, as agent, and the lenders
signatory thereto, and PANACO, Inc.
21.1 List of subsidiaries of PANACO, Inc.
27 Financial Data Schedule.
*Filed with the Registration Statement on Form S-4, Commission File No.
33-44486, initially filed December 13, 1991, and incorporated herein by this
reference.
** Filed with the Registration Statement on Form S-1, Commission file No.
333-18233, initially filed December 19, 1996 and incorporated herein by this
reference.
***Filed with the Registration Statement on Form S-4, Commission File No.
333-39919, initially filed November 10, 1997 and incorporated herein by this
reference.
(d) Financial Statement Schedules. See Index to Financial Statements, Page F-1.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PANACO, Inc.
By: \s\H. James Maxwell
H. James Maxwell, Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
By: \s\ H. James Maxwell
H. James Maxwell,
Chief Executive Officer and
Director
By: \s\Larry M. Wright
Larry M. Wright,
President and Director
By: \s\Michael Springs
Michael Springs, Director
By: \s\Todd R. Bart
Todd R. Bart, Chief Financial
Officer, Secretary and Director
By: \s\Mark C. Barrett
Mark C. Barrett, Director
By: \s\A. Theodore Stautberg
A. Theodore Stautberg, Director
<PAGE>
PANACO, Inc.
INDEX TO FINANCIAL STATEMENTS
PANACO, Inc. - AUDITED FINANCIAL STATEMENTS Page
- -------------------------------------------- ----
Report of Independent Public Accountants F-2
Independent Auditors' Report F-3
Consolidated Balance Sheets, December 31, 1997 and 1996 F-4
Consolidated Statements of Income (Operations) for the Years Ended
December 31, 1997, 1996 and 1995 F-6
Consolidated Statements of Changes in Stockholders' Equity
for the Years Ended December 31, 1997, 1996 and 1995 F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995 F-8
Notes to Consolidated Financial Statements for the Years Ended
December 31, 1997, 1996 and 1995 F-10
<PAGE>
Report of Independent Public Accountants
To the Stockholders and Board of Directors of PANACO, Inc.:
We have audited the accompanying consolidated balance sheets of PANACO, Inc. (a
Delaware Corporation) and subsidiaries as of December 31, 1997 and 1996, and the
related consolidated statements of income (operations), changes in stockholders'
equity and cash flows for the years then ended. 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 consolidated financial statements referred to above present
fairly, in all material respects, the financial position of PANACO, Inc. and
subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for the years then ended in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Kansas City, Missouri,
April 7, 1998
F-2
<PAGE>
Independent Auditors' Report
To the Board of Directors
PANACO, Inc.
We have audited the accompanying balance sheets of PANACO, Inc. (a Delaware
corporation) as of December 31, 1995 and the related statement of income
(operations), changes in Stockholders' equity and cash flows for the year ended
December 31, 1995. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in the 1995 Financial Statements, the Company has given retroactive
effect to the change in accounting for its oil and gas operations.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PANACO, Inc. as of December 31,
1995 and the results of its operations, changes in stockholders' equity and cash
flows for the year ended December 31, 1995 in conformity with generally accepted
accounting principles.
BARRETT & ASSOCIATES
Overland Park, Kansas
February 26, 1996, except for the change in accounting for oil and gas
operations, for which the date is June 7, 1996.
F-3
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED BALANCE SHEETS
<CAPTION>
ASSETS
December 31,
1997 1996
CURRENT ASSETS ------ ------
<S> <C> <C>
Cash and cash equivalents $ 36,909,000 $ 1,736,000
Accounts receivable 9,735,000 6,197,000
Investment in marketable securities --- 1,642,000
Prepaid and other 626,000 424,000
------------ ------------
Total current assets 47,270,000 9,999,000
------------ ------------
OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
Oil and gas properties, proved 198,840,000 125,283,000
Oil and gas properties, unproved 12,947,000 7,128,000
Less accumulated depreciation, depletion and amortization (99,239,000) (81,871,000)
------------ -----------
Net oil and gas properties 112,548,000 50,540,000
----------- -----------
PROPERTY, PLANT, AND EQUIPMENT
Pipelines and equipment 14,875,000 10,534,000
Less accumulated depreciation (1,416,000) (327,000)
------------ -----------
Net property, plant and equipment 13,459,000 10,207,000
------------ -----------
OTHER ASSETS
Deferred debt costs, net 3,813,000 611,000
Restricted deposits 2,256,000 2,115,000
Other 283,000 296,000
------------- -----------
Total other assets 6,352,000 3,022,000
------------- -----------
TOTAL ASSETS $ 179,629,000 $ 73,768,000
============== ============
The accompanying notes are an integral part of these
consolidated statements.
