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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, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-26662
PANACO, Inc.
(Exact name of registrant as specified in its charter)
Delaware 43 - 1593374
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1100 Louisiana, Suite 5100
Houston, TX 77002 77002-5220 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. [ X ]
The aggregate market value of the voting stock held by non-affiliates of the
registrant was approximately $11,933,777 as of March 20, 2000.
24,323,521 shares of the registrant's Common Stock were outstanding
as of March 20, 2000.
Documents Incorporated by Reference
Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 1999, are incorporated by reference into Part III.
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<PAGE>
PANACO, Inc.
Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 1999
Table of Contents
<TABLE>
<CAPTION>
Page Number
<S> <C>
Part I
Item 1. Business 2
Item 2. Properties 15
Item 3. Legal Proceedings 20
Item 4. Submission of Matters to a Vote of Security Holders 20
Part II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 20
Item 6. Selected Financial Data 24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 24
Item 7a. Qualitative and Quantitative Disclosures
About Market Risks 29
Item 8. Financial Statements and Supplementary Data 30
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 30
Part III
Item 10. Directors and Executive Officers of the Registrant 30
Item 11. Executive Compensation 30
Item 12. Security Ownership of Certain Beneficial Owners and
Management 30
Item 13. Certain Relationships and Related Transactions 30
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports
On Form 8-K 31
Glossary of Selected Oil and Gas Terms 33
Signatures 36
</TABLE>
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PART 1
Item 1. Business.
With the exception of historical information, the matters discussed in this
Form 10-K contain forward-looking statements. The forward-looking statements we
make, not only in this Form 10-K, but also in press releases, oral statements
and other reports that we file with the Securities and Exchange Commission
("SEC") are intended to be subject to the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995. These statements relate to future
results of operations, the ability to satisfy future capital requirements, the
growth of our Company and other matters. You are cautioned that all
forward-looking statements involve risks and uncertainties. The words
"estimate," "anticipate," "expect," "predict," "believe" and similar expressions
are intended to qualify these forward-looking statements. We believe that the
forward-looking statements that we make are based on reasonable expectations.
However, due to the nature of the business we are in and other factors, we can
not assure you that the actual results of our Company will not differ from those
expectations.
Unless otherwise specified, all references we make to "PANACO" or the
"Company" include PANACO, Inc. and the predecessor company, PAN Petroleum, MLP.
Through December 31, 1999 we had two subsidiaries, Goldking Acquisition Corp.
and PANACO Production Company. On December 31, 1999 we merged these into PANACO,
Inc. and our references to PANACO may include these former subsidiaries.
Capitalized terms in this Form 10-K are defined in a glossary, which begins on
Page 33. Our corporate headquarters are located at 1100 Louisiana Street, Suite
5100, Houston, Texas 77002. Our telephone number is (713) 970-3100 and our fax
number is (713) 970-3151. You can also visit our website, which can be found at
www.panaco.com.
The predecessor of PANACO was formed in 1984 as a consolidator of oil and
gas partnerships. From 1984 through 1988 a total of 114 partnerships were
acquired and merged into our predecessor, which became PAN Petroleum, MLP in
1987. In 1991, we formed PANACO, Inc. as a Delaware Corporation and acquired PAN
Petroleum, MLP in 1992. At that time, we began focusing our resources on the
Gulf of Mexico and the states surroundings the Gulf, which we collectively refer
to as the Gulf Coast Region. We acquired our first property in the Gulf of
Mexico in 1991, and since that time, have acquired other properties in the Gulf
Coast Region and Gulf of Mexico in every year since 1994. We have grown not only
through acquisitions in each of those years but also by further developing the
properties we have acquired. We acquired those properties from companies such as
Conoco, Texaco, Arco, Oxy and BP Exploration & Oil, Inc. (now BP Amoco). We also
acquired the common stock and the oil and gas properties from the Goldking
Companies in 1997. We are in the business of selling oil and natural gas
produced on properties we lease to third party purchasers. We obtain the
reserves of crude oil and natural gas by a combination of buying them from
others, drilling developmental wells on acquired properties and drilling
exploratory wells in new locations.
Business Strategy
Our strategy is to systematically grow reserves, production, cash flow and
earnings through a program focused on the Gulf Coast Region. Some of the ways we
do this are: (i) strategic acquisitions and mergers, (ii) exploiting and
developing acquired properties, (iii) marketing of existing infrastructure and
(iv) a selective exploration program. As a result of previous property
acquisitions from BP, Amoco, Goldking and others, which are described below, we
have 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
In implementing our strategy, we focus our acquisition efforts on Gulf
Coast Region properties that have an inventory of development and exploitation
projects, significant operating control, infrastructure value and opportunities
for cost reduction. The properties we seek to acquire are generally geologically
complex with multiple reservoirs, have an established production history and are
candidates for exploitation and further exploration. 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, we identify properties that may be acquired, preferably through
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negotiated transactions or, where appropriate, sealed bid transactions. Once we
acquire these properties we focus on reducing operating costs and implementing
production enhancements through the application of technologically advanced
production and recompletion techniques.
In the future, we may acquire more oil and natural gas assets or ownerships
in other assets that we believe will provide value to our investors. In doing
so, there are inherent risks associated with the oil and natural gas industry.
The success of our acquisitions will depend on our ability to estimate the
quantity of oil and natural gas reserves using all of the data available to us
at the time. The success of these acquisitions will also depend on how the
actual results of the properties compare to the results that we projected when
the acquisition was evaluated.
While we tend to focus on acquisitions of properties from large integrated
oil companies, we evaluate a broad range of acquisition and merger
opportunities. PANACO is comprised of a staff with technical experience in
evaluating, identifying, exploiting and exploration on Gulf Coast Region
properties. Also, we believe that we are regarded in the industry as a competent
buyer with the proven ability to close transactions in a timely manner. Based on
these factors, we are usually asked to bid on significant producing property
sales in the Gulf Coast Region. Below are highlights of some of our more
significant acquisitions.
Price Lake Field
We acquired the Price Lake Field in April 1998 as a potential development
field in addition to exploration prospects which had been identified using new
3-D Seismic data. The Field had previously produced 26.7 Bcf of natural gas and
913,000 barrels of oil from shallower reservoirs. As operator, we evaluated the
3-D Seismic data, identified potential drilling locations and brought partners
into the prospect. We spudded the first well in January 1999 and reached a depth
of 16,467 in May 1999. This well, the Sturlese Estate #1, was successful in the
exploratory zones of the prospect and encountered 144' of producing formation in
the MA-22 and MA-24 sands. This well began production in September 1999 once we
completed production facilities. We own 56.25% of this well until it reaches
payout, after which we will own 51.2% and we will own 51.2% of the subsequent
wells in this Field. The second well in the Field, the Sturlese #3 was spudded
in November 1999, and was completed as a successful developmental well in March
2000. The Sturlese #3 was drilled to a total depth of 17,000' and encountered an
estimated 98' of productive sand in two zones.
BP Acquisition
In May 1998 we acquired 100% of East Breaks Blocks 165 and 209 and 75% of
High Island Block 587 from BP Exploration and Oil, Inc., now BP Amoco ("BP"). We
entered into a purchase and sale agreement with BP on May 14 and closed the
acquisition on May 26. We paid $19.6 million in cash and accounted for the
acquisition as a purchase. In addition to the leases acquired, we also received
3-D Seismic data which covers 20 offshore blocks. We became the operator
effective June 1, 1998.
The central production platform for all three blocks is located in East
Breaks 165. This platform is nicknamed "Snapper" and is located in 863 feet of
water. Also included in the acquisition was 31.72 miles of 12" oil pipeline,
with capacity of over 20,000 barrels of oil per day. This oil pipeline ties our
production platform to the High Island Pipeline System, which is the major oil
transportation system in that area. We also acquired a 9.3 mile, 12 3/4" gas
pipeline, which connects to the High Island Offshore System, the major gas
transportation system in the area. We currently receive payments from other
lease operators in the area for their use of our platform and processing
facilities, which reduces our operating expenses in this Field. We have
completed some development on the Field since it was acquired, and continue to
evaluate the 3-D Seismic data for further development.
Goldking Acquisition
On July 31, 1997, we acquired the Goldking Companies, Inc. ("Goldking") by
purchasing all of the common stock of its parent Company, a privately held oil
and natural gas company. The Goldking acquisition included not only oil and gas
reserves, but also a portfolio of exploration prospects, an extensive
development program and a technical staff experienced in Gulf Coast oil and
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natural gas operations. Goldking was held as a subsidiary of PANACO, Inc., which
was named PANACO Production Company. On December 31, 1999 we merged the
subsidiary into PANACO, Inc. The largest oil and gas lease we acquired from
Goldking was the Umbrella Point Field, which we have successfully developed
since the acquisition. In January 1998 we completed a developmental well that
began production in February 1998, the State Lease #74-10 well. This well
produced as much as 27 MMcf of natural gas and 260 barrels of condensate per
day. In December 1999, we completed a workover on this well and brought its
production back up to 19 MMcf of natural gas and 176 barrels of condensate per
day. We recently completed another successful development well in this Field in
January 2000. The State tract #87-12 was spud on December 25, 1999 and drilled
to a total depth of 12,000'. The well reached total depth in January 2000 and
encountered 85' of net productive intervals in four different zones. The well
flowed 10,100 Mcf and 337 barrels of condensate during a 24 hour test and has a
calculated open flow rate of 38,100 Mcf per day.
Amoco Acquisition
In October 1996 we acquired interests in six offshore fields from Amoco
Production Company, now BP Amoco. We paid Amoco $32 million in cash and issued
them 2 million shares of common stock in consideration for the properties.
Following is a summary of the interests acquired:
<TABLE>
<CAPTION>
Net Reserves at 12/31/99
---------------------------------------
Working Pretax PV-10
Field Blocks Interest Oil (Mbbls) Gas (Bcf) ($ Millions)
----- ------ -------- ----------- --------- ------------
<S> <C> <C> <C> <C> <C>
East Breaks 160 160/161 33% 995 9.5 $ 24.9
West Cameron 180 144 12.5% 11 2.4 3.5
High Island 309 309/310 50% 4 3.7 2.4
High Island 474 474/475/489/499 12% 100 0.3 1.1
High Island 330 330/349 12% -- 0.3 (0.3)
High Island 302 302 33% -- -- (0.3)
</TABLE>
All of the properties we acquired from Amoco are operated by third parties,
which are Unocal, Texaco, Coastal Oil and Gas and Newfield Exploration. We
acquired an additional 25% interest in West Cameron 144 in 1998.
Zapata Acquisition
In July 1995, we acquired all of Zapata Corp.'s remaining offshore
properties. The net purchase price was $2.8 million in cash and was effective
October 1, 1994. The purchase price also included a production payment to Zapata
and a platform revenue sharing agreement, both of which related to the East
Breaks 109 Field. In January 2000, we acquired the production payment and
revenue sharing agreement for $1.4 million in cash and a 1% overriding royalty
on East Breaks 109/110. In late 1998 we acquired new 3-D Seismic covering
several blocks in the East Breaks area, including blocks 109 and 110. Based on a
review of this new seismic data, we have identified several developmental and
exploratory drilling locations on blocks 109 and 110 and we have allocated a
relatively significant part of our 2000 capital budget to developmental work on
these blocks.
Exploitation and Development of Acquired Properties
Primarily through these acquisitions, we have developed an inventory of
exploitation projects including development drilling, workovers, sidetrack
drilling, recompletions and artificial lift enhancements. As of December 31,
1999, 40% of our total Pretax PV-10 relates to Proved Undeveloped Reserves. We
use advanced technologies where appropriate in development activities to convert
Proved Behind Pipe and 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 utilizing our existing platform and pipeline
infrastructure, which improve project economics.
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Marketing of Existing Infrastructure
A key element of each acquisition we have made has been production
infrastructure. While we focus primarily on oil and natural gas reserves, we
view platforms, pipelines and related facilities as an often-overlooked source
of additional revenues. We own interests in 23 offshore platforms and 109 miles
of offshore oil and natural gas pipelines with diameters of 10" or greater. We
market the use of this infrastructure to other lease operators as a source of
additional revenue to us and as a way for other lease operators to produce their
hydrocarbons in a more economical fashion. We currently have facility use or
processing agreements in the West Delta Fields, the Umbrella Point Field, the
East Cameron 359 Field, the East Breaks 109 Fields, the East Breaks 160 Fields
and the East Breaks 165 Fields. Our major focus of marketing these facilities
has been in the East Breaks area. We own 100% of the platforms and related
pipelines in the East Breaks 109 and East Breaks 165 Fields and 33% of the
platforms and pipelines in the East Breaks 160 Fields. These existing platforms
are three of the furthest from the coast line in the Gulf of Mexico and are in
700' to 900' of water and replacement costs for these facilities are in excess
of $100 million. These existing platforms can significantly improve the
economics of operating an adjacent oil and gas lease and in return lower our
costs of operating this infrastructure. We currently receive approximately
$175,000 per month from other lease operators in the East Breaks area alone,
which we account for as a reduction of lease operating expense.
