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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________
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, 1998
[ ] 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 (I.R.S. Employer
of incorporation or organization) Identification Number)
1100 Louisiana, Suite 5100
Houston, TX 77002 77002-5220
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 970 - 3100
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. [ ]
The aggregate market value of the voting stock held by non-affiliates of the
registrant was approximately $14,877,008 as of March 31, 1999.
23,985,927 shares of the registrant's Common Stock were outstanding as
of March 31, 1999.
Documents Incorporated by Reference
Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 1998, are incorporated by reference into Part III.
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<PAGE>
PANACO, Inc. and Subsidiaries
Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 1998
<TABLE>
Table of Contents
<CAPTION>
Page Number
<S> <C>
Part I
Item 1. Business 2
Item 2. Properties 16
Item 3. Legal Proceedings 23
Item 4. Submission of Matters to a Vote of Security Holders 24
Part II
Item 5. Market for Common Stock and
Related Shareholder Matters 24
Item 6. Selected Financial Data 28
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 29
Item 7a. Quantitative and Qualitative Disclosures
About Market Risks 35
Item 8. Financial Statements and Supplementary Data 36
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 36
Part III
Item 10. Directors and Executive Officers of the Registrant 37
Item 11. Executive Compensation 37
Item 12. Security Ownership of Certain Beneficial Owners and
Management 37
Item 13. Certain Relationships and Related Transactions 37
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports
On Form 8-K 37
Glossary of Selected Oil and Gas Terms 40
Signatures 43
</TABLE>
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ITEM 1. BUSINESS.
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Forward-looking statements in this Form 10-K, future filings by the Company
with the Securities and Exchange Commission ("SEC"), 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.
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, 1997 and 1998. The
Company has experienced substantial growth as a result of the acquisition of
offshore properties from Amoco (the "Amoco Acquisition") and BP Exploration &
Oil, Inc. (the "BP Acquisition") along with 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 office is located at 1100 Louisiana, Suite 5100, Houston,
Texas 77002-5220, and its telephone number is (713) 970-3100, FAX (713)
970-3151.
Business Strategy
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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 BP, Amoco and Goldking
Acquisitions, 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.
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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. A historical summary, through December 31, 1998, of the
Company's acquisitions is illustrated below:
<PAGE>
<TABLE>
<CAPTION>
Cumulative Cumulative
Purchase Purchase Capital Cash SEC
Acquisition Seller Date Price Expenditures(a) Flow(b) PV 10(c)
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(dollars in millions)
<S> <C> <C> <C> <C> <C> <C>
West Delta Fields(d) CATO(e) May 1991 $ 19.6 $ 18.8 $ 55.1 $ 6.9
Zapata Properties Zapata Jul 1995 2.7(f) 2.1 15.2 3.3
Amoco Properties Amoco Oct 1996 40.4 43.7 32.0 27.7
Goldking Shareholders Jul 1997 27.5(g) 9.5 11.2 29.6
BP Properties BP May 1998 19.6 1.8 4.4 21.0
_______________
(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, 1998.
(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) Excludes debt and liabilities of Goldking in the amount of $22.3 million.
</TABLE>
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.
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.
BP Acquisition
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On May 14, 1998 PANACO entered into a definitive agreement with BP
Exploration & Oil, Inc. ("BP") to acquire BP's 100% interest in East Breaks
Blocks 165 and 209 and 75% interest in High Island Block 587. The Acquisition
closed on May 26, 1998 and was accounted for using the purchase method. PANACO
acquired the properties for $19.6 million in cash. Included with the properties
is 3-D seismic data covering twenty offshore blocks. PANACO became the operator
of all three blocks effective June 1, 1998.
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The production platform in Block 165 is named "Snapper." This mammoth
structure, located in 863 feet of water, is among the tallest bottom supported
structures in the Gulf of Mexico. The two wells in High Island Block 587 are
completed subsea and tied back to the East Breaks 165 production platform. The
remaining 25% of High Island Block 587 is owned by Burlington Resources.
The Company acquired 31.72 miles of 12" oil pipeline, with capacity of over
20,000 barrels of oil per day, which ties the production platform back to the
High Island Pipeline System, the major oil transportation system in the area.
The Acquisition also included 9.3 miles of 12 3/4" gas pipeline, which ties the
production platform back to the High Island Offshore System, the major gas
transportation system in the area.
Goldking Acquisition
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Effective July 31, 1997, the Company acquired Goldking Companies, Inc.
("Goldking"), a privately owned, Houston-based oil and natural gas company.
Through the Goldking 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 Goldking's 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.
In 1998 the Company merged the Union subsidiaries and changed the name of that
subsidiary to PANACO Production Company.
Amoco Acquisition
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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. The Company acquired an additional 25% interest in West Cameron 180
Field in 1998.
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, 1998, 25% 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. A majority 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
23 offshore platforms and 109 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
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Field, East Breaks 160 Field and East Breaks 165 Field. The annual revenue
received from these contracts for use of the Company's infrastructure in 1998
totaled $2.8 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.
Selective Exploration Program
The Company allocated a modest portion of its 1998 capital budget to
exploratory projects and non-drilling exploration expenses. The non-drilling
exploration expenses are primarily related to the acquisition, review and
interpretation of 3-D Seismic. The Company participated in nine exploratory
wells in 1998 all of which were operated by third parties and the Company owned
working interests in these wells ranging from 7.5% to 20%. Three of the nine
exploratory wells the Company participated in were successful. The amount of
money spent on these type of expenditures is determined by management and
approved by the board of directors. The Company plans to spend significantly
less money on exploration expenses in 1999.
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 35% 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 49 linear miles
of 2-D Seismic data and 443 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.
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<PAGE>
Significant Operating Control
The Company operates 63% 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.
Well Operations
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The Company operates 93 offshore wells and owns all of the working
interests in a majority of those wells. The Company's 78 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 80 onshore wells in which it
owns a majority or all of the working interest. In addition, it owns working
interests in 370 onshore 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
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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.
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 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.
Use of 3-D Seismic Technology
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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.
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<PAGE>
3-D Seismic and CAEX technology have been in existence since the mid 1970s;
however, it was not until the late 1980s, 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.
With the BP Acquisition, the Company acquired 129 square miles of 3-D
Seismic that it is currently reviewing. The Company has used the seismic for its
workover and recompletion activity to date, and plans further development on the
fields acquired with the seismic. The Company is also processing 18 square miles
of new 3-D Seismic data shot over its East Breaks 109 and 110 fields for use in
developing those reserves.
Marketing of Production
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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 Plains Resources,
Amoco, Oxy, Conoco, Texaco, Unocal and Vastar. Oxy, 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. Plains Resources purchases the oil production from the Umbrella Point
Fields and the East Breaks 165 and 209 Fields. 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 42% of the revenues in 1998. There
are numerous natural gas purchasers doing business in the areas involved as well
as natural gas brokers and clearinghouses. 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.
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 7,301 to 27,301 MMbtu
per day in each of the months in 1999 for a total of 6,310,000 MMbtu, at
pipeline prices averaging approximately $1.98 per MMbtu, for a NYMEX equivalent
of approximately $2.13 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 has hedged
223 Bbls of oil for each day in 1999 at an average price of $17.27 per Bbl and
232 Bbls of oil for each day in 2000 at an average price of $17.35 per Bbl.
Plugging and Abandonment Escrows
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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 gas. Through November 30, 1997 the
Company funded $900,000 into an escrow account with respect to the West Delta
Fields. At that time, the Company completed its obligation for the funding of
the West Delta agreement. 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, from the Amoco properties. The Company has established
the "PANACO East Breaks 110 Platform Trust" in favor of the Minerals Management
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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 $2.4 million. In connection with the BP Acquisition, the
Company deposited $1 million into an escrow account on July 1, 1998. On the
first day of each quarter thereafter, the Company will deposit $250,000 into the
escrow account until the balance in the escrow account reaches $6.5 million.
Insurance
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The Company maintains insurance coverage which it believes 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.
Funding of Business Activities
- ------------------------------
The Company currently has a $17 million capital budget for 1999, which is
subject to change upon review by management and the board of directors. The
Company anticipated funding this capital budget through cash flows and
borrowings under its line of credit. In conjunction with an amendment to the
loan agreement, on April 13, 1999 the borrowing base under the line of credit
was reduced to $25 million, see "Bank Facility." The amendment provides for a $4
million reductions in this borrowing base on June 30, 1999 and September 30,
1999. With these reductions in the borrowing base, and the amount outstanding on
April 16, 1999 of $24 million, the Company will be required to reduce its 1999
capital budget to $11.5 million, which it currently has committed to spend.
These assumptions do not include any external sources of financing or
redeterminations of its borrowings. The line of credit permits the Company to
request such a redetermination from the bank.
During 1998, the Company's capital expenditures were approximately $61.8
million for (1) acquisition of an offshore property, (2) the development of its
oil and gas properties and (3) participation in exploratory wells. The sources
of funds for capital expenditures were cash flow from operations, proceeds from
the Senior Note offering and borrowings on the Company's existing bank facility.
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.
During 1996 shareholders' equity increased by $1.8 million, as a result of
the exercise of warrants, and $8.4 million 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 $22 million as a result of the issuance
of 6,000,000 Common Shares in a public offering, $1.2 million as a result of
issuance and exercise of warrants, contributions to the Company's ESOP and
employee stock bonuses, and $14.4 million 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. The
Company issued shares to the ESOP and as director compensation in 1998 which
increased shareholders' equity by $275,000.
Senior Notes
- ------------
On October 9, 1997 the Company issued $100 million 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.
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<PAGE>
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 as defined in the Indenture, 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 Company
must maintain a total Adjusted Consolidated Net Tangible Asset Value, as defined
in the Indenture, ("ACNTA") equal to 125% of the Company's indebtedness, as
defined in the Indenture, at the end of each quarter. If the Company's ACNTA
falls below this percentage of indebtedness for two succeeding quarters, the
Company must redeem an amount of the Senior Notes sufficient to maintain this
ratio.
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.
Bank Facility
- -------------
The Company has a $75.0 million revolving credit facility (the "Bank
Facility") from First Union National Bank of North Carolina, as Administrative
Agent and Banque Paribas (collectively, the "Lenders"). The Bank Facility
provides funds for working capital support and general corporate purposes and to
have available letters of credit.
The Bank Facility is a revolving credit subject to a borrowing base
determination made April 1 and October 1 of each year by the Lenders. At April
1, 1999 the borrowing base was reduced to $25.0 million from $45.0 million at
December 31, 1998. If at any time, at the sole discretion of the Lenders, 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. As of April 15,
1999, the Company's balance under the Bank Facility was $24.0 million. The
borrowing base is subject to $4 million reductions on June 30, 1999 and
September 30, 1999.
The Company may elect to pay interest on the Bank Facility at either the
Bank's prime rate or at LIBOR plus 1 to 1.75% at December 31, 1998 (effective
April 1, 1999 1.5 to 2.25%), 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 Bank Facility has a maturity of four years with no required principal
payments until maturity, provided that the outstanding principal balance does
not exceed the borrowing base determinations April 1 and October 1 of each year
by the Lenders. Indebtedness under the Bank 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
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<PAGE>
capital stock of all subsidiaries of the Company is pledged pursuant to the Bank
Facility. Each of the Company's wholly owned subsidiaries guarantees the Bank
Facility.