</TABLE>
F-4
<PAGE>
<TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<CAPTION>
December 31,
1997 1996
------ ------
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable $ 17,225,000 $ 6,246,000
Interest payable 2,416,000 524,000
Current portion of long-term debt --- ---
------------ -----------
Total current liabilities 19,641,000 6,770,000
------------ -----------
LONG-TERM DEBT 101,700,000 49,500,000
DEFERRED INCOME TAXES 3,100,000 ---
COMMITMENTS AND CONTINGENCIES --- ---
STOCKHOLDERS' EQUITY
Preferred Shares, $.01 par value,
5,000,000 shares authorized; no
shares issued and outstanding --- ---
Common Shares, $.01 par value,
40,000,000 shares authorized;
23,913,531 and 14,350,255 shares
issued and outstanding, respectively 239,000 143,000
Additional paid-in capital 69,041,000 31,490,000
Retained earnings (deficit) (14,092,000) (14,135,000)
------------ ------------
Total Stockholders' Equity 55,188,000 17,498,000
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 179,629,000 $ 73,768,000
============= ============
The accompanying notes are an integral part of these
consolidated statements.
</TABLE>
F-5
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF INCOME (OPERATIONS)
<CAPTION>
Year Ended December 31,
1997 1996 1995
REVENUES =========== =========== ============
<S> <C> <C> <C>
Oil and natural gas sales $37,841,000 $20,063,000 $ 18,447,000
COSTS AND EXPENSES
Lease operating expense 11,305,000 8,477,000 8,055,000
Depreciation, depletion and amortization 18,866,000 9,022,000 8,064,000
General and administrative expense 1,764,000 772,000 690,000
Production and ad valorem taxes 721,000 559,000 1,078,000
Exploratory dry hole expense 67,000 --- 8,112,000
Geological and geophysical expense 286,000 --- ---
Provision for losses on disposition
and write-down of assets --- --- 751,000
West Delta fire loss --- 500,000 ---
------------ ----------- -----------
Total 33,009,000 19,330,000 26,750,000
------------ ----------- -----------
OPERATING INCOME (LOSS) 4,832,000 733,000 (8,303,000)
------------ ----------- -----------
OTHER INCOME (EXPENSE)
Gain (loss) on investment in common stock 75,000 (258,000) ---
Interest income 745,000 29,000 5,000
Interest expense (4,675,000) (2,543,000) (992,000)
------------- ----------- -----------
Total (3,855,000) (2,772,000) (987,000)
------------- ----------- -----------
INCOME (LOSS) BEFORE INCOME
TAXES AND EXTRAORDINARY ITEM 977,000 (2,039,000) (9,290,000)
INCOME TAXES --- --- ---
------------- ----------- -----------
INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM 977,000 (2,039,000) (9,290,000)
EXTRAORDINARY ITEM - Loss on early
retirement of debt (934,000) --- ---
------------- ----------- ------------
NET INCOME (LOSS) $ 43,000 $( 2,039,000) $ (9,290,000)
============= =========== ============
BASIC AND DILUTED EARNINGS (LOSS)
PER SHARE
Income (loss) before extraordinary item $ .05 $ (.16) $ (.81)
Extraordinary item (.05) --- ---
------------- ----------- ------------
Net income (loss) $ --- $ (.16) $ (.81)
============= =========== ============
BASIC WEIGHTED AVERAGE
SHARES OUTSTANDING 20,781,205 12,742,213 11,504,615
============= ============ ============
DILUTED WEIGHTED AVERAGE
SHARES OUTSTANDING 21,024,847 12,742,213 11,504,615
============= ============ ============
The accompanying notes are an integral part of these
consolidated statements.
</TABLE>
F-6
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995, 1996 AND 1997
<CAPTION>
Common Additional Retained
Share Paid-In Earnings
Shares Par Value Capital (Deficit)
========== ========== =========== =============
Balances, December 31, 1994 10,220,138 $ 102,000 $17,586,000 $ (2,806,000)
<S> <C>
Net loss --- --- --- (9,290,000)
Exercise of stock options and warrants 1,181,602 12,000 3,137,000 ---
Issuance of new shares 102,875 1,000 432,000 ---
---------- ---------- ---------- -----------
Balances, December 31, 1995 11,504,615 115,000 21,155,000 (12,096,000)
Net loss --- --- --- (2,039,000)
Exercise of warrants, shares issued under
Employee Stock Ownership Plan and
Director stock bonuses 845,640 8,000 1,955,000 ---
Acquisition of properties 2,000,000 20,000 8,380,000 ---
---------- --------- ---------- -----------
Balances, December 31, 1996 14,350,255 143,000 31,490,000 (14,135,000)
Net income --- --- --- 43,000
Exercise of warrants, shares issued under
Employee Stock Ownership Plan and
Director and employee stock bonuses 324,346 3,000 783,000 ---
Issuance of warrants to retire debt --- --- 450,000 ---
Acquisition of properties 3,238,930 33,000 14,381,000 ---
Issuance of new shares 6,000,000 60,000 21,937,000 ---
---------- --------- ----------- ------------
Balances, December 31, 1997 23,913,531 $ 239,000 $69,041,000 $(14,092,000)
========== ========= =========== ============
The accompanying notes are an integral part of these
consolidated statements.