Selective Exploration Program
During 1996 we began to increase our exposure to exploration projects by
allocating more resources to and reviewing more of these projects. This process
continued with the Goldking acquisition in 1997. Goldking increased our
inventory of exploratory projects and the technical staff of PANACO. In 1998 and
1999 we allocated 10% to 20% of our capital budget on exploratory projects. We
believe a balanced capital budget includes the higher reward and higher risk
exploratory projects along with the lower risk developmental projects.
The increased technical staff has helped us by increasing exposure to
third-party projects and, more importantly, by generating more projects on the
properties we already own. New 3-D Seismic data and our technical staff have
generated several exploration prospects, most recently the successful Price Lake
wells and Umbrella Point wells. Our exploratory inventory is unique in that many
of the exploration prospects can be reached in conjunction with developmental
wells, which reduces the risk by providing "bail outs" in lower risk
developmental reserves.
Geographic Focus
Our reserve base is focused primarily in the Gulf Coast Region, which
includes the Gulf of Mexico. The Gulf of Mexico has historically been the most
prolific basin in North America and currently accounts for over 35% of the
natural gas produced 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, we have focused our efforts in this region. We believe we have
the technical expertise and infrastructure in place to take advantage of the
inherent benefits of the Gulf Coast Region. Also, as the integrated oil
companies move to deeper water, we believe we will continue to be well
positioned to use our expertise to acquire and exploit Gulf Coast Region
properties.
Inventory of Exploitation and Development Projects
We have identified development drilling locations and recompletion and
workover opportunities. We believe that the majority of these opportunities have
a moderate risk profile and could add incremental reserves and production. In
addition to these identified opportunities, with the use of 3-D Seismic
technology, additional opportunities continue to be found in the known
reservoirs as well as deeper undrilled horizons. For example, new 3-D Seismic on
the West Delta Fields, which were acquired in 1991, has identified further
development potential, which led to a new well completed in January 2000.
Significant Operating Control
We operate 78% of our properties as measured by Pretax PV-10 value. The
operator of an oil and natural gas property supervises production, maintains
production records, employs field personnel, and performs other functions
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required in the production and administration of such property. This level of
operating control benefits us in numerous ways by enabling us 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, our geographic focus allows us to operate a large
value asset base with relatively few employees, thereby decreasing overhead
relative to other offshore lease operators.
Well Operations
We operate 64 productive offshore wells and own all of the working
interests in a majority of those wells. Our 50 remaining productive offshore
wells are operated by third party operators, including Unocal Corporation,
Coastal Oil & Gas Corp., Newfield Exploration, Texaco, Anadarko Petroleum
Corporation and Burlington. We also operate 25 productive onshore wells in which
we own a majority or all of the working interest. In addition, we own working
interests in two productive 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 we acquired our interest in these
properties. We consider these joint operating agreements to be on terms
customary within the industry. 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
We utilize our capital budget for (a) the acquisition of interests in other
producing properties, (b) recompletions of our 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
larger fields that fit their criteria. Present day technology permits drilling
and completing wells in water in excess of 10,000 feet.
We believe that our 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 we drill will vary from period to period depending upon the
amount of the capital budget available for drilling, the cost of each well, our
commitment to participate in the wells drilled on properties operated by third
parties, the size of the fractional working interest acquired 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 greater.
Use of 3-D Seismic Technology
The use of 3-D Seismic and computer-aided exploration ("CAEX") technology
is an integral component of our acquisition, exploitation, drilling and business
strategy. In general, 3-D Seismic is the process of obtaining continuous seismic
data within a large geographic area, rather than as individual, widely spaced
lines. 3-D Seismic differs from 2-D Seismic in that it provides information as a
seamless volume, or "cube" of data instead of information along a single
vertical line or numerous separate vertical lines across the geological
formations of interest.
By integrating well log and production data from existing wells with the
structural and stratigraphic details of a continuous 3-D Seismic volume, our
Geoscience team obtains a greater understanding and clearer image of the
formations of interest. While it is impossible to predict with certainty the
exact structural configuration or lithological composition of any underground
geological formation, 3-D Seismic provides a mechanism by which more accurate
and detailed 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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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 smaller companies such as ours. Prior to that, it was the exclusive
province of large multinational oil companies. We own our own seismic
interpretation workstations and data processing equipment and utilize the
services of outside firms to process and interpret seismic data.
With the BP Acquisition, we acquired 129 square miles of 3-D Seismic. We
have used the seismic for workover and recompletion activity to date, and we
plan further development on the fields acquired with this seismic data.
Marketing of Production
We sell the Production from our properties in accordance with industry
practices, which include the sale of oil and natural gas at the wellhead to
third parties. We sell both at prices based on factors normally considered in
the industry, such as index price for natural gas or the posted price for oil,
price premiums or bonuses with adjustments for transportation and the quality of
the oil and natural gas.
We market all of our offshore oil production to Plains Resources, Amoco,
Oxy, Conoco, Texaco, Unocal and Vastar. Oxy, Conoco, Texaco and Vastar each have
a 25% call (exclusive right 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 our properties acquired from Amoco at their
posted prices. If we have 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 our choice.
Plains Resources purchases the oil production from the Umbrella Point Fields,
the East Breaks 165 Fields, the Price Lake Field and on some of our smaller
fields that produce oil. Plains Resources accounted for 37% of our total
revenues in 1999. Natural gas is generally sold on the spot market or under
short-term contracts of one year or less. There are numerous potential
purchasers for natural gas. Notwithstanding this, natural gas purchased by
Columbia Energy Services Corporation (now Enron North America Corp.) accounted
for 39% of our total revenues in 1999. There are numerous natural gas purchasers
doing business in the areas that we operate in as well as natural gas brokers
and clearinghouses. Furthermore, we can contract to sell the natural gas
directly to end-users. We do not believe that we are dependent upon any one
customer or group of customers for the purchase of natural gas.
Plugging and Abandonment
All of our reserve values include the estimated future liability to plug
and abandon ("P&A") all of the wells, platforms and pipelines in accordance with
guidelines established by regulatory authorities. These costs vary according to
the location of the lease, depth of water, number of wells, etc. The total
estimated future abandonment costs for all of our properties is over $21
million. The Minerals Management Service of the U.S. Department of the Interior
("MMS") requires operators of offshore platforms to provide evidence of the
ability to satisfy these future obligations. The companies that we acquire
properties from may also require evidence of our ability to satisfy these future
obligations. Our preferred method of providing evidence to these parties is a
combination of escrow accounts and surety bonds. Following is a description of
the methods by which we have accomplished these objectives.
West Delta Fields
The former owner of these Fields requires a $4.1 million surety bond, based
on their estimate of the P&A Liability of the Fields. As security for the $4.1
million bond, we have provided a cash escrow account to the underwriter of the
bond. The balance of this escrow account was $1.1 million at December 31, 1999,
and was fully funded in November 1997 in accordance with the terms of the escrow
agreement. We also provide the MMS a $50,000 surety bond for the plugging of two
wells in federal blocks of these Fields.
East Breaks 165 Fields
We provide the MMS with a $10.9 million surety bond based on their
estimated P&A Liability for these Fields. As security for the underwriter of
this bond we have established a cash escrow account. The balance in this escrow
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account totaled $2.3 million at December 31, 1999 and requires quarterly
deposits of $250,000 until the balance in the escrow account reaches $6.5
million. The underwriter also provides the former owner of these Fields with a
$6.5 million security bond based on the same escrow account used for the bond
provided to the MMS.
East Breaks 109 Fields
We provide the MMS with a $5.8 million surety bond for these Fields. As
security for the underwriter of these bonds, we have established an escrow
account, the balance of which was $1.8 million at December 31, 1999. The escrow
agreement requires quarterly deposits of $250,000 until the balance of the
account reaches $5.4 million.
Amoco Properties
The properties we acquired from Amoco in 1996 are all operated by third
parties and as such, the MMS does not require non-operators to provide evidence
of the ability to P&A the properties. However, Amoco Production Company requires
us to fund an escrow account to provide them with this evidence. The escrow
agreement requires that we deposit 10% of the cash flows from the Fields, net of
capital expenditures for their lives. At December 31, 1999 the balance in this
escrow account was $315,000.
We provide much smaller bonds on various locations for similar purposes,
the amounts of which are not significant. All of these agreements provide for us
to receive the escrow monies back upon satisfaction of our performance of these
obligations.
Insurance
We maintain insurance coverage that is customary for companies our size and
engaged in the same line of business. Our coverage includes general liability
insurance in the amount of $50 million for personal injury and property damage.
We carry cost of control and operators extra expense insurance of $5 million to
$20 million, depending on the estimated cost to drill the well for wells onshore
or in state waters, and up to $50 million for wells in federal offshore waters.
The amounts are proportionately reduced if we own less than 100% of the well. We
also maintain $112 million in property insurance on our offshore properties. We
also carry business interruption insurance on our significant properties, which
covers the estimated cash flows from each property after it has been
non-producing for 21 days and reimburses us for those amounts for up to six
months. Finally, our officers and directors are indemnified by PANACO and we
maintain insurance of $3 million which is designed to reimburse us for legal
fees incurred in defense costs. We believe that our insurance coverage is
adequate and the underwriters of our insurance will be able to satisfy any
claims made. However, we can not assure you that this insurance or that the
underwriters will adequately cover all of the costs or that we will be able to
continue to purchase insurance at reasonable prices. Even one significant event,
if not adequately insured, could significantly impair our financial condition
and results of operations.
Funding of Business Activities
Credit Facility
Our primary source of capital beyond discretionary cash flows is our Credit
Facility. Our Credit Facility is secured by a first mortgage on most of our oil
and natural gas properties, and is used primarily as development capital on
properties that we own. We may also use the Credit Facility for working capital
support, to provide letters of credit and general corporate purposes.
In September 1999 we put in place a new Credit Facility, with Foothill
Capital Corp. as the Agent, along with Foothill Partners, L.P. and Ableco
Finance, a subsidiary of Cereberus Capital Management, L.P. This Credit Facility
is a $60 million line, with a term of two years to October 1, 2001, and
extendable for an additional year at our option. Borrowings under this Facility
bear interest at rates ranging from prime plus .5% up to prime plus 3.0%
depending on the amounts borrowed. We had $36.7 million outstanding at December
31, 1999. We will continue to use this Facility in 2000 to fund part of our $30
million capital budget.
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The Credit Facility is a revolving credit agreement subject to monthly
borrowing base determinations. These determinations are made from internally
prepared engineering reports, using a two year average of NYMEX future commodity
prices and are based on our semi-annual third party reserve reports.
Indebtedness under this Credit Facility constitutes senior indebtedness with
respect to the Senior Notes.
Under the terms of this Credit Facility, we must maintain a ratio of
trailing twelve-month EBITDA to net interest expense of not less than 1.0 to 1.0
through December 31, 1999 and 1.5 to 1.0 from January 1, 2000 through the term
of the Facility. We must also maintain a working capital ratio, as defined in
the agreement, of not less than .25 to 1.0. Also, the Credit Facility contains
certain limitations on mergers, additional indebtedness and pledging or selling
assets. We were in compliance at December 31, 1999 with the covenants contained
in the Credit Facility.
Senior Notes
In October 1997 we issued $100 million of Senior Notes which bear interest
at 10 5/8% and are due October 1, 2004. These Senior Notes are general unsecured
obligations and rank pari passu with any unsubordinated indebtedness and rank
senior to any subordinated indebtedness. In effect, the Senior Notes are
subordinated to all secured indebtedness, such as the Credit Facility, but only
up to the value of the assets that are secured.
We can redeem all or part of the Senior Notes, at our option, after October
1, 2001, at certain prices, which are specified in the indenture plus accrued
interest to date. We can also redeem up to 35% of the Senior Notes any time
after October 1, 2000 at a price of 110.625% of the principal, plus accrued
interest to date, with the proceeds of an equity offering.