Under the terms of the Bank Facility, the Company must maintain a ratio of
EBITDA to consolidated interest expense of not less than 2.0 to 1 at December
31, 1998 (2.5 to 1 thereafter). In addition, the Company must also maintain
current assets, including availability under the line at that time, of not less
than current liabilities. The Bank Facility 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. At December 31, 1998, the Company had not satisfied all of the covenants
required under the Bank Facility. The Company has obtained waivers and amended
the agreement to eliminate the default. However, the Company has classified this
debt as a current liability since it is probable the Company will fail to meet
these covenants at measurement dates prior to December 31, 1999.
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.
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. The substantial amount of natural gas storage becoming available in the
U.S. is altering this seasonality. During 1994, 1995, 1996 and 1997 the
Company=s natural gas prices averaged $1.88, $1.58, $2.17 and $2.49,
respectively, in each case, per Mcf. 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 1998, natural gas prices received by the Company ranged from a
low of $1.62 to a high of $2.37 per Mcf. The average price received per Mcf for
1998 was $2.05.
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<PAGE>
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
"NGA") and the Natural Gas Policy Act of 1978 (the "NGPA").
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.
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
Astrict 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 ASuperfund@ 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.
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<PAGE>
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 34 full time employees, five of whom are officers. The
Company utilizes an additional 40 contract personnel in the operation of its
properties, and uses numerous outside geologists, production engineers,
reservoir engineers, geophysicists and other professionals on a consulting
basis.
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 incurred a significant loss in 1998, and is significantly
leveraged, with outstanding long-term indebtedness of $115.7 million and
stockholders' equity of $7.9 million as of December 31, 1998. 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 Bank 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 Bank 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.
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<PAGE>
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 Bank 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 had $25.0 million in borrowing base at April 1, 1999 under the
Borrowing Base of the Bank Facility. If oil or natural gas prices decline below
their current levels, the availability of funds under the Bank Facility could be
materially adversely affected.
The Bank 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 Bank 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 Bank Facility and demand immediate
repayment thereof. See "Bank Facility." At December 31, 1998, the Company had
not satisfied all of the covenants required of the Bank Facility. The Company
has obtained waivers and amended the Bank Facility to eliminate the covenant
deficiency. See "Bank Facility" and "Management's Discussion and Analysis of
Financial Conditions and Results of Operations."
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."
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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, 1998 is based on prices of $2.05 per MMbtu of natural
gas and $10.00 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 Securities and Exchange 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."
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 BP and Amoco Acquisitions. 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, 1998, one purchaser accounted for approximately 42% of the
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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 on an annualized basis. 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.
AbandonmentCosts
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, 1998, total abandonment
costs for the Company's offshore properties estimated to be incurred through
2014 were approximately $17.4 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."
-15-
<PAGE>
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."
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.
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 six acquisitions of producing properties
for a total of $106.4 million, which properties had Proved Reserves of
approximately 159 Bcfe as of their respective acquisition dates. As of December
31, 1998, the Company had Proved Reserves of 126 Bcfe with a SEC PV-10 of $94.6
million. Approximately 75% of the Company=s total SEC PV-10 are classified as
Proved Developed Reserves and approximately 65% 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 282 oil wells and 362
natural gas wells. The Company owns interests in 23 federal blocks in the Gulf
of Mexico and nine state water blocks and operates 63% of the 171 offshore
wells, based upon the SEC PV-10 value as of December 31, 1998. 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 450 onshore wells account for 10.8% of the Company's total SEC
PV-10 value as of December 31, 1998. The Company operates 65% of the onshore
wells, based upon such SEC PV-10 value. The Company also owns interests in 23
offshore production platforms and 109 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, 1998. These properties
represent 79% of the aggregate SEC PV-10 value of the Company.
<TABLE>
<CAPTION>
Total Proved % of
Working Reserves SEC PV-10 Total SEC
Field Interests Wells Operator MBbls Bcf Value(000s) PV-10
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
East Breaks 165 75 - 100% 18 PANACO 3,321 21.3 $ 21,044 22%
Umbrella Point 80-100% 20 PANACO 1,783 16.0 20,480 22%
East Breaks 160 33.3% 16 Unocal 992 9.7 13,582 14%
High Island 309 50% 18 Coastal 115 9.8 13,001 14%
West Delta 100% 35 PANACO 271 6.1 6,860 7%
- ---------------------------------------------------------------------------------------------------
Total 107 6,482 62.9 $ 74,967 79%
</TABLE>
East Breaks 165
For information regarding the East Breaks 165 field, see "Business Strategy
- - BP Acquisition."
-16-
<PAGE>
Umbrella Point
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.
East Breaks 160
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 Vastar 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.
High Island 309
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 and 1998. The Company has drilled new wells, sidetracked
existing wells into new formations and recompleted existing wells in new
formations. The field is currently producing 30 MMcf per day of natural gas and
15 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.
West Delta
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.
These Fields were shut in from December 6, 1998 throughout the first quarter due
to a third party pipeline being shut in.
-17-
<PAGE>
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 16,800'. 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.
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 16,800'. Production commenced in
April, 1995. The Company has a 15% overriding royalty interest in that acreage.
The well is currently producing 9,000 Mcf per day and 150 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 7,000 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 $4.1 million plugging and abandonment
bond collateralized in part with a bank escrow account. See "The Company -
Plugging and Abandonment Escrows."
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.
-18-
<PAGE>
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 initial
12.5% working interest from Amoco in 1996 and additional 25% from another owner
in 1998. 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 4.1 MMcf and 60
barrels of condensate per day.
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.
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.
-19-
<PAGE>
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. 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, 1998 were prepared by
independent petroleum engineers, Ryder Scott Company, Netherland, Sewell &
Associates, Inc., W.D Von Gonten & Co. and McCune Engineering, P.E. See "Risk
Factors - Uncertainty of Estimates of Reserves and Future Net Cash Flows" and
"Finding and Acquiring Additional Reserves; Depletion."
<TABLE>
Proved Reserves (a)
<CAPTION>
The following table sets forth information as of December 31, 1998 as to
the estimated Proved Reserves attributable to the Company's properties.
Oil and liquids (Bbl): Pro Forma (b)
<S> <C> <C>
Proved Developed Reserves...................................5,165,328 5,223,359
Proved Undeveloped Reserves.................................2,288,917 2,629,180
---------- ----------
Total Proved Reserves..............................7,454,245 7,852,539
Natural gas (Mcf):
Proved Developed Reserves .............................50,538,718 50,844,718
Proved Undeveloped Reserves............................30,709,981 32,834,981
Total Proved Reserves.............................81,248,699 83,679,699
_____________
(a) Calculated by the Company in accordance with the rules and regulations
of the SEC, based upon December 31, 1998 prices of $10.00 per Bbl of
oil and $2.05 per MMbtu 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.
(b) Includes reserve amounts for acquisitions that were in progress at
December 31, 1998.
</TABLE>
<TABLE>
Estimated Future Net Revenues
from Proved Reserves (a)
<CAPTION>
The following table sets forth information as of December 31, 1998 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 Pro Forma(b) Reserves Pro Forma(b)
--------- --------- -------- ---------
<S> <C> <C> <C> <C>
Estimated Future net revenues (c):.............$86,547,916 $87,344,716 $129,326,942 $133,363,339
Present value (10%) of estimated future net
revenues (SEC PV-10)..........................$71,186,819 $71,692,758 $94,580,281 $97,156,670
_______________
(a) Calculated by the Company in accordance with the rules and regulations of
the SEC, based upon December 31, 1998 prices of $10.00 per Bbl of oil and
$2.05 per MMbtu 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) Includes amounts for acquisitions that were in progress at December 31,
1998.
(c) 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.
-20-
<PAGE>
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,
1998, 1997 and 1996.
For the year ended December 31,
---------------------------------------------------------
1996(a) 1997 1998
Oil and Condensate:
Net Production (Bbls)(b) 276,000 515,000 895,000
Revenue $ 5,356,000 $ 9,354,000 $ 10,916,000
Hedge gains (losses) $ -- $ (67,000) $ 2,034,000
Average net Bbl per day 756 1,411 2,452
Average price per Bbl before hedges $ 19.42 $ 18.17 $ 12.20
Average price per Bbl including hedges $ 19.42 $ 18.04 $ 14.47
Natural Gas:
Net Production (Mcf)(b) 6,788,000 11,468,000 18,041,000
Revenue $ 18,653,000 $ 29,751,000 $ 36,910,000
Hedge gains (losses) $ (3,946,000) $ (1,197,000) $ 431,000
Average net Mcf per day 18,600 31,400 49,400
Average price per Mcf before hedges $ 2.74 $ 2.59 $ 2.05
Average price per Mcf including hedges $ 2.17 $ 2.49 $ 2.07
Total Revenues $ 20,063,000 $ 37,841,000 $ 50,291,000
Production Cost:
Production cost $ 8,186,000 $ 11,150,000 $ 18,148,000
Mcfe(c) 8,444,000 14,557,000 23,411,000
Production cost per Mcfe(c) $ .97 $ .77 $ .78
______________
(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.
</TABLE>
-21-
<PAGE>
<TABLE>
Productive Wells (a)
<CAPTION>
The following table sets forth the number of productive oil and natural gas
wells, as of December 31, 1998, attributable to the Company's properties.
Productive Wells Company Operated
---------------- ----------------
<S> <C> <C>
Gross productive offshore wells (b):
Oil ..................................... 73 47
Natural Gas .............................. 121 46
--- ---
Total ................................ 194 93
Net productive offshore wells (c):
Oil ..................................... 53 47
Natural Gas .............................. 60 42
--- ---
Total ................................ 113 89
Gross productive onshore wells (b):
Oil ..................................... 209 65
Natural Gas .............................. 241 15
--- ---
Total ................................ 450 80
Net productive onshore wells (c):
Oil ..................................... 70 58
Natural Gas .............................. 13 8
--- ---
Total ................................ 83 66
__________
(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,
1998, attributable to the Company's properties.
Developed onshore acreage (a):
Gross acres (b).......................................................... 83,393
Net acres (c)............................................................ 6,734
Undeveloped onshore acreage (a):
Gross acres (b).......................................................... 8,787
Net acres (c)............................................................ 3,229
Developed offshore acreage (a):
Gross acres (b).......................................................... 127,935
Net acres (c)............................................................ 47,926
Undeveloped offshore acreage (a)(d):
Gross acres (b).......................................................... 82,380
Net acres (c)............................................................ 10,721
__________
(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.
</TABLE>
-22-
<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, 1998. 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.
<TABLE>
<CAPTION>
Developmental Wells Exploratory Wells
Completed Dry Completed Dry
Oil Gas Oil Gas Oil Gas Oil Gas
------------------------- -----------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1994 5 4 -- -- -- 1 -- --
1995 -- -- -- -- -- -- -- 3
1996 -- -- 2 -- -- -- -- --
1997 6 13 -- 1 -- -- -- --
1998 1 9 -- -- -- 3 -- 6
Total 12 26 2 1 -- 4 -- 9
</TABLE>
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.
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.
An action was filed against the Company, Exxon Pipeline Company ("Exxon"),
National Energy Group, Inc. ("NEG"), Mendoza Marine, Inc., Shell Western
Exploration & Production, Inc. ("Shell"), and the Louisiana Department of
Transportation and Development. The petition was filed in August 1998, and
alleges that, in 1997 and perhaps earlier, leaks from a buried crude oil
pipeline contaminated the plaintiffs' property.