</TABLE>
F-7
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Year Ended December 31,
1997 1996 1995
CASH FLOWS FROM OPERATING ACTIVITIES ============ ============ ============
<S> <C> <C> <C>
Net income (loss) $ 43,000 $ (2,039,000) $ (9,290,000)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Extraordinary item 934,000 --- ---
Depreciation, depletion and amortization 18,866,000 9,022,000 8,065,000
Exploratory dry hole expense 67,000 --- 8,112,000
Provision for losses on disposition
and write-down of assets --- --- 751,000
Loss (gain) on investment in common stock (75,000) 258,000 ---
ESOP stock contribution 165,000 122,000 132,000
Changes in operating assets and liabilities,
net of acquisitions:
Accounts receivable (969,000) (1,811,000) (2,155,000)
Prepaid and other 129,000 274,000 (125,000)
Accounts payable 4,172,000 1,803,000 2,916,000
Interest payable 1,822,000 363,000 (24,000)
----------- ---------- ----------
Net cash provided by operating activities 25,154,000 7,992,000 8,382,000
----------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and gas properties 87,000 9,017,000 11,000
Proceeds from the sale of investment in common stock 1,717,000 --- ---
Capital expenditures and acquisitions (41,997,000) (43,050,000) (21,841,000)
Increase in restricted deposits (141,000) (2,115,000) ---
Other --- 96,000 ---
------------ ----------- -----------
Net cash used in investing activities (40,334,000) (36,052,000) (21,830,000)
------------ ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the common stock offering, net 21,997,000 --- ---
Long-term debt proceeds 112,459,000 38,514,000 16,890,000
Repayment of long-term debt (84,742,000) (11,753,000) (7,000,000)
Proceeds from the issuance of common shares -
exercise of warrants and options 639,000 1,837,000 3,173,000
------------ ----------- -----------
Net cash provided by financing activities 50,353,000 28,598,000 13,063,000
------------ ----------- -----------
NET INCREASE (DECREASE) IN CASH 35,173,000 538,000 (385,000)
CASH AT BEGINNING OF YEAR 1,736,000 1,198,000 1,583,000
------------ ----------- -----------
CASH AT END OF YEAR $ 36,909,000 $ 1,736,000 $ 1,198,000
============ ============ ============
The accompanying notes are an integral part of these
consolidated statements.
</TABLE>
F-8
<PAGE>
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
For the year ended December 31, 1997:
The Company issued 10,649 common shares as director and employee bonuses
and contributed 24,332 shares to the ESOP. The Company also issued 3,238,930
common shares, $6.0 million in notes, assumed $19.2 million in debt and net
liabilities and recorded a $3.1 million deferred tax liability in connection
with an acquisition.
The Company issued 2,060,606 warrants to acquire common shares to a former
lender in connection with debt which was prepaid in 1997.
For the year ended December 31, 1996:
The Company issued 2,000,000 common shares totaling $8.4 million to Amoco
Production Company in connection with an acquisition of oil and gas assets.
The Company issued 2,447 common shares each to two new directors. The Company
also issued 24,220 shares to the ESOP.
The Company received 477,612 shares of National Energy Group, Inc. common stock
in connection with the sale of the Bayou Sorrel Field.
For the year ended December 31, 1995:
The Company issued 97,680 common shares totaling $409,000 in exchange for oil
and gas properties.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year ended December 31:
1997 1996 1995
---- ---- ----
Interest $2,552,000 $2,218,000 $1,016,000
========== ========== ==========
Income taxes $ --- $ --- $ ---
=========== ========== ==========
F-9
<PAGE>
PANACO, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
The Company is an independent oil and natural gas exploration and production
company with operations focused in the Gulf of Mexico and onshore in the Gulf
Coast region. It 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, 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.
Revenue Recognition
The Company recognizes its ownership interest in oil and gas sales as revenue.
Gas balancing arrangements with partners in natural gas wells are accounted for
by the entitlements method. At December 31, 1997 and 1996 both the quantity and
dollar amounts of such arrangements recorded in the Consolidated Balance Sheet
were immaterial.
Hedging Transactions
The Company hedges the prices of its oil and gas production through the use of
oil and natural gas hedge and swap contracts within the normal course of its
business. The Company uses hedge and swap contracts to reduce the effects of
fluctuations in oil and natural gas prices (see Note 7). Changes in the market
value of these contracts are deferred and subsequent gains and losses are
recognized monthly as adjustments to revenues in the same production period as
the hedged item. Contracts are placed with major financial institutions that the
Company believes have minimal credit risk.
Income Taxes
The Company records income taxes in accordance with the requirements of
Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for
Income Taxes", which requires recognition of deferred tax assets and liabilities
for the expected future tax consequences of events that have been included in
the financial statements or tax returns. Under this method, deferred tax assets
and liabilities are determined based on the differences between the financial
statement and tax bases of assets and liabilities using enacted tax rates.