If a Change in Control occurs, as it is defined in the Indenture, the
holders of the Senior Notes can require PANACO to repurchase those notes at 101%
of the principal amounts plus accrued interest to date. We must maintain a total
Adjusted Consolidated Net Tangible Asset Value, as defined in the Indenture,
("ACNTA") equal to 125% of our indebtedness at the end of each quarter. If our
ACNTA falls below this percentage of indebtedness for two succeeding quarters,
we must redeem an amount of the Senior Notes sufficient to maintain this ratio.
The Indenture contains certain restrictive covenants that limit us 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 and incur liens. The Indenture also restricts us
from merging or consolidating with any other person or sell, assign, transfer,
lease, convey or otherwise dispose of all or substantially all of our assets. In
addition, under certain circumstances, we 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. We were in compliance at December 31, 1999
with the covenants contained in the Indenture.
Common and Preferred Stock
On December 31, 1999 we had issued and outstanding 23,986,521 shares of
$.01 par value common stock. You will find a more detailed description of our
common stock and the rights of ownership in Part II, Item 5 of this Form 10-K.
We are authorized to issue 100 million shares of common stock for a variety of
purposes with board of director approval. In the past, we have issued new common
stock for property acquisitions, raising additional capital and for compensation
to our directors and employees. We have an Employee Stock Ownership Plan
("ESOP") that we contribute shares to for the account of employees. The ESOP
plan was established in 1994 and is funded annually at the discretion of the
board of directors.
We are authorized to issue up to 5 million shares of preferred stock the
details of which you can also find in Part II, Item 5 of this Form 10-K. We have
not issued any shares of preferred stock.
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
9
<PAGE>
natural gas producing properties and securing experienced personnel. We
encounter competition from various independent oil companies in raising capital
and in acquiring producing properties. Many of our competitors have financial
resources and staffs considerably larger than ours.
Markets. Our ability to produce and market oil and natural gas profitably
is dependent upon on numerous factors beyond our control. 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. At various times during
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 during those
periods.
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. We 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 that we produce 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, we are unable to predict future oil
and natural gas prices. In order to minimize these uncertainties we have from
time to time hedged prices on a portion of our 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. We sell our natural gas on the spot market
based upon published index prices. Historically our net price received for our
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 $.12 below the index price.
Environmental and Other Regulation. Our 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. These rules and regulations include
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 our
business. In view of the many uncertainties with respect to current law and
regulations, including their applicability to us, we cannot predict the overall
effect of such laws and regulations on future operations.
We believe that our 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 our method of operations than on
other similar companies in the industry. The following discussion contains
summaries only of certain laws and regulations.
Various aspects of our 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
10
<PAGE>
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 us are not
regulated and are made at market prices. The price we receive from the sale of
these products is affected by the cost of transporting the products to market.
Effective 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. We are not able to predict with certainty
the effect, if any, these regulations will have on our business.
Additional proposals and proceedings that might affect the oil and natural
gas industry are pending before Congress, the FERC and the courts. We 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 our
capital expenditures, earnings or competitive position.
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 we are subject relating to
protection of the environment may, in certain circumstances, impose "strict
liability" for environmental contamination, rendering a person liable for
environmental damages and response costs without regard to negligence or fault
on the part of such person. For example, the federal Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended, also known as the
"Superfund" law, imposes strict, joint and several liability on an owner and
operator of a facility or site where a release of hazardous substances into the
environment has occurred and on companies that disposed or arranged for the
disposal of the hazardous substances released at the facility or site.
Similarly, the Oil Pollution Act of 1990 ("OPA") imposes strict liability for
remediation and natural resource damages in the event of an oil spill. In
addition to other requirements, the OPA requires operators of oil and natural
gas leases on or near navigable waterways to provide $35 million in "financial
responsibility" as defined in the Act. At present we are 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 our operations and costs. Furthermore, we 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 us. While compliance with
environmental requirements generally could have a material adverse effect on our
capital expenditures, earnings or competitive position we believe that other
independent energy companies in the oil and natural gas industry likely would be
similarly affected. We also believe that we are 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
us.
Offshore operations 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, we do not expect these costs to be material.
See "Risk Factors - Environmental and Other Regulations."
Employees
We have 34 full time employees, five of whom are officers. Additionally, we
utilize approximately 40 contract personnel in the operation of our properties,
and use numerous outside geologists, production engineers, reservoir engineers,
geophysicists and other professionals on a consulting basis.
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<PAGE>
Risk Factors
Finding and Acquiring Additional Reserves; Depletion
Our future success and growth depends upon the ability to find or acquire
additional oil and natural gas reserves that are economically recoverable.
Except to the extent that we conduct successful exploration or development
activities or acquires properties containing Proved Reserves, our Proved
Reserves will generally decline as they are produced. The decline rate varies
depending upon reservoir characteristics and other factors. Our future oil and
natural gas reserves and production, and, therefore, cash flow and income are
highly dependent upon the level of success in exploiting our 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, our ability to make the necessary capital investments to maintain
or expand this asset base of oil and natural gas reserves could be impaired.
There can be no assurance that our planned development projects and acquisition
activities will result in additional reserves or that we will have success
drilling productive wells at economic returns sufficient to replace our current
and future production.
Substantial Leverage; Ability to Service Debt
We have incurred significant losses in 1999 and 1998 and are significantly
leveraged. Our long-term debt balance at December 31, 1999 was $138.9 million
and our stockholders' deficit was ($26.9 million). A large part of our losses in
each year was due to depletion and impairment of property costs based primarily
on low commodity prices. This level of indebtedness has several important
effects on our operations, including (i) a substantial portion of our cash flow
from operations is dedicated to interest on our long-term debt and is not
available for other purposes, (ii) the covenants in our Credit Facility and our
Senior Notes can be very restrictive as to how we conduct business, (iii) our
ability to obtain additional financing may be restricted, (iv) the market price
for our common stock may be lower than companies in our peer group. We can not
give you assurance that we will continue to find financing on acceptable terms,
or at all. If sufficient capital is not available, we may not be able to
continue to implement our business strategy.
The Credit Facility lenders have the ultimate decision, at their sole
discretion, as to the amounts available to borrow under the line. If oil or
natural gas prices decline significantly, the availability under this line could
be severely reduced. The Credit Facility requires us to satisfy certain
financial ratios in the future. The failure to satisfy these covenants or any of
the other covenants in the Credit Facility would constitute an event of default
thereunder and may permit the lenders to accelerate the indebtedness outstanding
under the Credit Facility and demand immediate repayment. See "Credit Facility."
Volatility of Oil and Natural Gas Prices
Our revenues, profitability and the carrying value of 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. Our ability to maintain or increase 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 our 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. Our
production is weighted toward natural gas, making earnings and cash flow more
sensitive to natural gas price fluctuations. Historically, we have attempted to
mitigate these risks by oil and natural gas hedging transactions. See "Business
- - - Marketing of Production."
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<PAGE>
Uncertainty of Estimates of Reserves and Future Net Cash Flows
The basis for the success and long-term continuation of our Company is the
prices that we receive for our oil and natural gas. These prices are the primary
factors for all aspects of our business including reserve values, future net
cash flows, borrowing availability and results of operations. The reserve
valuations are prepared semi-annually by independent petroleum consultants,
including the Pretax PV-10 values included in this Form 10-K. However, there are
many uncertainties inherent in preparing these reports and the third party
consultants rely on information we provide them. The Pretax PV-10 calculations
assume constant oil and natural gas prices, operating expenses and capital
expenditures over the lives of the reserves. They also assume certain timing for
completion of projects and that we will have the financial ability to conduct
operations and capital expenditures without regard to factors independent of the
reserve report. The actual results we realize from these properties have
historically varied from these reports and may do so in the future. The volumes
estimated in these reports may also vary due to a variety of reasons including
incorrect assumptions, unsuccessful drilling and the actual oil and natural gas
prices that we receive.
You should not assume that the Pretax PV-10 values of our reserves that are
included in this Form 10-K represent the market value for those reserves. These
values are prepared in accordance with strict guidelines imposed by the SEC.
These valuations are the estimated discounted future net cash flows from our
Proved Reserves. These estimates use prices that we received or would have
received on December 31, 1999 and use costs for operating and capital
expenditures in effect at that same time. The average prices used in calculating
the Pretax PV-10 value at December 31, 1999 were $2.43 per Mcf of natural gas
and $24.99 per barrel of oil. These prices are adjusted on a property by
property basis for the quality of the oil and natural gas and for transportation
to the appropriate location. These assumptions are then used to calculate a
future cash flow stream, that is discounted at a rate of 10%.
Acquisition Risks
As our business strategy is to grow primarily through acquisitions and
subsequent development of those acquired properties, you should know that there
are risks involved in acquiring oil and gas reserves. We perform extensive
reviews of properties that we intend to acquire based on the information
available to us. With a limited staff, we may use consultants to assist us in
our review and we may rely on third party information available to us. Again,
these are inherent uncertainties in the review process. Consistent with other
companies in our peer group, we focus our review on the properties with the most
significant values and spend less time on less significant properties. This
could leave undetected a problem or issue that did not initially appear to be
significant to us.
We have typically focused our acquisition efforts on larger assets being
sold such as our BP Acquisition and Amoco Acquisition. By doing so, we are at
risk for unforeseen problems to become significant both operationally and
financially. Variations of actual results from results we estimate in the review
process could also be more significant to us.
Exploration and Development Risks
With our inventory of projects on our existing properties, we have done or
plan to do more development, and to a lesser extent, exploration than we have
since the inception of our Company. While we feel that this is the best approach
to implement our business strategy, it also involves inherent risks. The costs
of drilling all types of wells are uncertain, as are the quantity of reserves to
be found, the prices that we will receive for the oil or natural gas and the
costs to operate the well. While we have successfully drilled many wells, you
should know that there are inherent risks in doing so, and those difficulties
could materially affect our financial condition and results of operations. Also,
just because we complete a well and begin producing oil or natural gas, we can
not assure you that we will recover our investment or make a profit.
Operating Hazards and Uninsured Risks
Our 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
13
<PAGE>
of life, damage to properties and substantial losses. Although we carry
insurance at levels we believe are reasonable, we are not fully insured against
all risks. Losses and liabilities arising from uninsured or under-insured events
could have a material adverse effect on our financial condition and operations.
Marketing Risks
Substantially all of our 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, 1999, one
natural gas purchaser accounted for approximately 39% of our revenues. Also, in
1999 we consolidated a majority of our oil production to one oil purchaser, who
accounted for 37% of our total revenues in 1999. We do not believe that
discontinuation of a sales arrangement with either of these purchasers would be
in any way disruptive to our marketing operations.
Hedging Risks
Historically, we have attempted to reduce our exposure to the volatility of
crude oil and natural gas prices by hedging a portion of our production. In a
typical hedge transaction, we 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, we are
required to pay the counter party all or a portion of this difference multiplied
by the quantity hedged, regardless of whether we have 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 us to make payments under the hedge agreements even though such payments
are not offset by sales of production. In the past, we have hedged up to 80% of
oil and natural gas production on an annualized basis. Hedging may also prevent
us from receiving the full advantage of increases in crude oil or natural gas
prices above the fixed amount specified in the hedge. For the year 2000, our
hedges are composed primarily of floors for both oil and natural gas. These
floors set a minimum price that we will receive on a certain amount of our daily
production, and allow us to receive all of the benefit of prices in excess of
these minimums. You can find more information regarding our hedging activity
beginning on Page 29.
Abandonment Costs
Government regulations and lease terms require all oil and natural gas
producers to plug and abandon platforms and production facilities at the end of
the properties' lives. Our reserve valuations include the estimated costs of
plugging the wells and abandoning the platforms and equipment on our properties.
These costs are usually higher on offshore properties, as are most expenditures
on offshore properties. As of December 31, 1999, our total estimated abandonment
costs, net of $5.6 million already in escrow, were approximately $15.7 million.
We account for those future liabilities by accruing for them in our
depreciation, depletion and amortization expense over the lines of each
property's total Proved Reserves.
Environmental and Other Regulations
Our operations are affected by extensive regulation through 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.
Our operations 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 us 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
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<PAGE>
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. In the past, we have agreed to indemnify sellers of producing
properties against certain liabilities for environmental claims associated with
those properties. We can not assure you that new laws or regulations, or
modifications of or new interpretations of existing laws and regulations, will
not substantially increase the cost of compliance or otherwise adversely affect
our oil and natural gas operations and financial condition or that material
indemnity claims will not arise with respect to properties that we acquire.
While we do not anticipate incurring material costs in connection with
environmental compliance and remediation, we cannot guarantee that material
costs will not be incurred.