Pursuant to the purchase and sale agreement between the Company and NEG,
NEG is required to indemnify the Company from any damages attributable to NEG's
operations on the property after the sale. However, NEG is in Chapter 11
bankruptcy proceedings, and so any action by the Company to assert its indemnity
rights against NEG is currently stayed. Counsel for the Company have prepared
and may file a motion to lift the stay so that the Company may assert its
indemnification rights against NEG. But even if the Company is successful in
proving its right to indemnity, NEG's judgmentworthiness is questionable because
of the bankruptcy.
Pursuant to another purchase and sale agreement, the Company may owe
indemnity to Shell and Exxon, from which it had acquired the property prior to
selling same to NEG. The Company may have insurance coverage for the claims
-23-
<PAGE>
asserted in the petition, and has notified or is in the process of notifying all
insurance carriers that might provide coverage under their policies. Some
discovery has occurred in the case, but discovery is not yet complete.
Therefore, at this point it is not possible to evaluate the likelihood of an
unfavorable outcome, or to estimate the amount or range of potential loss.
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 23,985,927 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 1998 the Company issued 52,793 Common Shares to directors as
compensation for services on the board. The exemption from registration relied
upon was that of Section 4(2) of the Securities Act of 1933.
Warrants and Options
- --------------------
The Company has outstanding options to acquire 1,150,000 Common Shares at a
price of $4.45 per share, expiring June 20, 2000. These options are all held by
current and former 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.
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
-24-
<PAGE>
rights, dividend rates, liquidation and other rights preferences, and
limitations that the Board of Directors fixes without any shareholder approval.
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 and low closing prices for the
Common Shares.
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
1998
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
- ----------- ----------- ----------- -----------
High $ 4 1/2 $ 4 5/8 $ 3 7/8 $ 2
Low $ 3 1/2 $ 3 7/8 $ 1 11/16 $ 13/16
On March 31, 1999, the last sale price of the Common Shares as reported on
the NASDAQ was $.94 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 Bank 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.
Certain Anti-takeover Provisions
- --------------------------------
In September 1998, the Board elected to redeem the Company's Preferred
Share Purchase Right at its stated value of $.005 per Common Share.
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
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<PAGE>
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.
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
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<PAGE>
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. In connection with a private sale of Common Shares in 1999, the
Board elected to waive the Delaware Anti-takeover statute.
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 Bank 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. The Senior Notes would become due upon an increase
in ownership of Common Shares outstanding to over 20% of the then outstanding
Common Shares.
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<PAGE>
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, 1998 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.
<TABLE>
<CAPTION>
For the year ended December 31,
1994 1995 1996 1997 1998
----------------------------------------------------------
Summary of Operating Data: (dollars in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Oil and natural gas sales $ 17,338 $ 18,447 $ 20,063 $ 37,841 $ 50,291
Lease operating expense 5,231 8,055 8,186 11,150 18,148
Depreciation, depletion &
amortization expense 6,038 8,064 9,022 18,866 37,500
General and administrative expense 587 690 1,063 1,919 4,629
Production and ad valorem taxes 1,006 1,078 559 721 1,351
Exploratory dry hole expense -- 8,112 -- 67 5,655
Geological and geophysical expense -- -- -- 286 1,927
Impairment of oil and gas properties 1,202 751 -- -- 20,406
Office consolidation and severance
expense -- -- -- -- 987
West Delta fire loss -- -- 500 -- --
-------- --------- --------- --------- --------
$ 3,274 $ (8,303) $ 733 $ 4,832 $(40,312)
Interest expense (net) 1,623 987 2,514 3,930 9,639
Gain (loss) on investment in
Common stock -- -- (258) 75 --
Income taxes (benefit) -- -- -- -- (3,100)
Extraordinary item- loss on early
retirement of debt (536) -- -- (934) --
-------- -------- --------- --------- --------
Net income (loss) $ 1,115 $ (9,290) $ (2,039) $ 43 $(46,851)
======== ======== ========= ========= ========
Net income (loss) per Common Share $ 0.11 $ (0.81) $ (0.16) $ -- $ (1.96)
Summary Balance Sheet Data:
Oil and gas properties (net) $ 23,945 $ 29,485 $ 50,540 $ 112,548 $100,723
Total assets 29,095 36,169 73,768 179,629 143,372
Long-term debt 12,500 22,390 49,500 101,700 115,749
Stockholders' equity 14,882 9,174 17,498 55,188 7,902
Dividends per Common Share
</TABLE>
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.
Several material acquisitions and one material disposition took place
during the five years ended December 31, 1998, see "Business-Strategic
Acquisitions and Mergers." In July 1995 the Company purchased interests in six
offshore blocks from Zapata Exploration Corp. for $2.7 million in cash and a
production payment to Zapata based on future production. In December 1995 the
Company purchased the Bayou Sorrel Field from Shell Western E & P Inc. for a net
purchase price of $9.7 million in cash. This was primarily an oil property,
which was subsequently sold effective September 1, 1996 for $11 million. In
October 1996 the Company acquired interests in six offshore fields from Amoco
Production Company for $32 million in cash and 2 million newly issued Common
Shares. In July 1997 the Company acquired the Goldking Companies, Inc. for $27.5
million in consideration plus the assumption of liabilities. In May 1998 the
Company acquired interests in three offshore fields from BP Exploration & Oil,
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<PAGE>
Inc. for $19.6 million in cash. All of these acquisitions were accounted for
using the purchase method. This information is also included in and should be
read in conjunction with the Company's Consolidated Financial Statements and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
- -------------------------------------------------------------------------------
General
- -------
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.
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.
Year 2000 Issue
- ---------------
The various problems that may result from the use of date codes in software
and other machinery is referred to as the "Year 2000 Issue." The once common
practice of using a two-digit identifier for the year in a date may cause a
program or system to become faulty or inoperative on or prior to January 1,
2000. This document serves as an informational disclosure regarding the Y2K
assessment activities for PANACO, Inc. and its subsidiaries (collectively
"PANACO") under the Year 2000 Information and Readiness Disclosure Act of 1998.
PANACO established a program during 1998 to ensure that, to the extent
reasonably possible, all systems are or will be Year 2000 ready prior to the end
of 1999. The Year 2000 Program ("Y2K Program"), designed with the assistance of
an outside consultant, consists of five phases: (a) Assessment -which includes
compiling an inventory of PANACO's assets, including significant third-party
supplier and customer relationships, (b) Repair/Upgrade/Replace -including an
analysis of the assets to determine compliance or non-compliance and repairing,
upgrading or replacing those that are non-compliant, (c) Compliance Testing, (d)
Contingency Planning, and (e) Roll-over Planning.
A team consisting of PANACO managers from Information Technology, Finance
and Operations has been established as the Year 2000 Compliance Project Team.
With the assistance of its outside consultant, the Team has designed an
aggressive schedule to identify information technology ("IT") and non-IT assets
requiring readiness upgrades, and a timetable for performance and testing of the
affected systems. In addition, the Y2K Program calls for validation of
compliance by significant PANACO suppliers and customers.
Once identified, detailed remediation steps will be scheduled to ensure
that internal systems and significant external suppliers and customers meet Y2K
compatibility requirements, or that sufficient contingency plans are in place.
Current Status
As of April 1999, PANACO's Year 2000 assessment is not complete. An
inventory of computing, communications and facility systems has been prepared
and validated. Significant third-party suppliers and customers have also been
identified for validation.
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<PAGE>
PANACO has substantially completed the inventory for both its IT and non-IT
systems and expects to complete the assessment phase for these systems on or
prior to July 2, 1999. The Y2K Program calls for the completion of all phases
for both IT and non-IT systems by year-end 1999.
PANACO is performing a review of significant third party suppliers and
customers and, where available, is surveying the public Year 2000 statements
issued by them. Additionally, PANACO has sent questionnaires to certain third
party suppliers and customers requesting information regarding their
vulnerability to Year 2000 issues. PANACO intends to pursue appropriate
responses to these inquiries and evaluate the responses it receives to determine
if alternate business actions will be necessary. PANACO expects to complete the
third party assessment phase by July 2, 1999, at which time contingency plans
will be developed.
Costs
The estimated total costs for Y2K readiness has been nominal. It is
anticipated that such costs for complete Y2K readiness will continue to be
nominal. In addition, there have been no material capital expenditures for Y2K
and there is not anticipated to be material capital expenditures, as it is
believed at this point that most major critical field operations do not have
date sensitive equipment. The company does not separately track the internal
costs incurred for the Y2K project as such costs are principally the related
payroll costs for its information systems group. Remediation and testing is
scheduled to be completed during the 3rd quarter of 1999.
Contingency Plans
Should any systems, customers or significant suppliers be determined to
have questionable remediation potential, the Year 2000 Compliance Project Team
will establish a contingency plan to address the at-risk area. This will be
decided during the analysis phase of the overall project now underway. PANACO is
unable at this time to determine what contingency plans, if any, should be
implemented. As PANACO progresses through the Y2K Program and identifies
specific risk areas, it intends to timely implement appropriate remedial actions
and contingency plans.
Risks
The failure to correct a Year 2000 problem could result in the interruption
or failure of certain normal business activities or operations. PANACO believes
that the greatest risks lie in its (a) financial systems applications, (b)
embedded chips in field equipment, (c) and third parties. A significant Year
2000-related disruption in these systems could disrupt financial and accounting
functions, crude oil and natural gas production, transportation, and marketing
activities. This disruption could have a material adverse effect on the
Company's operating results and liquidity.
PANACO is not presently aware of any vendor related Year 2000 issue that is
likely to result in any disruption of this type. Although there is inherent
uncertainty in the Year 2000 issue, PANACO expects that as it progresses in its
Y2K Program, the level of uncertainty about the impact of the Year 2000 issue
will be reduced significantly.
Conclusion and Disclaimers
These estimates and conclusions contain forward-looking statements and are
based on management's best estimates of future events. PANACO's expectations
about risks, future costs, and the timely completion of its Year 2000
remediation are subject to uncertainties that could cause actual results to
differ materially from the statements made in this readiness disclosure.
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<PAGE>
Liquidity and Capital Resources
- -------------------------------
The Company currently has a $17 million capital budget for 1999, which is
subject to change upon review by management and the board of directors. The
Company anticipated funding this capital budget through cash flows and
borrowings under its line of credit. In conjunction with an amendment to the
loan agreement, on April 13, 1999 the borrowing base under the line of credit
was reduced to $25 million, see "Bank Facility." The amendment provides for 4
million reductions in this borrowing base on June 30, 1999 and September 30,
1999. With these reductions in the borrowing base, and the amount outstanding on
April 16, 1999 of $24 million, the Company will be required to reduce its 1999
capital budget to $11.5 million, which it currently has committed to spend.
These assumptions do not include any external sources of financing or
redeterminations of its borrowing base. The line of credit permits the Company
to request such a redetermination from the bank.
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 million from the offering were used to prepay
$13.5 million of its 12% subordinated debt and the remainder was used to reduce
borrowings under the Company's bank facility.
On October 9, 1997, the Company issued $100 million principal amount of 10
5/8% 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 used for capital expenditures and the BP Acquisition.