Oil and Gas Producing Activities and Depreciation, Depletion and Amortization
The Company utilizes the successful efforts method of accounting for its oil and
gas properties. Under the successful efforts method, lease acquisition costs are
capitalized. Non-drilling exploratory costs including geological and geophysical
costs and delay rentals are expensed. Exploratory drilling costs are also
capitalized pending determination of proved reserves. If proved reserves are not
discovered, the exploratory costs are expensed. All development costs are
capitalized. Provision for depreciation and depletion is determined on a
field-by-field basis using the unit-of-production method. Estimated future
abandonment costs are recorded by charges to depreciation and depletion expense
over the lives of the proved reserves of the properties. The carrying amounts of
unproved properties are not depleted until a determination of reserves has been
made. The carrying amounts of proven and unproven properties are reviewed
periodically on a field-by-field basis, based on future net cash flows
F-10
<PAGE>
determined by independent engineering firms, and an impairment reserve is
provided as conditions warrant. A provision for the write down of assets in the
amount of $751,000 was incurred in 1995. Fees for processing and transporting
oil and natural gas for others are treated as a reduction of lease operating
expense related to the facilities and infrastructure.
Capitalized Interest
The Company capitalizes interest costs associated with unproved properties.
Interest capitalized in 1997, 1996 and 1995 was $513,000, $0 and $0,
respectively.
Property, Plant & Equipment
Property and equipment are carried at cost. Oil and natural gas pipelines and
equipment are depreciated on the straight-line method over their estimated
lives, primarily fifteen years. Other property is also depreciated on the
straight-line method over their estimated lives, ranging from three to ten
years.
Amortization of Deferred Debt Costs
Cost incurred in debt financing transactions are amortized over the term of the
debt.
Per Share Amounts
Effective December 31, 1997, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 128, "Earnings per Share." In accordance with
SFAS No. 128, the Company's basic earnings per share amounts have been computed
based on the average number of common shares outstanding. Diluted weighted
average shares outstanding amounts include the effect of the Company's
outstanding stock options and warrants using the treasury stock method when
dilutive. Basic and diluted earnings per share were the same for all periods
presented.
Stock Based Compensation
The Company accounts for stock-based compensation under the intrinsic value
method. Under this method, the Company records no compensation expense for stock
options granted when the exercise price of options granted is equal to or higher
than the fair market value of the Company's common shares on the date of grant,
see Note 8.
Consolidated Statements of Cash Flows
For purposes of reporting cash flows, the Company considers all cash investments
with original maturities of three months or less to be cash equivalents.
Use of Estimates
The preparation of financial statements in accordance with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses, and
disclosure of contingent assets and liabilities in the financial statements,
including the use of estimates for oil and gas reserve information and the
valuation allowance for deferred income taxes. Actual results could differ from
those estimates. Estimates related to oil and gas reserve information and the
standardized measure are based on estimates provided by independent engineering
firms. Changes in prices could significantly affect these estimates from year to
year.
Reclassification
Certain financial statement items have been reclassified to conform to the
current year's presentation.
F-11
<PAGE>
Note 2 - ACQUISITIONS AND DISPOSITIONS
On July 31, 1997, the Company acquired Goldking by merging its corporate parent,
The Union Companies, Inc. (Union) into Goldking Acquisition Corp., a newly
formed, wholly-owned subsidiary of the Company. The individual shareholders of
Union received merger consideration consisting of $7.5 million in cash, $6
million in notes (which were paid in October 1997) and 3,154,930 Company common
shares, valued at $14 million. The Company assumed the debt of Goldking of $15.9
million and other net liabilities of $3.3 million and recorded a $3.1 million
deferred tax liability based upon the complete utilization of the Company's
deferred tax asset valuation allowance and the requirement for additional
deferred tax liabilities resulting from the acquisition. The purchase price
allocation is preliminary, based upon the estimated tax effects of the Company's
merger with Goldking. Management does not expect any change in the final
allocation of the purchase price and the resulting effect on depletion,
depreciation and amortization to be material.
On October 8,1996, the Company closed its acquisition of interests in thirteen
offshore blocks comprising six fields in the Gulf of Mexico from Amoco
Production Company. The purchase price for the assets acquired in this
transaction was $40.4 million, paid by the issuance of 2,000,000 common shares,
valued at $4.20 per share, and by payment to Amoco of $32 million in cash.
Both of these acquisitions were accounted for using the purchase method. The
results for the Amoco acquisition are included in the Company's results of
operations from October 8, 1996. The results for Goldking are included in the
Company's results of operations from August 1, 1997.
Effective September 1, 1996, the Company sold its Bayou Sorrel Field for
$11,000,000. This field was purchased in 1995 from Shell Western E & P, Inc. for
$10,500,000. There was no gain or loss on the sale of the field and the
remaining net book value is assigned to an overriding royalty interest retained.