Dependence Upon Key Personnel
Our success will depend almost entirely upon the ability of a small group
of key executives and technical staff to manage our business. Should one or more
of these employees leave or become unable to perform their duties, we can not
assure you that we will be able to attract competent new management.
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. We encounter competition from
various independent oil companies in raising capital and in acquiring producing
properties. Many of our competitors have financial resources and staffs
considerably larger than us. See "Business - Competition, Markets Seasonality
and Environmental and Other Regulation."
Item 2. Properties.
At December 31, 1999 our Proved Reserves totaled 135 Bcfe and had a Pretax
PV-10 value of $181.3 million. Approximately 60% of these reserves are
classified as Proved Developed Reserves and approximately 61% are natural gas.
Our 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. We
own interests in a total of 43 producing oil wells and 98 producing natural gas
wells. We also own interests in 23 federal blocks in the Gulf of Mexico and 9
state water blocks and we operate 66% of the 114 producing offshore wells, based
upon the Pretax PV-10 value as of December 31, 1999. Our non-operated offshore
properties are operated by large independents and major oil companies, including
Unocal, Newfield, Texaco, Coastal, Anadarko and Burlington. Our 27 producing
onshore wells account for 18% of our total Pretax PV-10 value as of December 31,
1999. We operate 52% of our onshore wells, based upon such Pretax PV-10 value.
We also own interests in 23 offshore production platforms and 109 miles of
offshore oil and natural gas pipelines with diameters of 10" or larger.
While we review many acquisition opportunities each year, and have made
several acquisitions under $5 million, we usually focus on larger acquisitions,
relative to the size of our company. Gulf Coast Region and more specifically,
Gulf of Mexico property acquisitions tend to have larger reserves and larger
purchase prices. We feel they usually also provide more exploitation and
development potential. Since 1991, we have made six acquisitions of producing
properties that had Proved Reserves of 159 Bcfe at the time of their respective
acquisitions. We paid a total of $106.4 million for the Proved Reserve component
of those acquisitions. By focusing on larger acquisitions, our reserve base is
concentrated in a small number of properties.
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<PAGE>
The following is a summary of our significant properties as of December 31,
1999. These properties represent 80% of the aggregate Pretax PV-10 value of our
Proved Reserves.
<TABLE>
<CAPTION>
Total Proved Reserves
-------------------------------------------
% of
Pretax PV-10 PANACO Total Pretax
Field Oi1 (MBbls) Natural Gas(Bcf) Value(000s) PV-10
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
East Breaks 165 3,989 20.3 $ 59,730 33%
Umbrella Point 1,255 12.9 26,841 15
East Breaks 160 995 9.5 24,869 14
West Delta 553 12.1 22,467 12
Price Lake 116 6.7 10,814 6
- - ------------------------------------------------------------------------------------------------
Total 6,908 61.5 $144,721 80%
</TABLE>
East Breaks 165
For information regarding the East Breaks 165 field, see "Business Strategy
- - - BP Acquisition."
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. We own
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 5 mile oil pipeline we own to our onshore production facility
at Cedar Point. Gas production is transported through a Midcon Pipeline Co.
pipeline.
We acquired this field in July 1997 as a part of the Goldking Acquisition.
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 we announced the successful completion
of our first new 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 production from this well peaked at 27,000 Mcf per
day of natural gas and 260 barrels of oil per day in July 1998. It declined to
600 Mcf of natural gas and 5 barrels of oil per day in December 1999. In that
month, we completed a workover on the well and brought the production back up to
18,600 Mcf of natural gas and 176 barrels of oil per day. We own an 80% working
interest in the well. The remaining 20% is owned by Peoples Energy Production.
East Breaks 160
We 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 some 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. from 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, we 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
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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 we believe that, due to the ongoing deepwater exploration in the Area,
our platform and pipelines can become long term strategic revenue generating
assets after the field reserves are depleted.
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 through May 1999 due to a third
party pipeline being shut in. We are the operator and generally own 100% of the
working interest in these wells. Presently, the properties have 36 wells, 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 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. In
February 2000 we completed a new well in Block 54, the #30 well. This new well
was drilled to 7500' and encountered and estimated 110' of producing formation.
The reserves in this well are primarily natural gas, adding approximately 6 Bcf
of net reserves.
We have allowed third party operators to drill several wells in Block 58
through farmout agreements. In return, we receive either a working interest or
overriding royalty interest in their wells at our option. We also process their
oil and some of their natural gas for a fee. In February 2000, Basin Exploration
completed a well that was farmed out from us in Block 58. Their well was drilled
to a subsea true vertical depth of 11,300' and logged in excess of 150' of net
oil and gas/condensate pay in multiple Miocene-aged sands. We retained a 10%
overriding royalty interest before payout with the option of either escalating
the overriding royalty interest to 12.5%, or converting to a 30% working
interest. In addition, not withstanding the forgoing terms, in the event the
completion is certain sands, our retained overriding royalty interest will
triple for the period of time in which our booked reserves are being produced.
During 1994, we 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. We
have a 15% overriding royalty interest in that acreage. The well is currently
producing 7,000 Mcf per day and 427 Bbls of condensate per day. Energy
Development Corporation was subsequently acquired by Samedan Oil Corporation.
In January 2000 we received a favorable judgement in a lawsuit we had filed
with our insurance carrier in 1996 related to the West Delta Fields. Our part of
the lawsuit was primarily for lost revenues in 1996 from a fire at Tank Battery
#3 which was caused by a third party service company. The judgement against the
service companies' insurance carrier was $1.1 million. Currently, we can not
estimate when we will recognize and receive the proceeds from this judgement.
Price Lake
For more information regarding the Price Lake Field, see "Business
Strategy-Price Lake Field."
Oil and Gas Information
Our reserve estimates are prepared by third party engineering firms who
prepare their reports based on information we provide them. The firms we use to
prepare these estimates are Ryder Scott Company, Netherland, Sewell and
Associates, Inc., W.D. Von Gonten and Co. and McCune Engineering. Ryder Scott
Company and Netherland, Sewell and Associates, Inc. prepare estimates for most
of our larger properties and account for 77% of the Pretax PV-10 of our reserve
estimates. Our proved oil reserves totaled 8.7 million barrels at December 31,
1999 compared to 7.5 million barrels at December 31, 1998. Our proved natural
gas reserves totaled 82.8 Bcf at December 31, 1999 as compared to 81.2 Bcf at
December 31, 1998. The Pretax PV-10 value of these reserves totaled $181 million
17
<PAGE>
at December 31, 1999 compared to $95 million at December 31, 1998. Despite
liquidity and capital resource we replaced 149% of our 1999 production which
totaled 18.1 Bcf equivalent. For more information related to our oil and natural
gas reserves, see "Supplemental Information Related to Oil and Gas Producing
Activities (Unaudited)," which is in Part IV, Item 14(a) in this Form 10-K.
Production, Price, and Cost Data
The following table presents certain production, price, and cost data with
respect to our properties for the three years ended December 31, 1997, 1998 and
1999.
<TABLE>
<CAPTION>
For the year ended December 31,
----------------------------------
1997 1998 1999(c)
<S> <C> <C> <C>
Oil and Condensate:
Net Production (Bbls)(a) 515,000 895,000 1,170,000
Revenue $ 9,354,000 $ 10,916,000 $ 22,025,000
Hedge gains (losses) $ (67,000) $ 2,034,000 $ (1,784,000)
Average net Bbl per day 1,411 2,452 3,204
Average price per Bbl before hedges $ 18.17 $ 12.20 $ 18.83
Average price per Bbl including hedges $ 18.04 $ 14.47 $ 17.31
Natural Gas:
Net Production (Mcf)(a) 11,468,000 18,041,000 11,114,000
Revenue $ 29,751,000 $ 36,910,000 $ 25,267,000
Hedge gains (losses) $ (1,197,000) $ 431,000 $ (2,836,000)
Average net Mcf per day 31,400 49,400 30,400
Average price per Mcf before hedges $ 2.59 $ 2.05 $ 2.27
Average price per Mcf including hedges $ 2.49 $ 2.07 $ 2.02
Total Revenues $ 37,841,000 $ 50,291,000 $ 42,672,000
Production costs $ 11,150,000 $ 18,148,000 $ 17,740,000
Total Production (Mcfe)(b) 14,557,000 23,411,000 18,132,000
Production cost per Mcfe(b) $ .77 $ .78 $ .98
</TABLE>
- - ----------------------
(a) Production information is net of all royalty interests. Beginning in 1999,
the MMS began taking its royalties in-kind rather than being paid in cash.
(b) Oil production is converted to Mcfe at the rate of 6 Mcf per Bbl, which
represents the estimated relative energy content of natural gas to oil.
(c) Several projects scheduled for 1999 were delayed due to capital
constraints.
Producing Wells(a)
The following table presents the number of producing oil and natural gas
wells, as of December 31, 1999, attributable to our properties.
<TABLE>
<CAPTION>
Producing Wells Company Operated
--------------- ----------------
<S> <C> <C>
Gross producing offshore wells(b):
Oil ..................................... 24 24
Natural Gas ............................. 90 40
-- --
Total ................................ 114 64
Net producing offshore wells(c):
Oil ..................................... 24 24
Natural Gas ............... 51 37
-- --
Total ................................ 75 61
18
<PAGE>
Gross producing onshore wells(b):
Oil ..................................... 19 16
Natural Gas ............................. 8 9
-- --
Total ................................ 27 25
Net productive onshore wells(c):
Oil ............... 9 7
Natural Gas ............... 5 4
-- --
Total ............................... 14 11
</TABLE>
- - ----------------------
(a) One or more completions in the same borehole are counted as one well.
(b) A "gross well" is a well in which we own a working interest.
(c) A "net well" is deemed to exist when the sum of the fractional working
interests in gross wells equals one.
<TABLE>
<CAPTION>
Leasehold Acreage
The following table presents the developed acreage as of December 31, 1999,
attributable to our properties.
<S> <C>
Developed onshore acreage(a):
Gross acres(b).................................... 3,728
Net acres(c)...................................... 1,843
Undeveloped onshore acreage(a):
Gross acres(b).................................... 3,887
Net acres(c)...................................... 1,145
Developed offshore acreage(a):
Gross acres(b).................................... 113,330
Net acres(c)...................................... 49,300
Undeveloped offshore acreage(a)(d):
Gross acres(b).................................... 3,667
Net acres(c)...................................... 2,587
</TABLE>
- - ----------------------
(a) Developed acreage is acreage assignable to producing wells.
(b) A "gross acre" is one in which we own a working interest.
(c) A "net acre" is deemed to exist when the sum of the fractional working
interests in gross acres equals one.
(d) In addition to these acres, our undeveloped offshore potential exists at
greater depths beneath existing producing reservoirs.
Drilling Activities
The following table presents the number of gross productive and dry wells
in which we had an interest, that were drilled and completed during the five
years ended December 31, 1999. You should not consider this to be indicative of
our future performance, nor should you assume that there is any correlation
between the number of productive wells drilled and the oil and natural gas
reserves generated from those wells or the costs of productive wells compared to
the costs 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>
1995 -- -- -- -- -- -- -- 3
1996 -- -- 2 -- -- -- -- --
1997 6 13 -- 1 -- -- -- --
1998 1 9 -- -- -- 3 -- 6
1999 1 -- -- -- -- 4 -- 3
--- --- --- --- --- --- --- ---
Total 8 22 2 1 -- 7 -- 12
</TABLE>
19
<PAGE>
Title to Oil and Gas Properties
When we acquire properties we obtain title opinions for our more
significant properties. Prior to the commencement of drilling operations we
conduct a thorough drill site title examination and perform any curative work
with respect to significant defects.
Item 3. Legal Proceedings.
An action was filed against us in Louisiana, along with 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 us and NEG, NEG is
required to indemnify us 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 us to assert our indemnity rights against NEG
is currently stayed. Our Counsel has prepared and may file a motion to lift the
stay so that we may assert its indemnification rights against NEG. But even if
we are successful in proving our right to indemnity, NEG's ability to satisfy
the judgement is questionable because of the bankruptcy.
Pursuant to another purchase and sale agreement, we may owe indemnity to
Shell and Exxon, from whom we acquired the property prior to selling same to
NEG. We may have insurance coverage for the claims asserted in the petition, and
have notified all insurance carriers that might provide coverage under our
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.
We are presently a party to several other legal proceedings, which we
consider to be routine and in the ordinary course of business. We have no
knowledge of any other pending or threatened claims that could give rise to any
litigation which would be material to the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5. Market for Common Stock and Related Shareholder Matters.