Bank Facility
In December 1998, the Company amended its bank facility. See "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, 1998 was $45 million, with
availability under the revolver of $31.5 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. At April 1, 1999 the
borrowing base was reduced to $25 million. The borrowing base is subject to $4
million reductions on June 30, 1999 and September 30, 1999. The balance
outstanding under the Bank Facility at April 15, 1999 was $24 million. Interest
on the loan is computed at the bank's prime rate or at 1.5 to 2.25% (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, and sale of assets. At December 31, 1998
the Company was not in compliance with these covenants which has been remedied
by waivers and an amendment to the Bank Facility. However, the Company has
classified this debt as a current liability since it is probable the Company
will fail to meet these covenants at measurement dates prior to December 31,
1999. The failure to satify these covenants, or any of the other covenants in
the Bank Facility would constitute an event of default thereunder and, subject
to grace periods, may permit the lenders to accelerate the indebtedness
oustanding under the Bank Facility and demand immediate payment thereof. In such
event, the Company could be required to sell certain oil and gas assets, sell
equity securities or obtain additional bank financing. No assurance can be given
that such transactions can be consummated on terms acceptable to the Company or
its lenders, whose approval may be required. In this situation, if the Company
is unable to raise the necessary funds, the Company could become in default on
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<PAGE>
the full amount of its indebtedness, which includes the Senior Notes. The
holders of the Senior Notes have acceleration rights, subject to certain grace
periods, if the Company is in default under the Bank Facility.
In 1998 the Board approved a program to repurchase up to 500,000 Common
Shares. The Board also authorized the redemption of the Shareholder Rights Plan
at the stated value of $.005 per share. In September, October and November the
Company purchased 304,650 shares of common stock for a total of $592,000. The
cost of redeeming the Shareholders Rights Plan totaled $118,000.
At December 31, 1998, 86% of the Company's total assets were represented by
oil and natural gas properties, pipelines and equipment, net of depreciation,
depletion and amortization.
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 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, from 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 $2.4 million. In connection with
the BP Acquisition, the Company deposited $1.0 million into an escrow account on
July 1, 1998. On the first day of each quarter thereafter, the Company will
deposit $250,000 into the escrow account until the balance in the escrow account
reaches $6.5 million.
In 1998, the Company spent $61.8 million in cash for capital expenditures,
approximately $19.6 million of which was for the BP Acquisition and the
remainder was for development of its oil and natural gas properties and
participation in exploration projects.
Results of Operations
- ---------------------
For the years ended December 31, 1998 and 1997:
The decreases in oil and natural gas prices realized by the Company in
1998, as discussed below, in combination with other key factors led to the
significant loss in 1998. Price declines led to a $20.4 million impairment of
its oil and gas properties based on estimated recoverability of the book value
of those assets. A substantial increase in non drilling exploration expenses and
exploratory dry hole expense, along with the closing of the Company's Kansas
City, Missouri office and the related severance expense also contributed to the
net loss for the year.
Production. Natural gas production increased 57%, to 18,041,000 Mcf in
1998, from 11,468,000 Mcf in 1997. The BP Acquisition in May 1998, the Goldking
Acquisition in July 1997 and successful developmental drilling programs in 1997
and 1998 were the primary factors in the increased production. The Goldking
Acquisition and several wells completed on those properties during 1998
accounted for an increase of 4,844,000 Mcf. Successful developmental drilling in
the High Island 309 and 310 Fields accounted for an increase in production of
2,537,000 Mcf, while a successful developmental well and the acquisition of a
co-owner's working interest in the West Cameron 144 Field accounted for an
increase of 600,000 Mcf.
Oil production increased 74% in 1998 to 895,000 barrels, from 515,000
barrels in 1997. The primary factors in the increased oil production were the
acquisition of the East Breaks 165 Field in May 1998 and a successful
developmental well completed in the Umbrella Point Field in January 1998.
Prices. Average natural gas prices, net of the impacts of hedging
transactions, decreased 17% in 1998, from $2.49 per Mcf in 1997 to $2.07 in
1998. The 1998 natural gas hedge program had the effect of increasing the
natural gas price realized by $0.02 per Mcf in 1998 and decreasing it by $0.10
per Mcf in 1997. The Company had natural gas hedged in quantities ranging from
10,000 to 50,000 MMbtu per day in each month in 1998 for a total of 11,980,000
MMbtu, at pipeline prices averaging approximately $2.05 per MMbtu, for a NYMEX
equivalent of approximately $2.20 per MMbtu.
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<PAGE>
Average oil prices, net of the impacts of hedging transactions, decreased
20%, to $14.47 per barrel, from $18.04 per barrel in 1997. The 1998 oil hedge
program had the effect of increasing the average net oil price realized by $2.27
per barrel. The Company hedged its oil prices on 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. Depressed commodity prices will continue
to have a negative impact on the Company's results of operations.
"Oil and natural gas sales" increased 33% in 1998 despite the 20% decrease
in oil prices and 17% decrease in natural gas prices. Increases in natural gas
and oil production brought about the increase in oil and natural gas sales.
During August and September, the Company was required for safety reasons to shut
in at least a portion of its production facilities due to severe weather on four
separate occasions. The increased production in 1998, as discussed above, would
have been greater had the storms in the Gulf of Mexico in August and September
not occurred.
"Lease operating expense" increased $7.0 million primarily due to the BP
and Goldking Acquisitions, these expenses increased to $0.78 per Mcfe, from
$0.77 per Mcfe in 1997.
"Depletion, depreciation and amortization" increased $18.6 million
primarily due to the increase in 1998 production as discussed above. The amount
per Mcfe also increased from $1.30 in 1997 to $1.60 in 1998. The increase in the
amount per Mcfe was in part due to the decline in reserve value of several
small, non-operated oil properties. The magnitude of depletion is also impacted
by the relatively short lives of the Company's proved reserves. Currently, the
average life of the Company's proved reserves is approximately five and one-half
years.
"General and administrative expense" increased $2.7 million in 1998 due to
acquisitions made by the Company in July 1997, April 1998 and May 1998. The
Company increased its allowance for doubtful accounts by $1 million in 1998
which also accounted for a large percentage of the increase.
"Production and ad valorem taxes" increased $630,000 in 1998, to 3% of oil
and natural gas sales, from 2% in 1997. The increase is due to production from
properties subject to state taxes which were acquired in July 1997.
"Exploratory dry hole expense" reflects the Company's increased exploratory
activities in 1998. Of the 19 wells the Company drilled or participated in
during 1998, six of the exploratory wells were not commercially productive. Two
of the wells were spudded and completed during the first quarter of 1998, three
others reached total depth during the second quarter and the final one reached
total depth during the third quarter. The wells were operated by third parties
and the Company owned working interests ranging from 10 to 20%.
"Geological and geophysical expense" during 1998 resulted from the
Company's non-drilling exploratory activities.
"Impairment of oil and gas properties" represents an impairment of the book
value of the Company's oil and gas properties based on estimated future net cash
flows from those properties. The impairment was primarily due to much lower
estimates of oil and natural gas prices at December 31, 1998. The impairment
tests were based upon future cash flows using an initial price of $11.50 per
barrel of oil and $1.90 per MMbtu of natural gas, each moderately escalated
thereafter. Costs and expenses were also escalated at 3%.
"Office consolidation and severance expense" was a non-recurring charge for
the costs associated with closing the Company's Kansas City, Missouri office.
The charge includes costs for the relocation of personnel and equipment to its
Houston, Texas office and severance costs for several former employees.
"Interest expense (net)" increased $5.8 million in 1998 primarily due to
increased borrowing levels. The increase in borrowing is due to the Company's
Senior Note offering completed in October 1997. The increase is somewhat offset
by a reduced interest rate on a majority of the Company's long term debt. In
connection with the offering, the Company prepaid or repaid long term debt, a
significant amount of which had rates in excess of the 10 5/8% rate on the
Notes. This included amounts borrowed in connection with the Amoco Acquisition
in October 1996 and debt assumed in connection with the Goldking Acquisition in
July 1997.
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<PAGE>
Results of Operations
- ---------------------
For the years ended December 31, 1997 and 1996:
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 million.
The Company spent $8.5 million on Tank Battery #3 inclusive of the $500,000
expensed during 1996 and has received reimbursement from its insurance company
of $3.9 million, 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.
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.
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 $9.8 million,
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, $4.0 million 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 $3.0 million, or 36% 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 29% in 1997 from 41% 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
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<PAGE>
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 $856,000 primarily as a
result of the Goldking Acquisition. As a percentage of oil and natural gas
sales, general and administrative expenses remained flat at 5%.
"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 million 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. 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 agreements in 1998 provided a minimum price of
$1.84 on volumes ranging from 10,000 MMbtu to 50,000 MMbtu per day of natural
gas. A gain of $431,000 was realized on this hedge in 1998.
The oil hedge agreement in 1998 provided the Company with an average of
$19.06 on 1,268 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 $19.28 on 500 of those barrels per day. A gain of
$2.0 million was realized on these hedges in 1998.
The Company currently has hedge agreements involving the following
provisions for the periods shown:
OIL
------------------------------------------------
Average
Notional Quantity Fixed Price Market
Period Per day (Bbls) (Bbl) Price
------- ---------------- ----------- -----
1999 223 $17.27 NYMEX
2000 232 $17.35 NYMEX
NATURAL GAS
------------------------------------------------
Average
Notional Quantity Fixed Price Market
Period Per day (MMbtu) (MMbtu) Price
------- ---------------- ----------- -----
1999 7,260 $ 1.89 Pipeline
Prices
1999 (April to Pipeline
September) 20,000 $ 2.06 Prices
2000 218 $ 1.87 Pipeline
Prices
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
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<PAGE>
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 1999 is equal to approximately 7% and 41%,
respectively, of its anticipated 1999 production based upon the year end reserve
reports. At December 31, 1998, the estimated fair market value of the hedge
agreements in place at that time was a gain of $1.8 million. A 10% increase in
the underlying commodity prices would result in a $1.4 million reduction in the
fair value of these agreements.
At December 31, 1998 the Company had $100 million in Senior Notes
outstanding with a fixed interest rate of 10 5/8%. The fair value of the Notes,
based on quoted market prices at December 31, 1998, was $78 million. The Company
had $13.5 million outstanding under its Bank Facility at December 31, 1998. The
Bank Facility is a floating rate facility, with a fair value of $13.5 million.
The Company does not have any interest rate hedge agreements at December 31,
1998.
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.
- -----------------------------------------------------------------------
On June 11, 1998, Arthur Andersen LLP informed the Company that it had
declined to stand for reelection as independent auditors of the Company at its
1998 annual meeting. The board of directors, upon recommendation from its Audit
Committee, engaged KPMG LLP as the Company's new independent accountant to audit
the financial statements for the year ended December 31, 1998. During the two
most recent fiscal years and through the date of this report, the Company has
had no disagreements with Arthur Andersen LLP on any matter of accounting
principles or practices, financial statement disclosure or auditing scope or
procedure, which disagreement(s), if not resolved would caused them to make
reference thereto in their report on the consolidated financial statement of the
Company for such years.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
- -----------------------------------------------------------
The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
- -------------------------------
The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
- -----------------------------------------------------------------------
The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
- -------------------------------------------------------
The information required by this item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.
-36-
<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 23, 1998 Change in Registrant's Certifying Accountant
(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.
10.14 Purchase 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.
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<PAGE>
10.17 Purchase 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.
10.17.1 Restated 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.
10.17 Form 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.
10.22****Third Amendment to Amended and Restated Credit Agreement
dated April 13, 1999.