The following unaudited pro forma financial information assumes the Goldking and
Amoco acquisitions had been consummated January 1, 1996, and the Bayou Sorrel
sale was completed January 1, 1996. The pro forma financial information does not
purport to be indicative of the results of the Company had these transactions
occurred on the date assumed, nor is it necessarily indicative of the future
results of the Company.
Unaudited Pro Forma Financial Information
For the Years Ended December 31, 1997 and 1996
1996 1997
----------- -----------
Revenues $41,938,000 $37,164,000
Income (loss) before extraordinary item (1,446,000) (2,475,000)
Net income (loss) (2,380,000) (2,475,000)
Net income (loss) per share $ (0.10) $ (0.14)
Note 3 - EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)
In August 1994 the Company established an ESOP and Trust that covers
substantially all employees. The Board of Directors can approve contributions,
up to a maximum of 15% of eligible employees' gross wages. The Company incurred
$165,000, $122,000 and $132,000 in costs for the years ended December 31, 1997,
1996 and 1995, respectively.
F-12
<PAGE>
Note 4 - RESTRICTED DEPOSITS
Pursuant to existing agreements the Company is required to deposit funds in bank
escrow and trust accounts to provide a reserve against satisfaction of its
eventual responsibility to plug and abandon wells and remove structures when
certain fields no longer produce oil and gas. Under the terms of the escrow
agreements, the company will be required to deposit 10% of the net cash flow
from the Amoco properties (as defined) into an escrow fund in 1998. In addition,
another agreement requires the Company to deposit into escrow accounts $997,000
during 1999 and $576,000 during 2000.
Note 5- LONG-TERM DEBT
1997 1996
============= ============
10 5/8 % Senior Notes due 2004(a) $100,000,000 $ ---
Note payable (b) --- 27,500,000
Note payable (c) --- 22,000,000
Production payment(d) 1,700,000 ---
------------ ------------
101,700,000 49,500,000
Less current portion --- ---
------------ ------------
Long-term debt $101,700,000 $ 49,500,000
============ ============
(a) In October 1997 the Company issued $100 million of 10.625% Senior Notes due
2004. Interest is payable semi-annually April 1 and October 1 of each year
beginning April 1, 1998. The net proceeds of the transaction were used to
repay or prepay substantially all of the Company's outstanding indebtedness
and for capital expenditures. The estimated fair value of these notes at
December 31, 1997 was $109,420,000 based on quoted market prices. The notes
are the general unsecured obligations of the Company and rank senior in
right of payment to any subordinated obligations.
(b) In October 1997, the Company amended its bank facility. The loan is a
reducing revolver designed to provide the Company up to $75 million
depending on the Company's borrowing base, as determined by the lenders.
The Company's borrowing base at December 31, 1997 was $40 million, with
availability under the revolver of $39 million. The principal amount of the
loan is due October 22, 2002, however, at no time may the Company have
outstanding borrowings in excess of its borrowing base. Interest on the
loan is computed at the bank's prime rate or at 1 to 1 3/4% (depending upon
the percentage of the facility being used) over the applicable London
Interbank Offered Rate (LIBOR) on Eurodollar loans. The bank facility is
collateralized by a first mortgage on the Company's offshore properties.
The loan agreement contains certain covenants including a requirement to
maintain a positive indebtedness to cash flow ratio, a positive working
capital ratio, a certain tangible net worth, as well as limitations on
future debt, guarantees, liens, dividends, mergers, material change in
ownership by management, and sale of assets.
(c) From time to time the Company has borrowed funds from institutional
lenders. In each case these loans were due at a stated maturity, required
payments of interest only at 12% per annum 45 days after the end of each
calendar quarter and were secured by a second mortgage on the Company's
offshore oil and gas properties. The loans were repaid in 1997. In
connection with the prepayment of the Convertible Subordinated notes, the
Company issued these lenders warrants to acquire 2,060,606 common shares at
an exercise price of $4.125 any time prior to December 31, 1998.
(d) Represents a production payment obligation to a former lender which is paid
with a portion of the revenues from certain wells.
F-13
<PAGE>
Note 6 - EXTRAORDINARY ITEM - LOSS ON EARLY RETIREMENT OF DEBT
In October 1997, the Company issued $100 million of 10.625% Senior Notes due
2004, see note 5. A portion of the proceeds from the offering was used to repay
or prepay substantially all of the Company's outstanding indebtedness. With the
early retirement of the debt, the Company incurred a $484,000 charge to
write-off the deferred financing costs associated with the previous debt
facilities. In addition, as part of the prepayment of the convertible
subordinated notes, the Company issued 2,060,606 warrants to acquire common
shares at an exercise price of $4.125 per share which were the existing
conversion terms of the prepaid notes. The fair value of these warrants has been
estimated by an investment banker to be approximately $450,000, which has been
recorded as an extraordinary item and additional paid-in capital.