Our authorized capital shares consists of 100,000,000 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 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 our Certificate of
Incorporation.
Common Shares
We are authorized by our Certificate of Incorporation, as amended, to issue
100,000,000 Common Shares, of which 24,323,521 shares are issued and outstanding
as of March 20, 2000 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.
20
<PAGE>
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.
Warrants and Options We also have 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 and 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 our Certificate of Incorporation, we are authorized to issue
5,000,000 preferred shares, and the Board of Directors, by resolution, may
establish one or more classes or series of preferred shares having the number of
shares, designations, relative voting rights, dividend rates, liquidation and
other rights preferences, and limitations that the Board of Directors fixes
without any shareholder approval.
Transfer Agent
The transfer agent, registrar and dividend disbursing agent for our Common
Shares is American Stock Transfer and Trust Company, 6201 15th Avenue, Brooklyn,
New York 11204.
Price Range of Common Shares
Since September 1999, our Common Shares have been traded on the OTC
Bulletin Board under the symbol "PANA." Prior to that, our Common Shares were
traded on NASDAQ under the same symbol. 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.
<TABLE>
<CAPTION>
1999
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
<S> <C> <C> <C>
High $ 1-3/16 $ 1-3/16 $ 1-1/32 $ 5/8
Low $ 7/8 9/16 $ 17/32 $ 5/16
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
</TABLE>
On March 20, 2000, the last sale price of the Common Shares was $.90 per
share.
Dividend Policy
We have not paid any cash dividends on our Common Shares. The Delaware
General Corporation Law, to which we are subject, permits us to pay dividends
only out of our 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 Credit
Facility and the Senior Notes contain restrictions on any dividends or
21
<PAGE>
distributions and on any purchases of our Common Shares. We retain our cash flow
to finance the expansion and development of our business and currently do 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.
Certain Anti-takeover Provisions
In September 1998, the Board elected to redeem the Preferred Share Purchase
Right at its stated value of $.005 per Common Share.
The provisions of the 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 their best interests, including attempts
that might result in a premium over the market price for the shares held by our
shareholders. In addition, certain provisions of Delaware law and our Long-Term
Incentive Plan may be deemed to have a similar effect.
Certificate of Incorporation and By-laws. Our Board of Directors is divided
into three classes. The term of office of one class of directors expires at each
annual meeting of shareholders, when their successors are elected and qualified.
Directors are elected for three-year terms. Shareholders may remove a director
only for cause. In general, the Board of Directors, not our shareholders, has
the right to appoint persons to fill vacancies on the Board of Directors.
Pursuant to our Certificate of Incorporation, the 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 the Company.
Our Certificate of Incorporation also contains a "fair price" provision
that requires the affirmative vote of the holders of at least 80% of the voting
shares and the affirmative vote of at least two-thirds of our voting shares that
are not owned, directly or indirectly, by the Related Person to approve any
merger, consolidation, sale or lease of all or substantially all of our assets
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 our voting shares who is a party to the Transaction at issue, a
director who is also an officer and is a party to the Transaction at issue, an
affiliate of either such person, and certain transferees of those persons. The
voting requirements are not applicable to certain transactions, including those
that are approved by the Continuing Directors (as defined in the Certificate of
Incorporation) or that meet certain "fair price" criteria contained in the
Certificate of Incorporation.
Our 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.
Our 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, 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 us 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.
22
<PAGE>
The Certificate of Incorporation also restricts the ability of shareholders
to interfere with the powers of the Board of Directors in certain specified
ways, including the constitution and composition of committees and the election
and removal of officers.
The Certificate of Incorporation provides that approval by the holders of
at least two-thirds of the outstanding voting shares is required to amend the
provisions of the Certificate of Incorporation discussed in the preceding
paragraphs and certain other provisions, except that approval by the holders of
at least 80% of the outstanding voting shares, 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. We are a Delaware corporation and are
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 outstanding voting shares) from engaging in a "business
combination" (as defined in Section 203) with us 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 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 our voting shares
outstanding at the time the transaction commenced (excluding shares held by
directors who are also officers and by employee stock plans that do not provide
employees with the right to determine confidentially whether shares held subject
to the plan will be tendered in a tender or exchange offer), or (c) following
the transaction in which that person became an interested shareholder, the
business combination is approved by the Board of Directors 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 us 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 our
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 Long-Term
Incentive Plan may provide that, upon a change in control (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 Credit Facility and Senior Notes may also
impede a change in control, in that they provide that the Credit Facility and
Senior Notes become due if there is a change in the management 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.
Our Credit Facility would become due upon an increase in ownership of Common
Shares outstanding to over 30% of the then outstanding Common Shares.
23
<PAGE>
Item 6. Selected Financial Data.
The following historical data is derived from Consolidated Financial
Statements and the notes thereto. When reading this data, you should refer to
our audited consolidated financial statements and the related notes, both of
which are included in this Form 10-K.
<TABLE>
<CAPTION>
For the year ended December 31,
1995 1996 1997 1998 1999
------------------------------------------------------
(dollars in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Oil and natural gas sales $ 18,447 $ 20,063 $ 37,841 $ 50,291 $ 42,672
Lease operating expense 8,055 8,186 11,150 18,148 17,740
Depreciation, depletion & amortization
expense 8,064 9,022 18,866 37,500 26,439
General and administrative expense 690 1,063 1,919 4,629 4,069
Production and ad valorem taxes 1,078 559 721 1,351 1,202
Exploratory dry hole expense 8,112 -- 67 5,655 1,050
Geological and geophysical expense -- -- 286 1,927 1,429
Impairment of oil and gas properties 751 -- -- 20,406 13,202
Office consolidation and severance
expense -- -- -- 987 --
West Delta fire loss -- 500
------ ----- ----- ------ ------
Operating income (loss) $ (8,303) $ 733 $ 4,832 $ (40,312) $ (22,459)
Interest expense (net) 987 2,514 3,930 9,639 12,437
Income taxes (benefit) -- -- -- (3,100) --
Gain (loss) on investment in common
stock -- (258) 75 -- --
Extraordinary item-loss on early
retirement of debt -- -- (934) -- (131)
------ ----- ----- ------ ------
Net Income (loss) $ (9,290) $(2,039) $ 43 $(46,851) $ (35,027)
====== ===== ===== ====== ======
Net income (loss) per Common Share $ (0.81) $ (0.16) $ -- $ (1.96) $ (1.46)
Summary Balance Sheet Data:
Oil and gas properties (net) $ 29,485 $50,540 $112,548 $100,723 $ 88,888
Total assets 36,169 73,768 179,629 143,372 135,438
Long-term debt 22,390 49,500 101,700 115,749 138,902
Stockholders' equity (deficit) 9,174 17,498 55,188 7,902 (26,875)
Dividends per Common Share -- -- -- -- --
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
When reading the following discussion, you should also read our
Consolidated Financial statements and their notes, both of which are included in
this Form 10-K. The following discussion is our best assessment of our Company
and current operations. You should not assume that these results will continue.
You should also understand that due to numerous acquisitions, the results of
operations for the periods presented may not be necessarily comparative. See
"Business Strategy - Strategic Acquisitions and Mergers," beginning on Page 2
for further discussion of our acquisitions.
General
With the exception of historical information, the matters discussed in this
Form 10-K contain forward-looking statements. The forward-looking statements we
make, not only in this Form 10-K, but also in press releases, oral statements
24
<PAGE>
and other reports that we file with the Securities and Exchange Commission
("SEC") are intended to be subject to the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995. These statements relate to future
results of operations, the ability to satisfy future capital requirements, the
growth of our Company and other matters. You are cautioned that all
forward-looking statements involve risks and uncertainties. The words
"estimate," "anticipate," "expect," "predict," "believe" and similar expressions
are intended to qualify these forward-looking statements. We believe that the
forward-looking statements that we make are based on reasonable expectations.
However, due to the nature of the business we are in, we can not assure you that
the actual results of our Company will not differ from those expectations.
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 those products and other uncertainties
in the world energy markets. You should consider the volatility of this industry
when reading the following.
Year 2000 Issue
To address this issue, we established a Year 2000 ("Y2K") Compliance
Project Team consisting of representatives from Information Technology, Finance
and Operations. The Team designed a 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 Team contacted
third-party suppliers and customers to ascertain their state of readiness and
developed contingency plans as necessary. We passed the milestone of the turn of
the century with no major issues pertaining to the date change, and we do not
anticipate any in the future. The costs to be prepared for Y2K were immaterial
to our results of operations.
Liquidity and Capital Resources
In implementing our business strategy of increasing our reserve base and
cash flows from operations, we have reinvested our cash flows from operations
into capital expenditures. Our secondary source of capital expenditure resources
is our Credit Facility, which is also used for working capital support and
general corporate purposes. During 1999, our cash flows from operations totaled
$8 million and our borrowings under the Credit Facility increased $23 million
for our $26 million in capital expenditures. This left our balance under the
Credit Facility at $36.7 million, with availability of $16 million at December
31, 1999. During 1999 we sold several of our non-core properties for $1 million.
The properties we sold are non-operated, onshore and have relatively small
values. By selling these properties we also became more efficient as we can
focus our resources on our more significant properties. We plan to continuing
reviewing all of our remaining similar properties for potential sale.
For the year 2000, our Board of Directors has approved a $30 million
capital budget. This budget is based primarily on those resources available to
us at this time. We believe that our cash flows from operations and borrowings
under our Credit Facility will fund this level of capital expenditures and that
we will have sufficient availability under our Credit Facility to do so.
On October 9, 1997, we 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 our
outstanding indebtedness with the remaining $41.5 million used for capital
expenditures including the BP Acquisition.
On March 5, 1997, we 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 newly issued shares 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). Our net
proceeds of $22 million from the offering were used to prepay $13.5 million of
12% subordinated debt and the remainder was used to reduce borrowings under the
existing Credit Facility.
25
<PAGE>
Credit Facility
Our primary source of capital beyond discretionary cash flows is our Credit
Facility. Our Credit Facility is secured by a first mortgage on most of our oil
and natural gas properties, and is used primarily as development capital on
properties that we own. We may also use the Credit Facility for working capital
support, to provide letters of credit and general corporate purposes.
In September 1999 we put in place a new Credit Facility, with Foothill
Capital Corp. as the Agent, and includes Foothill Partners, L.P. and Ableco
Finance, a subsidiary of Cereberus Capital Management, L.P. This Credit Facility
is a $60 million line, with a term of two years, and extendable for an
additional year at our option. Borrowings under this Facility bear interest at
rates ranging from prime plus .5% up to prime plus 3.0% depending on the amounts
borrowed. We had $36.7 million outstanding at December 31, 1999. We will
continue to use this Facility in 2000 to fund part of our $30 million capital
budget.
The Credit Facility is a revolving credit agreement subject to monthly
borrowing base determinations. These determinations are made based on internally
prepared engineering reports, using a two year average of NYMEX future commodity
process and are based on our semi-annual third party reserve reports.
Indebtedness under this Credit Facility constitutes senior indebtedness with
respect to the Senior Notes.
Under the terms of this Credit Facility, we must maintain a ratio of
trailing twelve-month EBITDA to net interest expense of not less than 1.0 to 1.0
through December 31, 1999 and 1.5 to 1.0 from January 1, 2000 through the term
of the Facility. We must also maintain a working capital ratio, as defined in
the agreement, of not less than .25 to 1.0. Also, the Credit Facility contains
certain limitations on mergers, additional indebtedness and pledging or selling
assets. We were in compliance with those covenants on December 31, 1999 and
anticipate compliance throughout the term of the loan.
At December 31, 1999, 81% of our total assets were represented by oil and
natural gas properties, pipelines and equipment, net of depreciation, depletion
and amortization.
Results of Operations
<TABLE>
<CAPTION>
For the years ended December 31, 1999 and 1998:
"Oil and natural gas sales"
Production and Prices:
% Increase
1999 1998 (Decrease)
---- ---- ----------
<S> <C> <C> <C>
Natural gas production (MMcf) 11,114 18,041 (38%)
Average price per Mcf
excluding hedging $ 2.27 $ 2.05 11%
Average price per Mcf
including hedging $ 2.02$ 2.07 (2%)
Oil Production (MBbl) 1,170 895 31%
Average price per Bbl
excluding hedging $ 18.83 $ 12.20 54%
Average price per Bbl
including hedging $ 17.31 $ 14.47 20%
</TABLE>
Improvements in natural gas and oil prices during 1999 helped support our
revenues, while a decrease in natural gas production led to an overall decline
in revenues. Impairments of our unproved properties and on the High Island 309
Fields were contributing factors to our net loss of $35 million.