10.23****Employment contract between the Company and Larry M. Wright.
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.
****Filed herewith.
(d) Financial Statement Schedules. See Index to Financial Statements,
Page F-1.
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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 Aslice@ 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.
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<PAGE>
Mcfe/d. Mcfe per day.
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.
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<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,
1998, 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, 1998, 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.
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<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\ Larry M. Wright April 22, 1999
------------------- --------------
Larry M. Wright, 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\ Larry M. Wright April 22, 1999
------------------- --------------
Larry M. Wright,
Chief Executive Officer and
Director
By: \s\Todd R. Bart April 22, 1999
--------------- --------------
Todd R. Bart
Chief Financial Officer
By: \s\Mark C. Barrett April 22, 1999
------------------ --------------
Mark C. Barrett, Director
By: \s\Donald Chesser April 22, 1999
----------------- --------------
Donald Chesser, Director
By: \s\Harold First April 22, 1999
--------------- --------------
Harold First, Director
By: \s\James B. Kreamer April 22, 1999
------------------- --------------
James B. Kreamer, Director
By: __________________
Richard Lampen, Director
By: __________________
Felix Pardo, Director
By: __________________
Michael Springs, Director
By: __________________
A. Theodore Stautberg, Director
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<PAGE>
Exhibit 21.1
Subsidiaries of PANACO, Inc.
State of
Incorporation
-------------
Goldking Acquisition Corp. Delaware
PANACO Production Company, Inc. Texas
<PAGE>
<PAGE>
PANACO, Inc.
INDEX TO FINANCIAL STATEMENTS
PANACO, Inc. - AUDITED FINANCIAL STATEMENTS Page Number
- ------------------------------------------- -----------
Independent Auditors' Report F-2
Report of Independent Public Accountants F-3
Consolidated Balance Sheets, December 31, 1998 and 1997 F-4
Consolidated Statements of Income (Operations) for the Years Ended
December 31, 1998, 1997 and 1996 F-6
Consolidated Statements of Changes in Stockholders' Equity
for the Years Ended December 31, 1998, 1997 and 1996 F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996 F-8
Notes to Consolidated Financial Statements for the Years Ended
December 31, 1998, 1997 and 1996 F-10
<PAGE>
Independent Auditors' Report
The Board of Directors and Shareholders
PANACO, Inc.
We have audited the accompanying consolidated balance sheet of PANACO, Inc. and
subsidiaries as of December 31, 1998, and the related consolidated statements of
income (operations), changes in stockholders' equity, and cash flows for the
year then ended. These consolidated financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these consolidated financial statements based on our audit.
We conducted our audit 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 audit provides 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, 1998, and the results of its operations and its
cash flows for the year then ended in conformity with generally accepted
accounting principles.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 5 to the
financial statements, the Company's substantial indebtedness, restrictive
covenant requirements and working capital deficit raise substantial doubt about
its ability to continue as a going concern. Management's plans in regard to
these matters are also described in Note 5. The financial statements do not
include any adjustments that might result from the outcome of this uncertainty.
KPMG LLP
Houston, Texas
April 22, 1999
F-2
<PAGE>
Report of Independent Public Accountants
To the Stockholders and Board of Directors of PANACO, Inc.:
We have audited the accompanying consolidated balance sheet of PANACO, Inc. (a
Delaware Corporation) and subsidiaries as of December 31, 1997 and the related
consolidated statements of income (operations), changes in stockholders' equity
and cash flows for the years ended December 31, 1997 and 1996. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 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 the results of their operations and
their cash flows for the years ended December 31, 1997 and 1996 in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Kansas City, Missouri
April 7, 1998
F-3
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED BALANCE SHEETS
<CAPTION>
ASSETS
------
December 31,
-----------
1998 1997
---- ----
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 3,452,000 $ 36,909,000
Accounts receivable 8,332,000 9,735,000
Accounts receivable-employee 18,000 --
Prepaid and other 268,000 626,000
-------------- --------------
Total current assets 12,070,000 47,270,000
-------------- --------------
OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
Oil and gas properties, proved 238,377,000 198,840,000
Oil and gas properties, unproved 15,128,000 12,947,000
Less accumulated depreciation, depletion and amortization (152,782,000) (99,239,000)
-------------- --------------
Net oil and gas properties 100,723,000 112,548,000
PIPELINES AND EQUIPMENT
Pipelines and equipment 26,252,000 14,875,000
Less accumulated depreciation (3,415,000) (1,416,000)
-------------- --------------
Net pipelines and equipment 22,837,000 13,459,000
OTHER ASSETS
Deferred debt costs, net 3,359,000 3,813,000
Restricted deposits 3,719,000 2,256,000
Employee note receivable 300,000 --
Other 364,000 283,000
-------------- --------------
Total other assets 7,742,000 6,352,000
-------------- --------------
TOTAL ASSETS $ 143,372,000 $ 179,629,000
============== ==============
See accompanying notes to consolidated financial statements.
</TABLE>
F-4
<PAGE>
<TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<CAPTION>
December 31,
-----------
1998 1997
-------------- --------------
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable $ 16,976,000 $ 17,225,000
Interest payable 2,745,000 2,416,000
Revolving credit facility 13,500,000 --
-------------- --------------
Total current liabilities 33,221,000 19,641,000
-------------- --------------
LONG-TERM DEBT 102,249,000 101,700,000
DEFERRED INCOME TAXES -- 3,100,000
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;
23,704,955 and 23,913,531 shares
issued and outstanding, respectively 240,000 239,000
Additional paid-in capital 69,197,000 69,041,000
Treasury stock, held at cost (592,000) --
Retained deficit (60,943,000) (14,092,000)
-------------- --------------
Total Stockholders' Equity 7,902,000 55,188,000
-------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 143,372,000 $ 179,629,000
============== ==============
COMMITMENTS AND CONTINGENCIES
See accompanying notes to consolidated financial statements.
</TABLE>
F-5
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF INCOME (OPERATIONS)
<CAPTION>
Year Ended December 31,
----------------------
1998 1997 1996
---------- ---------- ----------
REVENUES
<S> <C> <C> <C>
Oil and natural gas sales $ 50,291,000 $ 37,841,000 $ 20,063,000
COSTS AND EXPENSES
Lease operating expense 18,148,000 11,150,000 8,186,000
Depreciation, depletion and amortization 37,500,000 18,866,000 9,022,000
General and administrative expense 4,629,000 1,919,000 1,063,000
Production and ad valorem taxes 1,351,000 721,000 559,000
Exploratory dry hole expense 5,655,000 67,000 --
Geological and geophysical expense 1,927,000 286,000 --
Office consolidation and severance expense 987,000 -- --
Impairment of oil and gas properties 20,406,000 -- --
West Delta fire loss -- -- 500,000
-------------- -------------- --------------
Total 90,603,000 33,009,000 19,330,000
-------------- -------------- --------------
OPERATING INCOME (LOSS) (40,312,000) 4,832,000 733,000
-------------- -------------- --------------
OTHER INCOME (EXPENSE)
Gain (loss) on investment in common stock -- 75,000 (258,000)
Interest income 849,000 745,000 29,000
Interest expense (10,488,000) (4,675,000) (2,543,000)
-------------- -------------- --------------
Total (9,639,000) (3,855,000) (2,772,000)
-------------- -------------- --------------
INCOME (LOSS) BEFORE INCOME
TAXES AND EXTRAORDINARY ITEM (49,951,000) 977,000 (2,039,000)
INCOME TAXES (BENEFIT) (3,100,000) -- --
-------------- -------------- --------------
INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM (46,851,000) 977,000 (2,039,000)
EXTRAORDINARY ITEM - Loss on early
retirement of debt -- (934,000) --
-------------- -------------- --------------
NET INCOME (LOSS) $ (46,851,000) $ 43,000 $ (2,039,000)
============== ============== ==============
BASIC AND DILUTED EARNINGS (LOSS)
PER SHARE
Income (loss) before extraordinary item $ (1.96) $ .05 $ (.16)
Extraordinary item -- (.05) --
-------------- -------------- --------------
Net income (loss) $ (1.96) $ -- $ (.16)
============== ============== ==============
BASIC WEIGHTED AVERAGE
SHARES OUTSTANDING 23,884,091 20,781,205 12,742,213
============== ============== ==============
DILUTED WEIGHTED AVERAGE
SHARES OUTSTANDING 23,884,091 21,024,847 12,742,213
============== ============== ==============
See accompanying notes to consolidated financial statements.
</TABLE>
F-6
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
<CAPTION>
Common Additional
Share Paid-In Treasury Retained
Shares Par Value Capital Stock Deficit
------ -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C>
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)
Net loss -- -- -- -- (46,851,000)
Shares issued under Employee
Stock Ownership Plan and
Director stock bonuses 96,074 1,000 274,000 -- --
Shareholder rights redemption -- -- (118,000) -- --
Purchase of treasury stock (304,650) -- -- (592,000) --
------------ ------------ ------------- ------------ -------------
Balances, December 31, 1998 23,704,955 $ 240,000 $ 69,197,000 $ (592,000) $ (60,943,000)
============= ============ ============= ============ =============
See accompanying notes to consolidated financial statements.
</TABLE>
F-7
<PAGE>
<TABLE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (46,851,000) $ 43,000 $ (2,039,000)
Adjustments to reconcile net income (loss) -- -- --
to net cash provided by operating activities:
Extraordinary item -- 934,000 --
Depreciation, depletion and amortization 37,500,000 18,866,000 9,022,000
Impairment of oil and gas properties 20,406,000 -- --
Exploration expenses 5,655,000 67,000 --
Deferred income tax benefit (3,100,000) -- --
Loss (gain) on investment in common stock -- (75,000) 258,000
ESOP stock contribution 275,000 165,000 122,000
Changes in operating assets and liabilities:
Accounts receivable 1,403,000 (969,000) (1,811,000)
Related party note receivable (318,000)
Prepaid and other 572,000 129,000 274,000
Accounts payable (249,000) 4,172,000 1,803,000
Interest payable 329,000 1,822,000 363,000
------------- ------------- -------------
Net cash provided by operating activities 16,198,000 25,154,000 7,992,000
------------- ------------- -------------
CASH FLOWS USED IN INVESTING ACTIVITIES
Proceeds from the sale of oil and gas properties 23,000 87,000 9,017,000
Proceeds from the sale of investment in common stock -- 1,717,000 --
Capital expenditures and acquisitions (61,829,000) (41,997,000) (43,050,000)
Increase in restricted deposits (1,463,000) (141,000) (2,115,000)
Other -- -- 96,000
------------- ------------- -------------
Net cash used in investing activities (63,269,000) (40,334,000) (36,052,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt proceeds 46,049,000 112,459,000 38,514,000
Repayment of long-term debt (32,000,000) (84,742,000) (11,753,000)
Issuance of common shares 275,000 22,636,000 1,837,000
Acquisition of treasury stock (592,000) -- --
Shareholder rights redemption (118,000) -- --
------------- ------------- -------------
Net cash provided by financing activities 13,614,000 50,353,000 28,598,000
------------- ------------- -------------
NET INCREASE (DECREASE) IN CASH (33,457,000) 35,173,000 538,000
CASH AT BEGINNING OF YEAR 36,909,000 1,736,000 1,198,000
------------- ------------- -------------
CASH AT END OF YEAR $ 3,452,000 $ 36,909,000 $ 1,736,000
============= ============= =============
See accompanying notes to consolidated financial statements.