Note 7 - COMMODITY HEDGE AGREEMENTS
During 1997 the Company hedged 263,000 barrels of oil and 5.1Bcf of gas, which
represented 51% and 45%, respectively, of production, and resulted in a loss on
such hedges of $1,270,000, thereby reducing the Company's average gross margin
on oil and gas by $0.13 per barrel and $0.10 per Mcf, respectively.
Hedge agreements for 1998 are for 463,000 barrels of oil and 12.0 Bcf of gas,
which represent 68% and 61%, respectively, of its anticipated 1998 production
based upon the year-end reserve reports. At December 31, 1997, the estimated
fair market value of the hedge agreements was a loss of $61,000. At December 31,
1996, the estimated fair market value of the hedge agreements was a loss of
$897,000.
These hedge agreements provide for the counterparty to make payments to the
Company to the extent the market prices (as determined in accordance with the
agreement) are less than the fixed prices for the notional amount hedged and the
Company to make payments to the counterparty to the extent market prices are
greater than the fixed prices, subject to the Company's participation in the
excess. The Company accounts for the gains and losses in oil and natural gas
revenue in the month of hedged production.
Note 8 - STOCK OPTIONS AND WARRANTS
On August 26, 1992, the shareholders approved a long-term incentive plan
allowing the Company to grant incentive and non-statutory stock options,
performance units, restricted stock awards and stock appreciation rights to key
employees, directors, and certain consultants and advisors of the Company up to
a maximum of 20% of the total number of shares outstanding.
SFAS No. 123, "Accounting for Stock-based Compensation" defines a fair value
method of accounting for an employee stock option or similar equity instrument.
The Company has elected to account for its stock options under the intrinsic
value method, whereby, no compensation expense is recognized for stock options
granted with an exercise price equal to or greater than the market value of the
Company's common stock on the date of the grant. On June 18, 1997, 1,200,000
options at $4.45 per share were issued to certain employees under the provisions
of the Company's long-term incentive plan, which expire June 20, 2000. Ownership
of the stock acquired upon exercise is contractually restricted for a three-year
period from the date of exercise, except in certain circumstances as described
in the plan.
F-14
<PAGE>
<TABLE>
<CAPTION>
1995 1996 1997
====================== ====================== =========================
Wtg. Avg. Wtg. Avg. Wtg. Avg.
Shares Ex. Price Shares Ex. Price Shares Ex. Price
------ --------- ------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 975,232 $2.44 289,365 $2.21 289,365 $ 2.21
Granted 0 --- 0 --- 1,200,000 4.45
Exercised (685,867) 2.54 0 --- (289,365) 2.21
Forfeited 0 --- 0 --- (10,000) 4.45
--------- ----- --------- ----- ----------- ------
Outstanding at end of year 289,365 2.21 289,365 2.21 1,190,000 4.45
--------- ----- --------- ----- ----------- ------
Exercisable at end of year 289,365 $2.21 289,365 $2.21 1,190,000 $4.45
Fair value of options granted N/A N/A $ 1.42
</TABLE>
The fair value of each option in 1997 was estimated at the date of grant using
the Black-Scholes Modified American Option Pricing Model with the following
assumptions:
Expected option life-years 3
Risk-free interest rate 6.1%
Dividend yield 0%
Volatility 38.4%
If compensation expense for the Company's stock option plans had been recorded
using the Black-Scholes fair value method and the assumptions described above,
the Company's net income (loss) and earnings (loss) per share for 1997 would
have been as shown below:
Net income(loss): As reported $ 43,000
Pro forma $ (239,000)
Earnings per share (loss) As reported $ ---
Pro forma $ (0.01)
Note 9 - MAJOR CUSTOMERS
One purchaser accounted for 62%, 49% and 69% of revenues in 1997, 1996 and 1995
respectively. These transactions represented spot sales of natural gas to one
customer.
Note 10 - INCOME TAXES
At December 31, 1997, the Company had net operating loss carry forwards for
federal income tax purposes of approximately $40,000,000 which are available to
offset future federal taxable income through 2012. The Company's timing of its
utilization of net operating loss carry forwards may be limited on an annual
basis in the future due to its issuance of common shares and the purchase of
Goldking common stock.
Significant components of the Company's deferred tax assets (liabilities) as of
December 31 are as follows:
1997 1996
------------ ------------
Deferred tax assets(liabilities)
Fixed asset basis differences $ (17,200,000) $ 2,312,000
Net operating loss carry forwards 14,100,000 6,342,000
----------- -----------
Total deferred tax assets(liabilities) (3,100,000) 8,654,000
----------- -----------
Valuation allowance for deferred
tax assets --- (8,654,000)
----------- ----------
Total deferred tax assets(liabilities) $(3,100,000) $ ---
=========== ==========
F-15
<PAGE>
A valuation allowance was provided at December 31, 1996 to reduce the deferred
tax assets to a level which, more likely than not, will be realized. The net
change in the total valuation allowance for the years ended December 31, 1997
and 1996 was a decrease of $8,654,000 and an increase of $940,000, respectively.