26
<PAGE>
During 1999, we hedged a total of 540,000 barrels of oil at an average
NYMEX equivalent flow price of $15.34 per barrel. These hedges were primarily
cost free collars, with 245,000 barrels having a floor of $15.00 and a cap of
$19.12 per barrel and 214,000 barrels having a floor of $15.00 and a cap of
$17.50 per barrel. We also hedged a total of 8.8 Bcf of natural gas at an
average NYMEX equivalent price of $2.14 per MMbtu.
The decrease in natural gas production in 1999 was primarily due to three
fields, the West Delta Fields, the High Island 309 Fields and the Umbrella Point
Field. High Island 309 production decreased 4.5 Bcf from 1998 due to natural
production declines, which was further complicated by compressor problems on
both the High Island 309 and 310 platforms. West Delta production decreased 1.1
Bcf due to shut-ins earlier in 1999 while the pipeline owned by Tennessee Gas
Pipeline was repaired along with the natural production decline of the wells.
Also, production from the Umbrella Point Field was accelerated in 1998 with the
successful completion of the SL 74 #10 well in January 1998. This well produced
as much as 27 MMcf per day in 1998 and has reduced since then. The change in
production from 1998 was a reduction of 2.4 Bcf. These decreases were somewhat
offset by an addition of 1.4 Bcf during 1999 from the East Breaks 165 Fields.
The Fields were acquired in May 1998 and produced for a full year in 1999.
The significant factor in our increased oil production was the acquisition
of the East Breaks 165 Field in May 1998, which is primarily an oil field.
"Lease operating expense" decreased in 1999 due to several factors. We sold
a group of non-core properties in 1999, which lowered these expenses. We also
implemented some cost reduction programs on several of the offshore properties
that we operate. A large percentage of the expenses associated with operating
oil and natural gas leases are fixed. Our decrease in production in 1999
accounted for the increase in expenses per unit, or Mcf equivalent ("Mcfe") of
production. We can significantly increase production on our properties without
increasing these operating expenses.
"Depreciation, depletion and amortization expense" decreased
proportionately with the decrease in total production. We also realized a lower
cost per unit of production in 1999, from $1.60 per Mcfe in 1998 to $1.46 in
1999.
"General and administrative expense" was $560,000 lower in 1999 primarily
due to a larger increase in our bad debt expense in 1998 versus 1999. Normal,
recurring general and administrative expenses have remained relatively flat.
"Exploratory dry hole expense" and "Geological and Geophysical expense" are
both representative of our decrease in exploratory projects in 1999 compared to
1998. During 2000, we plan to continue some participation in exploratory
projects, but we also plan to continue to do so at a modest level and percentage
of our capital budget.
"Impairment of oil and gas properties" in 1999 related to two property
groups. We impaired most of our unproved properties in order to reflect the lack
of planned drilling activity on those properties with associated unproved costs.
We have an extensive drilling program for 2000, however, the projects identified
do not include those properties that were impaired. We also impaired the
carrying value of our High Island 309 Fields due to unsuccessful workovers
completed during the fourth quarter. These unsuccessful workovers resulted in
reserve reductions of approximately 5 Bcf.
"Interest expense (net)" increased in 1999 as we increased our borrowing
levels over 1998. In early 1998 and throughout most that year, our Credit
Facility borrowing was relatively low, as we had cash available for capital
expenditures from our Senior Note Offering. We increased the Credit Facility
balance during 1999 to $36.7 million at December 31, 1999 compared to the
balance at December 31, 1998 of $13.5 million.
"Extraordinary item-loss on early retirement of debt" relates to a new
Credit Facility we put in place in September 1999 and the write off of costs
associated with the previous facility, that was prepaid.
27
<PAGE>
<TABLE>
<CAPTION>
For the years ended December 31, 1998 and 1997:
"Oil and natural gas sales"
Production and Prices:
% Increase
1998 1997 (Decrease)
---- ---- ----------
<S> <C> <C> <C>
Natural gas production (MMcf) 18,041 11,468 57%
Average price per Mcf
excluding hedging $ 2.05 $ 2.59 (21%)
Average price per Mcf
including hedging $ 2.07 $ 2.49 (17%)
Oil Production (MBbl) 895 515 74%
Average price per Bbl
excluding hedging $ 12.20 $ 18.17 (33%)
Average price per Bbl
including hedging $ 14.47 $ 18.04 (20%)
</TABLE>
The decreases in oil and natural gas prices we realized in 1998, in
combination with other key factors led to the significant loss in 1998. Price
declines led to a $20.4 million impairment of our 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 our Kansas City, Missouri office and the related
severance expense also contributed to the net loss for the year.
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 our increased natural gas production during 1998. 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. The primary factors in our increased oil production in
1998 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.
During 1998 we had natural gas hedged in quantities ranging from 10,000 to
50,000 MMbtu per day in each month 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.
Our 1998 oil hedge program improved the average net oil price we realized
by $2.27 per barrel. We hedged 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.
"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 our proved reserves. At December 31, 1998, the
average life of our proved reserves was approximately five and one-half years.
28
<PAGE>
"General and administrative expense" increased $2.7 million in 1998 due to
acquisitions we made in July 1997, April 1998 and May 1998. We also increased an
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 that we acquired in July 1997.
"Exploratory dry hole expense" reflects our increased exploratory
activities in 1998. Of the 19 wells we drilled or participated in during 1998,
six of the exploratory wells were not commercially productive. The wells were
operated by third parties and we owned working interests ranging from 10 to 20%.
"Geological and geophysical expense" during 1998 resulted from our
non-drilling exploratory activities.
"Impairment of oil and gas properties" represents an impairment of the book
value of our proved 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 our 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 our Senior Note
offering completed in October 1997. The increase is somewhat offset by a reduced
interest rate on a majority of long term debt. In connection with the offering,
we 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.
Item 7a. Qualitative and Quantitative Disclosure about Market Risks.
We follow a hedging strategy designed to protect against the possibility of
severe price declines due to unusual market conditions. We usually make hedging
decisions to assure a payout of a specific acquisition or development project or
to take advantage of unusual strength in the market.
During 1997, 1998 and 1999, we hedged a portion of our oil and natural gas
production in accordance with our hedging policy and as a requirement of our
Credit Facilities. During these periods, the hedges we entered into were either
swaps or cost free collars. The swaps were agreements to sell a certain quantity
of oil or natural gas in the future at a predetermined price. Cost free collars
ensured that we would receive a predetermined range of prices for our products.
Following is a summary of our historical hedging activity.
<TABLE>
<CAPTION>
Volume Hedged Percentage of Actual Production
Year Natural Gas (Bcf) Oil (MBbl) Natural Gas Oil Gain/(Loss)
---- ---------------------------- ----------- --- -----------
<S> <C> <C> <C> <C> <C>
1997 5.1 263 45% 51% ($1.3 million)
1998 12.0 463 67% 52% $2.5 million
1999 8.8 540 79% 46% ($4.6 million)
</TABLE>
For the year 2000, the Company has purchased options to put oil and natural
gas produced to a purchaser at an agreed upon price. The natural gas put option
is for 10,000 MMbtu per day at a NYMEX price of $2.04 per MMbtu. The Company
paid $366,000 for the put option which will be amortized over the period the
hedged item is produced, fiscal year 2000. The oil put option is for 1,000
barrels of oil per day beginning March 1 and continuing through December 31 at a
NYMEX price of $20.00 per barrel. The oil put option cost $275,000 and will also
be amortized over the period the hedge item is produced, fiscal year 2000. The
Company also has a small swap in place on an average of 232 barrels of oil for
each day at $17.00 per barrel. At December 31, 1999 the fair value of all of its
hedges was a loss of $800,000. The fair values of its hedges on December 31,
1998 and 1997 was a gain of $1.8 million and a loss of $61,000, respectively.
29
<PAGE>
The fair value of our commodity hedging instruments is the estimated amount
we 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 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 consolidated balance sheets
as of December 31, 1999 and 1998. A 10% change in commodity prices would not
have a material change in the fair value of our hedging instruments.
These hedge agreements provide for the counterparty to make payments to us
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 to make
payments to the counterparty to the extent market prices are greater than the
fixed prices.
At December 31, 1998 we 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, 1999, was $70 million. We also had $36.7 million
outstanding under our Credit Facility at December 31, 1999. The Credit Facility
is a floating rate facility, with a fair value of $36.7 million. We do not have
any interest rate hedge agreements at December 31, 1999.
Item 8. Financial Statements and Supplementary Data.
The financial statements are included herein beginning at F-1. The table of
contents at the front of the financial statements lists the financial statements
and schedules included therein.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
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, 1999. 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, 1999. 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, 1999. 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, 1999. Such information is incorporated herein by reference.
30
<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. No reports on Form 8-K were filed during the last
quarter of the period covered by this report:
(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.
4.6*** 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.
10.17 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.
10.23**** Employment contract between the Company and Larry M.
Wright.
31
<PAGE>
10.25 New credit agreement dated September 30, 1999 filed as an
exhibit on the Company's Form 10-Q on November 15, 1999,
and incorporated herein by reference.
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.
32
<PAGE>
GLOSSARY OF SELECTED OIL AND GAS TERMS
2-D Seismic. Seismic data and the related technology used to acquire and process
such data to yield a two-dimensional view of a "slice" of the subsurface.
3-D Seismic. Seismic data and the related technology used to acquire and process
such data to yield a three-dimensional picture of the subsurface. 3-D Seismic is
created by the propagation of sound waves through sedimentary rock layers, which
are then detected and recorded as they are reflected and refracted back to the
surface. By measuring the time taken for the sound to return and applying
computer technology to process the resulting data in volume, imagery of
significantly greater accuracy and usefulness than older-style 2-D Seismic can
be created.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalents converting one Bbl of
oil to six Mcf of natural gas.
Block. One offshore unit of lease acreage, generally 5,000 acres.
Btu. British Thermal Unit, the quantity of heat required to raise one pound of
water by one degree Fahrenheit.
Condensate. A hydrocarbon mixture that becomes liquid and separates from natural
gas when the gas is produced and is similar to crude oil.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole. A well found to be incapable of producing either oil or natural gas in
sufficient quantities to justify completion as an oil or natural gas well.
Estimated Future Net Revenues. Revenues from production of oil and natural gas,
net of all production-related taxes, lease operating expenses and capital costs.
Exploratory Well. A well drilled to find and produce oil or natural gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir.
Farmout. An agreement whereby the lease owner agrees to allow another to drill a
well or wells and thereby earn the right to an assignment of a portion or all of
the lease, with the original lease owner typically retaining an overriding
royalty interest and other rights to participate in the lease.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Group 3-D Seismic. Seismic procured by a group of parties or shot on a
speculative basis by a seismic company.
MBbl. One thousand Bbls of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalents converting one Bbl of
oil to six Mcf of natural gas.
Mcfe/d. Mcfe per day.
MMbbl. One million Bbls of oil or other liquid hydrocarbons.
MMbtu. One million Btu.
MMcf. One million cubic feet of natural gas.
33
<PAGE>
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.
Pretax PV-10. The present value of proved reserves is an estimate of the
discounted future net cash flows from oil and natural gas reserves at December
31, 1999, or as otherwise indicated. Net cash flow is defined as net revenues
less production and ad valorem taxes, future capital costs and operating
expenses, but before deducting federal income taxes. These 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,
1999, or as otherwise indicated.
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.
34
<PAGE>
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.
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.
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.
35
<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 March 27, 2000
----------------------- --------------
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 March 27, 2000
------------------------ --------------
Larry M. Wright,
Chief Executive Officer and
Director
By: \s\ Todd R. Bart March 27, 2000
------------------------ --------------
Todd R. Bart
Chief Financial Officer &
Principal Accounting Officer
By: \s\ Harold First March 27, 2000
------------------------ --------------
Harold First, Director
By: \s\ A. Theodore Stautberg March 27, 2000
------------------------ --------------
A. Theodore Stautberg, Director
By: \s\ James B. Kreamer March 27, 2000
------------------------ --------------
James B. Kreamer, Director
By: \s\ Richard Lampen March 27, 2000
------------------------ --------------
Richard Lampen, Director
By: ------------------------
Felix Pardo, Director
By: ------------------------
Stanley Nortman, Director
By: ------------------------
Mark C. Barrett, Director
By: ------------------------
Donald Chesser, Director
36
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, 1999 and 1998 F-4
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998 and 1997 F-6
Consolidated Statements of Changes in Stockholders' Equity (Deficit)
for the Years Ended December 31, 1999, 1998 and 1997 F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997 F-8
Notes to Consolidated Financial Statements for the Years Ended
December 31, 1999, 1998 and 1997 F-10
F-1
<PAGE>
Independent Auditors' Report
The Board of Directors and Shareholders PANACO, Inc.:
We have audited the accompanying consolidated balance sheets of PANACO, Inc. and
subsidiaries as of December 31, 1999 and 1998, and the related consolidated
statements of operations, changes in stockholders' equity (deficit), and cash
flows for the years 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, 1999 and 1998, and the results of their
operations and their cash flows for the years then ended in conformity with
generally accepted accounting principles.