</TABLE>
F-8
<PAGE>
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
For the year ended December 31, 1998:
- ------------------------------------
The Company issued 43,281 common shares valued at $165,000 to the ESOP. The
Company also issued 52,793 common shares valued at $110,000 as director
compensation which were expensed in 1998.
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.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year ended December 31:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Interest (net of capitalized interest) $10,489,000 $ 2,552,000 $ 2,218,000
=========== =========== ===========
Income taxes $ -- $ -- $ --
=========== =========== ===========
</TABLE>
F-9
<PAGE>
PANACO, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996
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, 1998 and 1997 both the quantity and
dollar amounts of such arrangements 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). To qualify as hedging
instruments, these instruments must be highly correlated to anticipated future
sales such that the Company's exposure to the risky of commodity price changes
is reduced. 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.
Contracts that do not or cease to qualify as a hedge are recorded at fair value,
with changes in fair value recognized in income.
Income Taxes
- ------------
Income taxes are accounted for under the asset and liability method. Deferred
tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases and operating
loss and tax credit carryforwards. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable income in the
years in which those temporary differences are expected to be recovered or
settled. The effect on deferred tax assets and liabilities of a change in tax
rates is recognized in income in the period that includes that enactment date.
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. 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.
Non-drilling exploratory costs including geological and geophysical costs and
delay rentals are expensed. Unproved leaseholds with significant acquisition
costs are assessed periodically, on a property-by-property basis, and a loss is
recognized to the extent, if any, that the cost of the property has been
F-10
<PAGE>
impaired. Unproved leaseholds whose acquisition costs are not individually
significant are aggregated, and the portion of such costs estimated to
ultimately prove nonproductive, based on experience, are amortized over an
average holding period. As unproved leaseholds are determined to be productive,
the related costs are transferred to proved leaseholds. Provision for
depreciation and depletion is determined on a depletable unit 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 Company performs a review for impairment of proved oil and gas properties on
a depletable unit basis when circumstances suggest there is a need for such a
review. For each depletable unit determined to be impaired, an impairment loss
equal to the difference between the carrying value and the fair value of the
depletable unit will be recognized. Fair value, on a depletable unit basis, is
estimated to be the present value of expected future cash flows computed by
applying estimated future oil and gas prices, as determined by management, to
estimated future production of oil and gas reserves over the economic lives of
the reserves. Future cash flows are based upon the Company's estimate of proved
reserves. In addition, other factors such as probable and possible reserves are
taken into consideration when justified by economic conditions and actual or
planned drilling. The Company recorded an asset impairment in 1998 of $20.4
million, primarily due to lower oil and natural gas prices.
Environment Liabilities
- -----------------------
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an existing
condition caused by past operations, and do not contribute to current or future
revenue generation, are expensed. Liabilities are recorded when environmental
assessments and/or clean-ups are probable, and the costs can be reasonably
estimated. Generally, the timing of these accruals coincides with the Company's
commitment to a formal plan of action.
Capitalized Interest
- --------------------
The Company capitalizes interest costs associated with unproved properties under
development. Interest capitalized in 1998, 1997 and 1996 was $936,000, $513,000
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. Fees for processing oil and natural gas for others are treated as a
reduction of lease operating expense related to the facilities and
infrastructure.
Amortization of Deferred Debt Costs
- -----------------------------------
Costs incurred in debt financing transactions are amortized over the term of the
debt.
Per Share Amounts
- -----------------
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 as reported prior to adoption of SFAS
No. 128 for all periods presented.
F-11
<PAGE>
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.
Accounts and Note Receivable
- ----------------------------
At December 31, 1998 Accounts receivable are net of an allowance of $1 million.
During 1998 the Company made a loan of $300,000 to an executive officer of the
Company evidenced by a note and secured by a second mortgage on certain assets
of the officer. The note bears interest at 7%, requires monthly interest
payments and matures March, 2002.
Note 2 - ACQUISITIONS AND DISPOSITIONS
-----------------------------
On May 14, 1998 the Company entered into a definitive agreement with BP
Exploration and Oil, Inc. ("BP") to acquire BP's 100% working interest in East
Breaks Blocks 165 and 209 and 75% working interest in High Island Block 587. The
acquisition was accounted for using the purchase method and closed on May 26,
1998. PANACO became the operator of all three blocks effective June 1, 1998. The
Company acquired the properties for $19.6 million in cash. Included in the
acquisition is the production platform, located in 863 feet of water in East
Breaks Block 165. The Company also acquired 31.72 miles of 12" pipeline, with
capacity of over 20,000 barrels of oil per day, which ties the production
platform to the High Island Pipeline System, the major oil transportation system
in the area. It also acquired 9.3 miles of 12 3/4" pipeline, which ties the
production platform to the High Island Offshore System, the major gas
transportation system in the area.
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.
F-12
<PAGE>
Both of these acquisitions were accounted for using the purchase method. The
following unaudited pro forma financial information assumes the BP and Goldking
acquisitions had been consummated January 1, 1997. 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, 1998 and 1997
1998 1997
---- ----
Revenues $54,666,000 $59,768,000
Income (loss) before extraordinary item (46,177,000) 6,419,000
Net income (loss) (46,177,000) 5,485,000
Net income (loss) per share $ (1.93) $ 0.24
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. This
acquisition was 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.
In connection with the Company's property review during 1998, an impairment was
provided for this property due to the uncertainty regarding the operator's plans
for the Bayou Sorrel Field.
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
$275,000, $165,000 and $122,000 in costs for the years ended December 31, 1998,
1997 and 1996, respectively.
Note 4 - RESTRICTED DEPOSITS
-------------------
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 gas. Through November 30, 1997 the
Company funded $900,000 into an escrow account with respect to the West Delta
Fields. At that time, the Company completed its obligation for the funding under
West Delta agreement. 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, from 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
F-13
<PAGE>
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 $2.4 million. In connection with the BP Acquisition, the
Company deposited $1.0 million into an escrow account on July 1, 1998. On the
first day of each quarter thereafter, the Company will deposit $250,000 into the
escrow account until the balance in the escrow account reaches $6.5 million.
Note 5 - LONG-TERM DEBT
--------------
1998 1997
---- ----
10 5/8 % Senior Notes due 2004(a) $100,000,000 $100,000,000
Revolving Credit Facility (b) 13,500,000 --
Production payment(c) 2,249,000 1,700,000
------------ ------------
115,749,000 $101,700,000
Less current portion 13,500,000 --
------------ ------------
Long-term debt $102,249,000 $101,700,000
============ ============
_______
(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,
1998 was $76,000,000 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. The Senior Note indenture contains certain restrictive
convenants 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 restrictive 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.
(b) In December 1998, the Company amended its bank facility. See "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, 1998 was $45 million, with
availability under the revolver of $31.5 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. At April 1, 1999 the
borrowing base was reduced to $25 million. The borrowing base is subject to $4
million reductions on June 30, 1999 and September 30, 1999. The balance
outstanding under the Bank Facility at April 15, 1999 was $24 million. Interest
on the loan is computed at the bank's prime rate or at 1.5 to 2.25% (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, and sale of assets. At December 31, 1998
the Company was not in compliance with these covenants which has been remedied
by waivers and an amendment to the Bank Facility. However, the Company has
classified this debt as a current liability since it is probable the Company
will fail to meet these covenants at measurement dates prior to December 31,
1999. The failure to satify these covenants, or any of the other covenants in
the Bank Facility would constitute an event of default thereunder and, subject
to grace periods, may permit the lenders to accelerate the indebtedness
oustanding under the Bank Facility and demand immediate payment thereof. In such
event, the Company could be required to sell certain oil and gas assets, sell
equity securities or obtain additional bank financing. No assurance can be given
that such transactions can be consummated on terms acceptable to the Company or
its lenders, whose approval may be required. In this situation, if the Company
is unable to raise the necessary funds, the Company could become in default on
the full amount of its indebtedness, which includes the Senior Notes. The
holders of the Senior Notes have acceleration rights, subject to certain grace
periods, if the Company is in default under the Bank Facility.
F-14
<PAGE>
(c) Represents a production payment obligation to a former lender which is
paid with a portion of the revenues from certain wells. The production payment
is a non-recourse loan related to the development of certain wells acquired in
the Goldking Acquisition. The agreement requires repayment of principal plus an
amount sufficient to provide an internal rate of return of 18%.
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
--------------------------
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. During 1997
the Company hedged 263,000 barrels of oil and 5.1 Bcf 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.
During 1998 the Company hedged 463,000 barrels of oil and 12.0 Bcf of gas, which
represented 52% and 67%, respectively, of production, and resulted in a gain on
such hedges of $2,465,000, thereby increasing the Company's average gross margin
on oil and gas by $2.27 per barrel and $0.02 per Mcf, respectively.
The Company has natural gas hedged in quantities ranging from 7,301 to 37,301
MMbtu per day in each of the months in 1999 for a total of 8,770,000 MMbtu, at
pipeline prices averaging approximately $1.99 per MMbtu, for a NYMEX equivalent
of approximately $2.14 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 has hedged
223 Bbls of oil for each day in 1999 at an average price of $17.27 per Bbl and
232 Bbls of oil for each day in 2000 at an average price of $17.35 per Bbl. At
December 31, 1998, the estimated fair market value of the hedge agreements was a
gain of $1.8 million. At December 31, 1997, the estimated fair market value of
the hedge agreements in place at that time was a loss of $61,000. The fair value
of the Company's commodity hedging instruments is the estimated amount the
Company would receive or pay to settle the applicable commodity hedging
instrument at the reporting date, taking into account the difference between
NYMEX prices or index prices at year-end and the contract price of the commodity
hedging instrument. Certain of the Company's commodity hedging instruments,
primarily swaps and options, are off balance sheet transactions and,
accordingly, no respective carrying amounts for these instruments were included
in the accompanying consolidated balance sheets as of December 31, 1998 and
1997.
F-15
<PAGE>
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. 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-16
<PAGE>
<TABLE>
<CAPTION>
1996 1997 1998
------------------- ---------------------- ----------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Shares Ex. Price Shares Ex. Price Shares Ex. Price
------ --------- ------ --------- ------ ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 289,365 $ 2.21 289,365 $ 2.21 1,190,000 $ 4.45
Granted 0 -- 1,200,000 4.45 0 --
Exercised 0 -- (289,365) 2.21 0 --
Forfeited 0 -- (10,000) 4.45 (40,000) 4.45
------- ------ --------- ------ --------- ------
Outstanding at end of year 289,365 2.21 1,190,000 4.45 1,150,000 4.45
------- --------- ---------
Exercisable at end of year 289,365 $ 2.21 1,190,000 $ 4.45 1,150,000 $ 4.45
Fair value of options granted N/A $ 1.42 N/A
</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 1998 and 1997
would have been as shown below:
1998 1997
------------ ------------
Net income (loss): As reported $(46,851,000) $ 43,000
Pro forma $(47,133,000) $ (239,000)
Earnings (loss) per share As reported $ (1.96) $ --
Pro forma $ (1.97) $ (0.01)
Note 9 - MAJOR CUSTOMERS
---------------
One purchaser accounted for 42%, 62% and 49% of revenues in 1998, 1997 and 1996
respectively. These transactions represented spot sales of natural gas to one
customer.