The decrease in the Company's deferred tax asset in 1997 is due to the
acquisition of Goldking. In connection with the acquisition, the Company
recorded a $3.1 million deferred tax liability based upon the complete
utilization of the Company's deferred tax asset valuation allowance and the
requirement for additional deferred tax liabilities resulting from the
acquisition.
Note 11 - COMMITMENTS AND CONTINGENCIES
The Company is subject to various legal proceedings and claims which arise in
the ordinary course of business. In the opinion of management, the amount of
liability, if any, with the respect to these actions would not materially affect
the financial position of the Company or its results of operation.
The Company has commitments under operating lease agreements for office space
leases. At December 31, 1997, the future minimum rental payments due under the
leases are as follows:
1998 $ 340,000
1999 360,000
2000 367,000
2001 420,000
2002 438,000
Thereafter 792,000
Total $2,717,000
Note 12 - SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
The following table reflects the costs incurred in oil and gas property
activities for each of the three years ended December 31:
1997 1996 1995
=========== ============ ============
Property acquisition costs, proved $39,384,000 $ 26,859,000 $ 12,603,000
Property acquisition costs, unproved 6,026,000 5,390,000 ---
Exploration costs 353,000 --- 8,112,000
Development costs 29,276,000 8,863,000 1,497,000
Quantities of Oil and Gas Reserves
The estimates of proved reserve quantities at December 31, 1997, are based upon
reports of third party petroleum engineers (Ryder Scott Company, W.D. Von Gonten
& Co. and McCune Engineering, P.E.) and do not purport to reflect realizable
values or fair market values of reserves. It should be emphasized that reserve
estimates are inherently imprecise and accordingly, these estimates are expected
to change as future information becomes available. These are estimates only and
should not be construed as exact amounts. All reserves are located in the United
States.
Proved reserves are estimated reserves of natural gas and crude oil and
condensate that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those expected
to be recovered through existing wells, equipment and operating methods.
F-16
<PAGE>
Proved developed and undeveloped reserves: Oil Gas
(BBLS) (MCF)
========= ==========
Estimated reserves as of December 31, 1994 943,000 41,582,000
Production (170,000) (9,850,000)
Sale of minerals in-place (1,000) (22,000)
Purchase of minerals in-place 1,140,000 20,094,000
Revisions of previous estimates (12,000) (5,093,000)
----------- ----------
Estimated reserves as of December 31, 1995 1,900,000 46,711,000
Production (276,000) (6,788,000)
Extensions and discoveries --- 972,000
Sale of minerals in-place (805,000) (3,102,000)
Purchase of minerals in-place 1,379,000 16,633,000
Revisions of previous estimates 41,000 (12,980,000)
----------- -----------
Estimated reserves as of December 31, 1996 2,239,000 41,446,000
Production (515,000) (11,468,000)
Extensions and discoveries 459,000 20,002,000
Sale of minerals in-place (11,000) (252,000)
Purchase of minerals in-place 2,334,000 23,904,000
----------- -----------
Estimated reserves as of December 31, 1997 4,506,000 73,632,000
=========== ===========
Proved developed reserves:
Oil Gas
(BBLS) (MCF)
----------- ------------
December 31, 1994 907,000 36,282,000
========== ==========
December 31, 1995 1,794,000 40,323,000
========== ==========
December 31, 1996 1,867,000 39,288,000
========== ==========
December 31, 1997 3,194,000 55,690,000
========== ==========
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows are computed by applying year-end prices of oil and gas
(with consideration of price changes only to the extent provided by contractual
arrangements) to the year-end estimated future production of proved oil and gas
reserves. Estimates of future development and production costs are based on
year-end costs and assume continuation of existing economic conditions. The
estimated future net cash flows are then discounted using a rate of 10 percent
per year to reflect the estimated timing of the future cash flows. The
standardized measure of discounted cash flows is the future net cash flows less
the computed discount.