KPMG LLP
Houston, Texas
March 20, 2000
F-2
<PAGE>
Report of Independent Public Accountants
To the Stockholders and Board of Directors of PANACO, Inc.:
We have audited the accompanying consolidated statements of operations, changes
in stockholders' equity (deficit) and cash flows of PANACO, INC. (a Delaware
Corporation) and Subsidiaries for the year ended December 31, 1997. The
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these 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 presents
fairly, in all material respects, the results of operations and cash flows of
PANACO, Inc. and Subsidiaries for the year ended December 31, 1997, in
conformity with generally accepted accounting principles.
Arthur Andersen LLP
Kansas City, Missouri
April 7, 1998
F-3
<PAGE>
PANACO, Inc.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
ASSETS
------
December 31,
------------
1999 1998
---- ----
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 5,575,000 $ 3,452,000
Accounts receivable 9,675,000 8,332,000
Accounts receivable-employee 16,000 18,000
Prepaid and other 729,000 268,000
----------- -----------
Total current assets 15,995,000 12,070,000
----------- -----------
OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
Oil and gas properties, proved 262,043,000 238,377,000
Oil and gas properties, unproved 15,672,000 15,128,000
Less accumulated depreciation, depletion and amortization (188,827,000) (152,782,000)
----------- -----------
Net oil and gas properties 88,888,000 100,723,000
----------- -----------
PIPELINES AND EQUIPMENT
Pipelines and equipment 26,327,000 26,252,000
Less accumulated depreciation (6,130,000) (3,415,000)
----------- -----------
Net pipelines and equipment 20,197,000 22,837,000
----------- -----------
OTHER ASSETS
Restricted deposits 5,602,000 3,719,000
Deferred financing costs, net 4,456,000 3,359,000
Employee note receivable 300,000 300,000
Other -- 364,000
----------- -----------
Total other assets 10,358,000 7,742,000
----------- -----------
TOTAL ASSETS $ 135,438,000 $ 143,372,000
============= =============
(Continued)
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
<TABLE>
<CAPTION>
December 31,
------------
1999 1998
---- ----
CURRENT ASSETS
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable $ 20,408,000 $ 16,976,000
Interest payable 3,003,000 2,745,000
Revolving credit facility -- 13,500,000
----------- -----------
Total current liabilities 23,411,000 33,221,000
----------- -----------
LONG-TERM DEBT 138,902,000 102,249,000
COMMITMENTS AND CONTINGENCIES -- --
STOCKHOLDERS' EQUITY (DEFICIT)
Preferred Shares, $.01 par value,
5,000,000 shares authorized; no
shares issued and outstanding -- --
Common Shares, $.01 par value,
100,000,000 shares authorized;
23,986,521 and 24,009,605 shares
issued; and 23,986,521 and 23,704,955
outstanding, respectively 243,000 240,000
Treasury stock, 304,650 shares held at cost -- (592,000)
Additional paid-in capital 68,852,000 69,197,000
Accumulated deficit (95,970,000) (60,943,000)
----------- -----------
Total Stockholders' Equity (Deficit) (26,875,000) 7,902,000
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) $ 135,438,000 $ 143,372,000
============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
REVENUES
Oil and natural gas sales $ 42,672,000 $ 50,291,000 $ 37,841,000
COSTS AND EXPENSES
Lease operating expense 17,740,000 18,148,000 11,150,000
Depreciation, depletion and amortization 26,439,000 37,500,000 18,866,000
General and administrative expense 4,069,000 4,629,000 1,919,000
Production and ad valorem taxes 1,202,000 1,351,000 721,000
Exploratory dry hole expense 1,050,000 5,655,000 67,000
Geological and geophysical expense 1,429,000 1,927,000 286,000
Impairment of oil and gas properties 13,202,000 20,406,000 --
Office consolidation and severance expense -- 987,000 --
----------- ----------- -----------
Total 65,131,000 90,603,000 33,009,000
----------- ----------- -----------
OPERATING INCOME (LOSS) (22,459,000) (40,312,000) 4,832,000
----------- ----------- -----------
OTHER INCOME (EXPENSE)
Gain on investment in common stock -- -- 75,000
Interest income 255,000 849,000 745,000
Interest expense (12,692,000) (10,488,000) (4,675,000)
----------- ----------- -----------
Total (12,437,000) (9,639,000) (3,855,000)
----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME
TAXES AND EXTRAORDINARY ITEM (34,896,000) (49,951,000) 977,000
INCOME TAXES (BENEFIT) -- (3,100,000) --
----------- ----------- -----------
INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM (34,896,000) (46,851,000) 977,000
EXTRAORDINARY ITEM - Loss on early
retirement of debt (131,000) -- (934,000)
----------- ------------ -----------
NET INCOME (LOSS) $(35,027,000) $ (46,851,000) 43,000
============ ============= ===========
BASIC AND DILUTED EARNINGS (LOSS)
PER SHARE
Income (loss) before extraordinary item $ (1.45) $ (1.96) $ .05
Extraordinary item (.01) -- (.05)
----------- ----------- -----------
Net income (loss) $ (1.46) $ (1.96) $ --
============ ============ ============
BASIC SHARES OUTSTANDING 23,940,785 23,884,091 20,781,205
============ ============ ============
DILUTED SHARES OUTSTANDING 23,940,785 23,884,091 21,024,847
============ ============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
<TABLE>
<CAPTION>
Total
Number of Common Additional Stockholders'
Common Share Paid-In Treasury Accumulated Equity
Shares Par Value Capital Stock Deficit (Deficit)
------ --------- ------- ----- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Balances, December 31, 1996 14,350,255 $ 143,000 $ 31,490,000 $ -- $(14,135,000) $ 17,498,000
Net income -- -- -- -- 43,000 43,000
Exercise of warrants, shares issued under
Employee Stock Ownership Plan and
Director and employee stock bonuses 324,346 3,000 783,000 -- -- 786,000
Issuance of warrants to retire debt -- -- 450,000 -- -- 450,000
Acquisition of properties 3,238,930 33,000 14,381,000 -- -- 14,414,000
Issuance of new shares 6,000,000 60,000 21,937,000 -- -- 21,997,000
---------- ------- ---------- ------- ---------- ----------
Balances, December 31, 1997 23,913,531 239,000 69,041,000 -- (14,092,000) 55,188,000
Net loss -- -- -- -- (46,851,000) (46,851,000)
Shares issued under Employee
Stock Ownership Plan and
Director stock bonuses 96,074 1,000 274,000 -- -- 275,000
Shareholder rights redemption -- -- (118,000) -- -- (118,000)
Purchase of treasury stock (304,650) -- -- (592,000) -- (592,000)
-------- -------- ---------- ------- ---------- ----------
Balances, December 31, 1998 23,704,955 240,000 69,197,000 $(592,000) (60,943,000) 7,902,000
Net loss -- -- -- -- (35,027,000) (35,027,000)
Shares issued under Employee
Stock Ownership Plan 281,566 3,000 247,000 -- -- 250,000
Cancellation of treasury stock -- -- (592,000) 592,000 -- --
---------- ------- ---------- ------- ---------- ----------
Balances, December 31, 1999 23,986,521 $ 243,000 $68,852,000 $ -- $(95,970,000) $(26,875,000)
========== ======== ========== ======= =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-7
<PAGE>
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (35,027,000) $ (46,851,000) $ 43,000
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Extraordinary item 131,000 -- 934,000
Depreciation, depletion and amortization 26,439,000 37,500,000 18,866,000
Impairment of oil and gas properties 13,202,000 20,406,000 --
Exploratory dry hole expense 1,050,000 5,655,000 67,000
Deferred income tax benefit -- (3,100,000) --
Gain on investment in common stock -- -- (75,000)
ESOP stock contribution expense -- 275,000 165,000
Changes in operating assets and liabilities:
Accounts receivable (1,343,000) 1,403,000 (969,000)
Related party note receivable 2,000 (318,000) --
Prepaid and other (97,000) 572,000 129,000
Accounts payable 3,682,000 (249,000) 4,172,000
Interest payable 258,000 329,000 1,822,000
---------- ---------- ----------
Net cash provided by operating activities 8,297,000 15,622,000 25,154,000
---------- ---------- ----------
CASH FLOWS USED IN INVESTING ACTIVITIES
Proceeds from the sale of oil and gas properties 1,036,000 23,000 87,000
Proceeds from the sale of investment in common stock -- -- 1,717,000
Capital expenditures and acquisitions (26,429,000) (61,253,000) (41,997,000)
Increase in restricted deposits (1,883,000) (1,463,000) (141,000)
---------- ---------- ----------
Net cash used in investing activities (27,276,000) (62,693,000) (40,334,000)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt proceeds 47,153,000 46,049,000 112,459,000
Repayment of long-term debt (24,000,000) (32,000,000) (84,742,000)
Issuance of common shares -- 275,000 22,636,000
Additional deferred financing costs (2,051,000) -- --
Acquisition of treasury stock -- (592,000) --
Shareholder rights redemption -- (118,000) --
---------- ---------- ----------
Net cash provided by financing activities 21,102,000 13,614,000 50,353,000
---------- ---------- ----------
NET INCREASE (DECREASE) IN CASH $ 2,123,000 $ (33,457,000) $ 35,173,000
CASH AT BEGINNING OF YEAR 3,452,000 36,909,000 1,736,000
---------- ---------- ----------
CASH AT END OF YEAR $ 5,575,000 $ 3,452,000 $ 36,909,000
========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
F-8
<PAGE>
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
For the year ended December 31, 1999:
- - -------------------------------------
The Company issued 281,566 common shares valued at $250,000 to the ESOP. The
change in accounts payable from December 31, 1998 to December 31, 1999 excludes
this non-cash reduction of the liability.
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.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year ended December 31:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Interest $12,978,000 $11,338,000 $3,297,000
=========== =========== ==========
Income taxes $ -- $ -- $ --
=========== =========== ==========
</TABLE>
F-9
<PAGE>
PANACO, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
- - ------------------
PANACO, Inc. and subsidiaries (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. The
Company's subsidiaries are consolidated as wholly-owned subsidiaries.
Revenue Recognition
- - -------------------
The Company recognizes its ownership interest in oil and gas production as
revenue. Gas balancing arrangements with partners in natural gas wells are
accounted for by the entitlements method. At December 31, 1999 and 1998 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 swap contracts and put options within the normal course of
its business. The Company uses swap contracts and put options to reduce the
effects of fluctuations in oil and natural gas prices (see Note 7). To qualify
as hedging instruments, swaps or put options must be highly correlated to
anticipated future sales such that the Company's exposure to the risk of
commodity price changes is reduced. Changes in the market value of swap
contracts or put options that are designated as hedges are deferred and
subsequent gains and losses are recognized monthly as adjustments to revenues in
the same production period as the hedged production. 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
initially 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.
F-10
<PAGE>
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
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
approved reserves. The Company recorded an asset impairment in 1999 of $13.2
million for unproved properties that the Company did not have current plans to
develop and for a reserve reduction in the High Island 309 Fields. The Company
also 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 1999, 1998 and 1997 was $544,000, $936,000
and $513,000, 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.
F-11
<PAGE>
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. In 1999 and 1998 the Company had options
outstanding that were exercisable at prices above the market. Due to losses in
1999 these shares are not considered dilutive and are not included in per share
calculations.
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, 1999 and 1998 accounts receivable are net of an allowance of
$830,000 and $1 million, respectively. 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
------------
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.
F-12
<PAGE>
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.
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
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
$337,000, $275,000 and $165,000 in costs for the years ended December 31, 1999,
1998 and 1997, 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 RLI, Underwriter's
Indemnity. This trust required an initial funding of $846,720 in December 1996,
and remaining deposits of $250,000 due at the end of each quarter until the
balance in the account reaches $5.4 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.