Note 10 - INCOME TAXES
------------
At December 31, 1998, the Company had net operating loss carry forwards for
federal income tax purposes of approximately $40.6 million which are available
to offset future federal taxable income through 2018. 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.
F-17
<PAGE>
Significant components of the Company's deferred tax assets (liabilities) as of
December 31 are as follows:
1998 1997
--------- ----------
Deferred tax assets (liabilities)
Fixed asset basis differences $ (388,000) $(17,200,000)
Net operating loss carry forwards 14,207,000 14,100,000
State Taxes 1,461,000 --
Other 410,000 --
---------- ----------
Total deferred tax assets (liabilities) 15,690,000 (3,100,000)
---------- ----------
Valuation allowance for deferred
tax assets (15,690,000) --
---------- ----------
Total deferred tax assets (liabilities) $ -- $ (3,100,000)
========== ===========
At December 31, 1998, the Company determined that it is more likely than not the
deferred tax assets will not be realized and the valuation allowance was
increased by $15,690,000. In connection with the Goldking Acquisition in 1997,
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.
Total income taxes were different than the amounts computed by appying the
statutory income tax rate to income before income taxes. The sources of these
differences are as follows:
1998 1997
------ ------
Before any valuation allowance
Statutory federal income tax rate (35.00%) 35.00%
State income taxes, net of federal benefit ( 2.92%) --
Other 0.31% --
Adjustments to valuation allowance 31.40% (35.00%)
------- -------
( 6.21%) 0.00%
======= =======
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 an operating lease agreement for office space.
At December 31, 1998, the future minimum rental payments due under the lease are
as follows:
1999 $ 329,000
2000 $ 336,000
2001 $ 389,000
2002 $ 102,000
-----------
Total $ 1,156,000
===========
F-18
<PAGE>
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:
1998 1997 1996
---------- ---------- ----------
Property acquisition costs, proved $ 9,877,000 $ 39,384,000 $ 26,859,000
Property acquisition costs, unproved 1,245,000 6,026,000 5,390,000
Exploration expenses 7,582,000 353,000 --
Development costs 29,957,000 29,276,000 8,863,000
Quantities of Oil and Gas Reserves
- ----------------------------------
The estimates of proved reserve quantities at December 31, 1998, are based upon
reports of third party petroleum engineers (Ryder Scott Company, Netherland,
Sewell & Associates, Inc., 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.
Proved developed and undeveloped reserves: Oil Gas
(BBLS) (MCF)
------ -----
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
Production (895,000) (18,041,000)
Extensions and discoveries 14,000 1,077,000
Sale of minerals in-place -- (272,000)
Purchase of minerals in-place 3,735,000 23,479,000
Revisions of previous estimates 94,000 1,374,000
--------- ----------
Estimated reserves as of December 31, 1998 7,454,000 81,249,000
========= ==========
F-19
<PAGE>
Proved developed reserves:
Oil Gas
(BBLS) (MCF)
--------- ----------
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
========= ==========
December 31, 1998 5,165,000 50,539,000
========= ==========
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. The prices used for estimates of future revenues at December 31, 1998
were $10.00 per barrel of oil and $2.05 per MMbtu of natural gas, adjusted for
transportation, gravity and Btu content. Estimates of future development and
production costs are based on year-end costs and assume continuation of existing
economic conditions and year-end prices. 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.
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>
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Future cash inflows $ 259,071,000 $ 269,141,000 $ 210,875,000
Future development and production costs (129,744,000) (102,114,000) (61,822,000)
------------- ------------- -------------
Future net cash flows 129,327,000 167,027,000 149,053,000
Future income taxes -- (10,563,000) (17,899,000)
------------- ------------- -------------
Future net cash flows after income taxes 129,327,000 156,464,000 131,154,000
10% annual discount 34,747,000 (35,592,000) (31,313,000)
------------- ------------- -------------
Standardized measure after income taxes $ 94,580,000 $ 120,872,000 $ 99,841,000
============= ============= =============
</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>
1998 1997 1996
------------ ------------- -------------
<S> <C> <C> <C>
Beginning balance $120,872,000 $ 99,841,000 $ 62,921,000
Sales of oil and gas, net of production costs (30,692,000) (25,815,000) (11,027,000)
Net change in income taxes 8,160,000 5,465,000 (4,116,000)
Changes in price and production costs (42,711,000) (32,461,000) 44,088,000
Purchases of minerals in-place 23,657,000 40,027,000 45,521,000
Sale of minerals in-place (514,000) -- (10,518,000)
Revision of previous estimates, extensions &
discoveries, net 15,808,000 33,815,000 (27,028,000)
------------ ------------- -------------
Ending balance $ 94,580,000 $ 120,872,000 $ 99,841,000
============ ============= =============
</TABLE>
F-20
<PAGE>
Exhibit 10.22
SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
THIS SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this
"Amendment") dated as of March 31, 1999 is among: PANACO, INC., a Delaware
corporation (the "Borrower"); each of the Lenders (as defined in the Credit
Agreement as hereinafter defined) that is a signatory hereto; FIRST UNION
NATIONAL BANK, a national banking association (in its individual capacity,
"First Union"), as agent for the Lenders (in such capacity, together with its
successors in such capacity, the "Administrative Agent"); and PARIBAS as
Documentation Agent.
R E C I T A L S
A. The Borrower, the Administrative Agent, the Documentation Agent and the
Lenders have entered into that certain Amended and Restated Credit Agreement
dated as of October 9, 1997 as amended by First Amendment to Credit Agreement
dated as of December 11, 1998 (as amended, the "Credit Agreement"), pursuant to
which the Lenders have agreed to make certain loans and extensions of credit to
the Borrower upon the terms and conditions as provided therein.
B. An Event of Default exists under the Credit Agreement under Section 9.13
as of March 31, 1999.
C. The Borrower, the Administrative Agent, the Documentation Agent and the
Lenders now desire to make certain amendments to the Credit Agreement.
NOW, THEREFORE, in consideration of the premises and other good and
valuable consideration and the mutual benefits, covenants and agreements herein
expressed, the parties hereto now agree as follows:
1. All capitalized terms used in this Amendment and not otherwise defined
herein shall have the meanings ascribed to such terms in the Credit Agreement.
2. The definition "Applicable Margin" is hereby amended to read as follows:
"Applicable Margin" shall mean for Base Rate Loans or LIBOR
Loans the following rate per annum as applicable:
<PAGE>
- -------------------------------------------------------------------------------
Borrowing Base Utilization Base Rate Loans LIBOR Loans
Percentage
- -------------------------------------------------------------------------------
less than 25% 0.50% 1.50%
greater than or equal to 25% 0.50% 1.75%
but less than 50%
greater than or equal to 50% 0.50% 2.00%
but less than 75%
equal to or greater than 75% 0.50% 2.25%
3. Section 1.02 of the Credit Agreement is hereby supplemented, where
alphabetically appropriate, with the addition of the following definitions:
"Second Amendment" shall mean that certain Second Amendment to Amended and
Restated Credit Agreement dated as of March 31, 1999 among the Borrower,
the Lenders, the Administrative Agent and the Documentation Agent.
4. On the date that this Amendment becomes effective until the Borrowing
Base is redetermined in accordance with the terms of the Credit Agreement, the
Borrowing Base shall decrease to $25,000,000, which will automatically reduce by
$4,000,000 on June 30, 1999 and by $4,000,000 on September 30, 1999.
5. Section 9.13 of the Credit Agreement is hereby amended to read as
follows:
"Section 9.13 Tangible Net Worth. The Borrower will not permit its Tangible
Net Worth to be less at the end of any fiscal quarter than an amount equal
to 85% of Tangible Net Worth as March 31, 1999 plus 85% of the Borrower's
Net Income (only if positive) for each fiscal quarter of the Borrower after
December 31, 1998, plus 75% of the net proceeds of any new issuance of
capital stock or other equity securities of the Borrower issued after March
31, 1999."
6. Section 8.01(a) of the Credit Agreement requires that Borrower provide
certain audited consolidated financial statements and other financial statements
by no later than 90 days after the end of each fiscal year. The Majority Lenders
hereby waive, on a one time basis, but only until two (2) Business Days after
the effectiveness of this Amendment, any violation of Section 8.01(a) and any
other relevant sections of the Credit Agreement as a result of the late delivery
of the annual financial statements required to be delivered no later than 90
days after December 31, 1998.
7. This Amendment shall become binding on the Lenders when, and only when,
the following conditions shall have been satisfied and the Administrative Agent
shall have received each of the following, as applicable, in form and substance
satisfactory to the Administrative Agent or its counsel:
<PAGE>
(a) counterparts of this Amendment and the Ratification attached
hereto executed by the Borrower, the Guarantors and the Lenders; and
(b) such other documents as it or its counsel may reasonably request.
8. The parties hereto hereby acknowledge and agree that, except as
specifically supplemented and amended, changed or modified hereby, the Credit
Agreement shall remain in full force and effect in accordance with its terms.
9. The Borrower hereby reaffirms that as of the date of this Amendment, the
representations and warranties contained in Article VII of the Credit Agreement,
as amended by this Amendment, are true and correct on the date hereof as though
made on and as of the date of this Amendment, except as such representations and
warranties are expressly limited to an earlier date.
10. THIS AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND
ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH,
THE LAWS OF THE STATE OF TEXAS, OTHER THAN THE CONFLICT OF LAWS RULES THEREOF.
11. This Amendment may be executed in two or more counterparts, and it
shall not be necessary that the signatures of all parties hereto be contained on
any one counterpart hereof; each counterpart shall be deemed an original, but
all of which together shall constitute one and the same instrument.
[SIGNATURES BEGIN NEXT PAGE]
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
executed as of the date first above written.
BORROWER: PANACO, INC
By:_____________________________
Name:
Title:
LENDER AND ADMINISTRATIVE FIRST UNION NATIONAL BANK
AGENT:
By:_____________________________
Name:
Title:
LENDER AND DOCUMENTATION PARIBAS
AGENT:
By:_____________________________
Name:
Title:
By:_____________________________
Name:
Title:
<PAGE>
RATIFICATION
Each of the undersigned (a "Guarantor") hereby agrees that its liabilities
under its respective Guaranty Agreement guaranteeing the indebtedness,
obligations and liabilities under that certain Amended and Restated Credit
Agreement dated October 9, 1997, as amended, shall remain enforceable against
such Guarantor in accordance with the terms of its Guaranty and shall not be
reduced, altered, limited, lessened or in any way affected by the execution and
delivery of this Second Amendment to Amended and Restated Credit Agreement. Each
Guarantor hereby confirms and ratifies its liabilities under its Guaranty in all
respects.
PANACO PRODUCTION COMPANY
By:_____________________________
Name:
Title:
GOLDKING ACQUISITION CORP.
By:_____________________________
Name:
Title:
<PAGE>
Exhibit 10.23
EMPLOYMENT AGREEMENT
PANACO, INC., ("Panaco") hereby employs LARRY M. WRIGHT (hereinafter
referred to as "Employee") to be employed and serve as President and Chief
Executive Officer, effective September 1, 1998, on the following terms and
conditions:
WITNESSETH
1. DUTIES. Employee shall perform such services regarding the operations of
Panaco as the Board of Directors may from time to time request. Employee shall
at all times faithfully, with diligence, and to the best of his ability,
experience and talents, perform all the duties that may be required of and from
him pursuant to the terms of this Agreement. It is expressly understood and
agreed that in the performance of his duties and obligations hereunder, Employee
shall at all times be subject to the direction and control of the Board of
Directors of Panaco.