F-17
<PAGE>
The accompanying table reflects the standardized measure of discounted
future cash flows relating to proved oil and gas reserves as of the three years
ended December 31:
<TABLE>
<CAPTION>
1997 1996 1995
--------------- --------------- --------------
<S> <C> <C> <C>
Future cash inflows $ 269,141,000 $ 210,875,000 $140,247,000
Future development and production costs (102,114,000) 61,822,000) (50,723,000)
--------------- --------------- --------------
Future net cash flows 167,027,000 149,053,000 89,524,000
Future income taxes (10,563,000) (17,899,000) (11,755,000)
--------------- --------------- --------------
Future net cash flows after income taxes 156,464,000 131,154,000 77,769,000
10% annual discount (35,592,000) (31,313,000) (14,848,000)
--------------- --------------- --------------
Standardized measure after income taxes $ 120,872,000 $ 99,841,000 $ 62,921,000
============= ============== ===============
</TABLE>
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
The accompanying table reflects the principal changes in the standardized
measure of discounted future net cash flows attributable to proved oil and gas
reserves for each of the three years ended December 31:
<TABLE>
<CAPTION>
1997 1996 1995
------------- ------------- -----------
<S> <C> <C> <C>
Beginning balance $ 99,841,000 $ 62,921,000 $41,915,000
Sales of oil and gas, net of production costs (25,815,000) (11,027,000) (9,314,000)
Net change in income taxes 5,465,000 (4,116,000) (4,267,000)
Changes in price and production costs (32,461,000) 44,088,000 11,498,000
Purchases of minerals in-place 40,027,000 45,521,000 34,415,000
Sale of minerals in-place --- (10,518,000) ---
Revision of previous estimates, extensions &
discoveries, net 33,815,000 (27,028,000) (11,326,000)
------------- ------------ ------------
Ending balance $120,872,000 $99,841,000 $62,921,000
============= ============ ============
</TABLE>
F-18
<PAGE>
Ex. 10.13.1
AMENDMENT TO
PANACO, INC. EMPLOYEE STOCK OWNERSHIP PLAN
The PANACO, Inc. Employee Stock Ownership Plan dated April 28, 1994
("Plan"), is hereby amended in accordance with Section 24 of the Plan in the
following respects effective July 31, 1997:
1. The definition of "Board' in Section 2 of the Plan is hereby amended
in its entirety to read as follows:
"Board" - The Board of Directors of PANACO, Inc."
2. The definition of "Company" in Section 2 of the Plan is hereby amended
in its entirety to read as follows:
"Company" - PANACO, Inc., a Delaware corporation, whose address is 1050
West Blue Ridge Boulevard, Kansas City, Missouri 64145-1216, and any entity
which is part of a Controlled Group which includes PANACO, Inc. Each entity
meeting the definition of "Company" shall be considered the Company under
the terms of the Plan except that PANACO, Inc. shall be the Plan Sponsor of
the Plan, and shall have the sole right and responsibility to carry out the
duties and exercises the rights of the Plan Sponsor."
3. The definition of "Compensation" in Section 2 of the Plan is hereby
amended by the addition thereto of the following:
"Not withstanding anything else herein, "Compensation" shall not include
any remuneration received by a Participant with respect to services
rendered prior to August 1, 1997 to Goldking Production, or any entity
which is part of a Controlled Group which included Goldking Production
Company on July 31, 1997."
4. Section 2 of the Plan is hereby amended by the addition thereto of the
following new definition of "Controlled Group":
"Controlled Group" - A controlled group shall consist of any entity and any
other entity or entities who form a controlled group of corporations or a
controlled group of businesses in accordance with Section 414(b) or Section
414(c) of the Code."
5. Section 3(b) of the Plan is hereby amended by the addition thereto of
the following new subsection (e):
" (e) Employees who were employed by Goldking Production Company or any
entity which was part of a Controlled Group which included Goldking
Production Company, on July 31, 1997, shall receive credit for all Hours of
Service rendered to Goldking Production Company or any such entity, whether
before or after July 31, 1997, for purposes of the following:
(1) In determining entitlement to share in the allocation of the Company
Contribution and Forfeitures under Section 3(b) above for the Plan Year
ending December 31, 1997; and
(2) In determining eligibility to participate in the Plan in accordance
with Section 3(a) above."
6. Section 14 of the Plan is hereby amended by the addition thereto of
the following new subsection (c):
" (c) Service With Goldking. Employees who were employed by Goldking
Production Company or any entity which was part of a Controlled Group
which included Goldking Production Company on July 31, 1997, shall
receive credit for all Hours of Service rendered to Goldking
Production Company or any such entity, whether before or after July
31, 1997, for purposes of determining Plan Years and Credited Service
taken into account for purposes of Section 13 of the Plan."
IN WITNESS HEREOF, this Amended has been executed on behalf of the
following party as of this 25th day of February 1998.
PANACO, Inc.
By: /s/ H. James Maxwell
Chief Executive Officer
By: /s/ Todd R. Bart
Secretary
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 36909000
<SECURITIES> 0
<RECEIVABLES> 9735000
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 47270000
<PP&E> 223562000
<DEPRECIATION> 100655000
<TOTAL-ASSETS> 179629000
<CURRENT-LIABILITIES> 19641000
<BONDS> 101700000
0
0
<COMMON> 239000
<OTHER-SE> 54949000
<TOTAL-LIABILITY-AND-EQUITY> 176629000
<SALES> 37841000
<TOTAL-REVENUES> 37841000
<CGS> 0
<TOTAL-COSTS> 33009000
<OTHER-EXPENSES> 790000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4675000
<INCOME-PRETAX> 977000
<INCOME-TAX> 0
<INCOME-CONTINUING> 977000
<DISCONTINUED> 0
<EXTRAORDINARY> 934000
<CHANGES> 0
<NET-INCOME> 43000
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