F-13
<PAGE>
Note 5 - LONG-TERM DEBT
--------------
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
10 5/8 % Senior Notes due 2004(a) $100,000,000 $100,000,000
Revolving credit facility due 2001(b) 36,653,000 13,500,000
Production payment(c) 2,249,000 2,249,000
----------- -----------
138,902,000 115,749,000
Less current portion -- 13,500,000
Long-term debt ------------ ------------
$138,902,000 $102,249,000
============ ============
</TABLE>
- - ------------
(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
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 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. The holders of the Senior Notes have
acceleration rights, subject to certain grace periods, if the Company is in
default under the credit facility.
(b) In October 1999 the Company put in place a new credit facility. The loan is
a reducing revolver which will provide the Company with up to $60 million,
depending on the borrowing base. The Company's borrowing base at December 31,
1999 was $55.1 million, with availability of $16.2 million. The principal amount
of the loan is due September 30, 2001, and may be extended for an additional
year. Interest on the loan is computed at Wells Fargo's prime rate plus .5% to
3.0%, depending on the percentage of the facility being used. The Credit
Facility is collateralized by a first mortgage on the Company's properties. The
loan agreement contains certain covenants including an EBITDA (as defined in the
agreement) to interest expense ratio of at least 1.5 to 1.0 and a working
capital ratio (as defined in the agreement) of at least .25 to 1.0. The loan
agreement also contains limitations on additional debt, dividends, mergers and
sales of assets.
The Company's previous credit facility was more restrictive and included
covenants that the Company was not in compliance with at December 31, 1998.
These covenant violations were remedied by waivers, but the Company most likely
would not have been in compliance with them for the entire year had the new
credit facility not been put in place.
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 1999 the Company replaced its credit facility, see Note 5. In connection with
the prepayment of the previous credit facility, the Company wrote off the
remaining deferred financing costs associated with the previous facility.
In October 1997, the Company issued $100 million of 10.625% Senior Notes due
2004, see Note 5. A portion of the proceeds from the offering was used to repay
or prepay substantially all of the Company's outstanding indebtedness. With the
early retirement of the debt, the Company incurred a $ 484,000 charge to
write-off the deferred financing costs associated with the previous debt
facilities. In addition, as part of the prepayment of the convertible
subordinated notes, the Company issued 2,060,606 warrants to acquire common
shares at an exercise price of $4.125 per share which were the existing
conversion terms of the prepaid notes. The fair value of these warrants has been
estimated by an investment banker to be approximately $450,000, which has been
recorded as an extraordinary item and additional paid-in capital.
Note 7 - COMMODITY HEDGE AGREEMENTS
--------------------------
During 1997, 1998 and 1999, the Company hedged a portion of its oil and natural
gas production in accordance with its hedging policy and as a requirement of its
credit facilities. During these periods, the hedges entered into by the Company
were either swaps or cost free collars. The swaps were agreements to sell a
certain quantity of oil or natural gas in the future at a predetermined price.
Cost free collars ensured that the Company would receive a predetermined range
of prices for its products.
<TABLE>
<CAPTION>
Volume Hedge Percentage of Actual Production
Year Natural Gas (BCF) Oil (MBbl) Natural Gas Oil Gain/(Loss)
---- ---------------------------- ------------------ -----------
<S> <C> <C> <C> <C> <C>
1997 5.1 263 45% 51% ($1.3 million)
1998 12.0 463 67% 52% $2.5 million
1999 8.8 540 79% 46% ($4.6 million)
</TABLE>
For the year 2000, the Company has purchased options to put oil and natural gas
produced to a purchaser at an agreed upon price. The natural gas put option is
for 10,000 MMbtu per day at a NYMEX price of $2.04 per MMbtu. The Company paid
$366,000 for the put option which will be amortized over the period the hedged
item is produced, fiscal year 2000. The oil put option is for 1,000 barrels of
oil per day beginning March 1 and continuing through December 31 at a NYMEX
price of $20.00 per barrel. The oil put option cost $275,000 and will also be
amortized over the period the hedge item is produced, fiscal year 2000. The
Company also has a small swap in place on an average of 232 barrels of oil for
each day at $17.00 per barrel. At December 31, 1999 the fair value of all of its
hedges was a loss of $800,000. The fair values of its hedges on December 31,
1998 and 1997 was a gain of $1.8 million and a loss of $61,000, respectively.
F-15
<PAGE>
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, 1999
and 1998. A 10% change in commodity prices would not have a material change in
the fair value of our hedging instruments.
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 when the exercise price is equal to or greater than the market value of
the Company's common stock on the date of an options grant. On June 18, 1997,
1.2 million 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.
<TABLE>
<CAPTION>
1999 1998 1997
--------------------- ---------------------- ---------------------
Wtd. Wtd. Wtd.
Avg. Avg. Avg.
Shares Ex. Price Shares Ex. Price Shares Ex. Price
------ --------- ------ --------- ------ ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 1,150,000 $ 4.45 1,190,000 $ 4.45 289,365 $ 2.21
Granted 0 -- 0 -- 1,200,000 4.45
Exercised 0 -- 0 -- (289,365) 2.21
Forfeited -- 4.45 (40,000) 4.45 (10,000) 4.45
--------- ----- --------- ----- --------- -----
Outstanding at end of year 1,150,000 4.45 1,150,000 4.45 1,190,000 4.45
--------- --------- ---------
Exercisable at end of year 1,150,000 $ 4.45 1,150,000 $ 4.45 1,190,000 $ 4.45
Fair value of options granted N/A N/A $ 1.42
</TABLE>
The fair value of each option in 1997 was estimated at the date of grant using
the Black-Scholes Modified American Option Pricing Model with the following
assumptions:
Expected option life-year 3
Risk-free interest rate 6.1%
Dividend yield 0%
Volatility 38.4%
F-16
<PAGE>
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 1999 and 1998
would have been as shown below:
<TABLE>
<CAPTION>
1999 1998
------------ ------------
<S> <C> <C>
Net loss As reported $(35,027,000) $(46,851,000)
-------- Pro forma $(35,311,000) $(47,133,000)
Net per share: As reported $ (1.46) $ (1.96)
------------- Pro forma $ (1.47) $ (1.97)
</TABLE>
Note 9 - MAJOR CUSTOMERS
---------------
In 1999, the purchaser for a majority of the Company's oil production accounted
for 37% of total revenues in 1999, while the purchaser for a majority of the
Company's gas production accounted for 39% of total revenues in 1999. One
purchaser accounted for 42% and 62% of revenues in 1998 and 1997, respectively.
These transactions represented spot sales of natural gas to one customer.
Note 10 - INCOME TAXES
------------
At December 31, 1999, the Company had net operating loss carry forwards for
federal income tax purposes of approximately $104 million which are available to
offset future federal taxable income through 2019. The Company's timing of its
utilization of a portion of its 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's common stock.
Significant components of the Company's deferred tax assets (liabilities) as of
December 31 are as follows:
<TABLE>
<CAPTION>
1999 1998
---------- -----------
<S> <C> <C>
Deferred tax assets (liabilities)
Fixed asset basis differences $(10,119,000) $ (388,000)
Net operating loss carry forwards 36,309,000 14,207,000
State Taxes 2,486,000 1,461,000
Other 297,000 410,000
----------- -----------
Total deferred tax assets (liabilities) 28,973,000 15,690,000
----------- -----------
Valuation allowance for deferred
tax assets (28,973,000) (15,690,000)
----------- -----------
Total deferred tax assets (liabilities) $ -- $ --
=========== ===========
</TABLE>
At December 31, 1999 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 $13,283,000.
F-17
<PAGE>
Total income taxes were different than the amounts computed by applying the
statutory income tax rate to income before income taxes. The sources of these
differences are as follows:
<TABLE>
<CAPTION>
1999 1998
------ ------
<S> <C> <C>
Before any valuation allowance
Statutory federal income tax rate (35.00%) (35.00%)
State income taxes, net of federal benefit (2.92) (2.92)
Other 0.00 0.31
Adjustments to valuation allowance 37.92 31.40
----- -----
0.00% (6.21%)
===== =====
</TABLE>
Note 11 - COMMITMENTS AND CONTINGENCIES
-----------------------------
An action was filed against the Company in Louisiana, along with 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 indemnity
rights against NEG is currently stayed. The Company's Counsel has 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 ability to satisfy the judgement is
questionable because of the bankruptcy.
Pursuant to another purchase and sale agreement, the Company may owe indemnity
to Shell and Exxon, from whom it acquired the property prior to selling same to
NEG. The Company may have insurance coverage for the claims asserted in the
petition, and has notified all insurance carriers that might provide coverage
under its 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.
The Company is subject to various other 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, 1999, the future minimum rental payments due under the lease are
as follows:
2000 $ 336,000
2001 $ 389,000
2002 $ 102,000
----------
Total $ 827,000
==========
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:
<TABLE>
<CAPTION>
1999 1998 1997
--------- ---------- ----------
<S> <C> <C> <C>
Property acquisition costs, proved $ -- $ 9,877,000 $39,384,000
Property acquisition costs, unproved 544,000 1,245,000 6,026,000
Exploration expenses 2,479,000 7,582,000 353,000
Development costs 24,777,000 29,957,000 29,276,000
</TABLE>
Quantities of Oil and Gas Reserves
- - ----------------------------------
The estimates of proved reserve quantities at December 31, 1999, 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.
<TABLE>
<CAPTION>
Proved developed and undeveloped reserves: Oil Gas
(BBLS) (MCF)
------ -----
<S> <C> <C>
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
Production (1,170,000) (11,114,000)
Extensions and discoveries 123,000 13,975,000
Sale of minerals in-place (50,000) (700,000)
Revisions of previous estimates 2,336,000 (642,000)
---------- ----------
Estimated reserves as of December 31, 1999 8,693,000 82,768,000
========== ==========
F-19
<PAGE>
Proved developed reserves: Oil Gas
(BBLS) (MCF)
------ -----
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
========== ==========
December 31, 1999 5,351,000 40,627,000
========== ==========
</TABLE>
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, 1999 averaged $24.99 per barrel of
oil and $2.43 per Mcf 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>
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows $ 420,060,000 $ 259,071,000 $ 269,141,000
Future development and production costs (167,631,000) (129,744,000) (102,114,000)
------------- ------------- -------------
Future net cash flows 252,429,000 129,327,000 167,027,000
10% annual discount (71,163,000) (34,747,000) (37,995,000)
- - -- ------------- ------------- -------------
Pretax PV-10 value 181,266,000 94,580,000 129,032,000
Future income taxes, discounted
at 10% -- -- (8,160,000)
------------- ------------- -------------
Standardized measure after income taxes $ 181,266,000 $ 94,580,000 $ 120,872,000
============= ============= =============
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:
1999 1998 1997
----------- ----------- -----------
Beginning balance $ 94,580,000 $ 120,872,000 $ 99,841,000
Sales of oil and gas, net of production costs (23,632,000) (30,692,000) (25,815,000)
Net change in income taxes -- 8,160,000 5,465,000
Changes in price and production costs 59,928,000 (42,711,000) (32,461,000)
Purchases of minerals in-place -- 23,657,000 40,027,000
Sale of minerals in-place (1,037,000) (514,000) --
Revision of previous estimates, extensions &
discoveries, net 51,427,000 15,808,000 33,815,000
------------ ------------- -------------
Ending balance $181,266,000 $ 94,580,000 $ 120,872,000
============ ============= =============
F-20
</TABLE>
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 5575000
<SECURITIES> 0
<RECEIVABLES> 10521000
<ALLOWANCES> (830000)
<INVENTORY> 0
<CURRENT-ASSETS> 15995000
<PP&E> 304042000
<DEPRECIATION> (194957000)
<TOTAL-ASSETS> 135438000
<CURRENT-LIABILITIES> 23411000
<BONDS> 138902000
0
0
<COMMON> 243000
<OTHER-SE> (27118000)
<TOTAL-LIABILITY-AND-EQUITY> 135438000
<SALES> 42672000
<TOTAL-REVENUES> 42672000
<CGS> 0
<TOTAL-COSTS> 65131000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 12437000
<INCOME-PRETAX> (34896000)
<INCOME-TAX> 0
<INCOME-CONTINUING> (34896000)
<DISCONTINUED> 0
<EXTRAORDINARY> (131000)
<CHANGES> 0
<NET-INCOME> (35027000)
<EPS-BASIC> (1.46)
<EPS-DILUTED> (1.46)
</TABLE>