2. TERM AND RENEWAL. The initial term of employmentcontemplated by this
Agreement shall commence effective September 1, 1998, and continue for a term
of three (3) years. Thereafter, this Agreement shall automatically renew for
consecutive terms of two (2) years each, upon expiration of the initial term
and each renewal term hereunder.
3. COMPENSATION. In consideration of the work and other services that
Employee performs for Panaco hereunder, Panaco shall pay Employee the following:
(a) BASE SALARY. During the term hereof, Panaco shall pay Employee
a gross annual salary of $285,000, payable semi-monthly in accordance
with the company's normal payroll policies, subject to withholding
for federal income tax, social security, state and local taxes, if
any, and any other sums that Panaco may be legally required to with-
hold. Employee will be eligible for all cost of living adjustments
that are awarded to Panaco employees.
(b) SUPPLEMENTAL SALARY. In addition to all other compensation
provided herein, but only so long as Employee remains indebted to
Panaco by virtue of that certain Promissory Note (the Note) from
Employee to Panaco dated November 4, 1998 (the "Note"), Employee
shall be entitled to the following supplemental payments:
(i) On March 31, 1999, an amount equal to the interest which
has accrued on the Note through February 28,1999;
(ii) On the last calendar day of each month thereafter,
Employee shall be entitled to a supplemental payment of an
amount equal to the interest which accrued on the Note during
the preceding calendar month;
(iii) At its option, Panaco may apply all supplemental payments
directly against the interest obligations accruing on the Note.
(c) VACATION. Employee shall be entitled to vacation in accordance
with the vacation policies of Panaco from time to time in effect with
respect to the executive employees of Panaco.
(d) OTHER BENEFITS. During the term of this Agreement, Employee shall
be entitled to participate in all employee benefit plans from time
to time made available to the executives or general employees of
Panaco.
(e) Insurance. Panaco will provide Employee and Employee's dependant's
with coverage under a policy of hospitalization and major medical
insurance at no cost to the Employee. Panaco will provide life
insurance coverage and short term and long term disability insurance
coverage to Employee in an amount to be determined by the company.
4. EXPENSES. Panaco shall reimburse Employee for all reasonable expenses
and disbursements incurred by Employee in connection with Employee's duties
hereunder, including expenses for entertainment and travel, as are consistent
with the policies and procedures of Panaco.
5. CONFIDENTIAL INFORMATION. Employee acknowledges that in the course
of employment by Panaco, Employee will receive certain trade secrets and
confidential information belonging to the Panaco which Panaco desires to protect
as confidential. For the purposes of this Agreement, the term "confidential
information" shall mean information of any nature and in any form which at
the time is not generally known to those persons engaged in business similar
to that conducted by Panaco. Employee agrees that such information is
confidential and that he will not reveal such information to anyone other than
officers, directors and employees of Panaco. Upon termination of employment,
for any reason, Employee shall surrender to Panaco all papers, documents and
other property of Panaco.
6. AGREEMENT NOT TO SOLICIT. During the initial or renewal term hereof
and for a period of two years after the termination of employment hereunder
(the "Termination Date"), regardless of how terminated, Employee will not,
singly, jointly, or as a partner, member, contractor, employee or agent
of any partnership or as an officer, director, employee, agent, contractor,
stockholder or investor in any other entity or in any other capacity,
directly or indirectly:
(a) induce, or attempt to induce, any person or party who, on the
Termination Date is employed by or affiliated with Panaco or at
any time during the term of this covenant is, or may be, or
becomes an employee of or affiliated with Panaco, to terminate
his, her or its employment or affiliation with Panaco;
(b) induce, or attempt to induce, any person, business or entity
which is or becomes a customer or supplier of Panaco, or which
otherwise is a contracting party with Panaco, as of the Termination
Date, or at any time during the term hereof, to terminate any written
or oral agreement or understanding with Panaco, or to interfere in
any manner with any relationship between Panaco and such customer
or supplier;
(c) employ or otherwise engage in any capacity any person who at the
Termination Date or at any time during the period two years prior
thereto was employed, or otherwise engaged, in any capacity by Panaco
and who, by reason thereof is or is reasonably likely to be in
possession of any confidential information.
Employee acknowledges and agrees that the provisions of this paragraph
constitute a material, mutually bargained for portion of the consideration to
be delivered under this agreement and that it is a condition precedent to the
creation and existence of the obligations of Panaco hereunder.
7. TERMINATION OF EMPLOYMENT.
(a) TERMINATION OF CAUSE. Nothing hereunder shall prevent Panaco from
terminating Employee's employment for Cause (as hereinafter defined).
Upon termination for Cause Employee shall receive his base salary only
through the date of termination, and neither Employee nor any other person
shall be entitled to any further payments from Panaco under this Agreement.
Any rights and benefits Employee may have under employee benefit plans
and programs of Panaco by reason of or after his termination shall be
determined in accordance with the terms of such plans and programs. For
purposes of this Agreement, Termination for Cause shall mean:
(i) termination due to continued neglect of duties for which
Employee is employed after receipt of written notice thereof from
the Board of Directors of Panaco;
(ii) termination due to conduct involving moral turpitude in the
performance of duties for which Employee is employed, including,
without limitation, the commission of fraud, misappropriation or
embezzlement by Employee; or
(iii) termination due to conduct which, if not in connection
with the performance of Employee's duties hereunder, would result in
serious prejudice to the interests of Panaco if he were retained as
an employee.
(b) DEATH, DISABILITY AND TERMINATION OTHER THAN FOR CAUSE. Notwithstand-
ing any other term or provision of this Agreement, Panaco may terminate
Employee's employment at any time, during any initial or renewal term
hereof, for any reason it deems appropriate or for no reason. If Employee's
employment hereunder is terminated for any reason other than Cause in
accordance with paragraph 7(a), or if Employee dies or becomes disabled
(meaning that employee is unable to perform his duties prescribed by
section 1 of this Agreement for a period of 180 consecutive days), then
Employee shall be entitled to payment of his base salary, at the rate
in effect at the time of such termination (i) for a period of 24 months, if
such termination occurs after September 1, 1999, (ii) or for a period equal
to the remainder of the initial term of this Agreement (August 31, 2001),
if such termination occurs before September 1, 1999. Any rights and
benefits Employee may have under employee benefit plans and programs of
Panaco by reason of or after his termination shall be determined in
accordance with the terms of such plans and programs.
(c) VOLUNTARY TERMINATION. Employee may terminate his employment at any
time upon ninety (90) days' prior written notice to Panaco; provided,
however, that Panaco, in its discretion, may cause such termination to be
effective at any time during that ninety (90) day period. In the event of
such a voluntary termination of employment, Employee will be entitled to
receive only his base salary through the ninety (90) day period. Neither
Employee nor any other person shall be entitled to any further payments
from Panaco under this Agreement upon a voluntary termination by Employee
of his employment hereunder, and any rights and benefits Employee may
have under employee benefit plans and programs of Panaco by reason of
or after his termination shall be determined in accordance with the terms
of such plans and programs.
(d) VOLUNTARY TERMINATION FOR "GOOD REASON." Notwithstanding any other
term or provision of this Agreement, if Employee voluntarily terminates
his employment for Good Reason (as hereinafter defined), then Employee
shall be entitled to payment of his base salary, at the rate in effect
at the time of such termination (i) for a period of 24 months, if such
termination occurs after September 1, 1999, (ii) or for a period equal to
the remainder of the initial term of this Agreement (August 31, 2001), if
such termination occurs before September 1, 1999. Any rights and benefits
Employee may have under employee benefit plans and programs of Panaco by
reason of or after his termination shall be determined in accordance with
the terms of such plans and programs. "Good Reason" shall mean any of the
following (without Executive's express written consent):
(i) Employee's Base Salary is set at an amount less than 90
percent of the greater of (a) his annual salary in effect on
September 1, 1998, or (b) his annual salary in effect during the
preceding calendar year, and Employee resigns within ninety days
after he is notified of the decision to modify his Base Salary.
(ii) A substantial and material alteration in the nature or
status of Employee's responsibilities, or the assignment of duties
inconsistent with Employee's duties and responsibilities;
(iii) Employee's line of report is changed so that he is
required to report to anyone other than the Executive Committee or
the Board of Directors;
(iv) A change in Employee's titles or Panaco's employing a
co-President or Chief Executive Officer;
(v) Employee is not elected as a director of Panaco;
(vi) Any material breach by Panaco of any provision of this
Agreement if such material breach has not been cured within thirty
(30) days following written notice of such breach by Employee to the
Executive Committee setting forth with reasonable specificity the
nature of the breach.
8. CONTINGENT IMMEDIATE VESTING OF OPTIONS. Employee will be entitled
to the immediate full vesting of any existing options outstanding if his
employment is terminated prior to the end of the term of this Agreement due
to one or more of the following events:
(a) Employee's employment is terminated other than for Cause;
(b) Employee voluntarily terminates his employment for Good Reason;
(c) Employee becomes disabled; or
(d) Employee dies.
9. OFFSET. Upon termination of Employee's employment with Panaco, for
whatever reason, Panaco shall be entitled to offset from any amounts owing to
Employee under this Agreement, any principal and accrued unpaid interest
owing under the Note or any renewals, extensions, or modifications thereof.
10. NOTICES. All notices or other communications pursuant to this contract
may be given by personal delivery, or by certified mail, addressed to the home
office of Panaco or to the last known address of Employee. Notices given by
personal delivery shall be deemed given at the time of delivery, and
notices sent by certified mail shall be deemed given when deposited with the
U.S. Post Office.
11. ENTIRETY OF AGREEMENT. This Agreement contains the entire understand-
ing of the parties and all of the covenants and agreements between the parties
with respect to the employment.
12. GOVERNING LAW. This Agreement shall be construed and enforced in
accordance with, and be governed by, the laws of the State of Texas.
13. WAIVER. The failure of either party to enforce any rights hereunder
shall not be deemed to be a waiver of such rights, unless such waiver is an
express written waiver which has been signed by the waiving party. Waiver of
one breach shall not be deemed a waiver of any other breach of the same or
any other provision hereof.
14. ASSIGNMENT. This Agreement shall not be assignable by Employee.
In the event of a future disposition of the properties and business of Panaco
by merger, consolidation, sale of assets, or otherwise, then Panaco may assign
this Agreement and all of its rights and obligations to the acquiring or
surviving entity; provided that any such entity shall assume all of the
obligations of Panaco hereunder.
15. ARBITRATION. Any dispute, controversy or claim arising out of or
relating to this Agreement shall be submitted to and finally settled by binding
arbitration to be held in Houston, Texas, in accordance with the rules of the
American Arbitration Association in effect on the date of this Agreement, and
judgment upon the award rendered by the arbitrator(s) may be entered in any
court having jurisdiction thereof. All agreements contemplated herein to be
entered into to which the parties hereto are parties shall contain provisions
which provide that all claims, actions or disputes pursuant to, or related to,
such agreements shall be submitted to binding arbitration. Employer agrees
to pay all fees charged by the American Arbitration Association in connection
with any arbitration.
DATED this ------- day of --------, 1999
PANACO, INC. EMPLOYEE
By: --------------------------------- --------------------------
A member of its Executive Committee
<PAGE>
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