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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 0-26662
PANACO, Inc.
(Exact name of registrant as specified in its charter)
Delaware 43 - 1593374
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
1100 Louisiana, Suite 5100
Houston, TX 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
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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 $12,512,889 as of March 25, 2002.
24,359,695 Shares of the registrant's Common Stock were outstanding
as of March 25, 2002.
Documents Incorporated by Reference
Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 2001, are incorporated by reference into Part III.
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PANACO, Inc.
Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2001
Table of Contents Page Number
Part I
Item 1. Business 2
Item 2. Properties 17
Item 3. Legal Proceedings 23
Item 4. Submission of Matters to a Vote of Security Holders 23
Part II
Item 5. Market for Common Stock and Related Shareholder Matters 23
Item 6. Selected Financial Data 27
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 28
Item 7a. Qualitative and Quantitative Disclosure About Market Risks 37
Item 8. Financial Statements and Supplementary Data 38
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 38
Part III
Item 10. Directors and Executive Officers of the Registrant 39
Item 11. Executive Compensation 39
Item 12. Security Ownership of Certain Beneficial Owners and Management 39
Item 13. Certain Relationships and Related Transactions 40
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 40
Glossary of Selected Oil and Gas Terms 42
Signatures 45
1
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. For
information concerning some of the most significant risks which may affect
PANACO's operations, see "Risk Factors." 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 cannot assure you that the actual
results 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
and two former 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 42. 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
http://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 surrounding the Gulf, which we collectively refer
to as the Gulf Coast Region. The Company acquires producing properties with a
view toward further exploitation and development, capitalizing on
state-of-the-art 3-D Seismic and advanced directional drilling technology to
recover reserves that were bypassed or previously overlooked. Emphasis is also
placed on pipeline and other infrastructure to provide transportation,
processing and tieback services to neighboring operators. We are in the business
of selling oil and natural gas, produced on properties we lease, to third party
purchasers. We obtain reserves of crude oil and natural gas by either buying
them from others or drilling developmental and exploratory wells on acquired
properties. We acquired our first property in the Gulf of Mexico in 1991 and
have acquired several other properties in the Gulf Coast Region and Gulf of
Mexico over the past ten years. We have grown not only through acquisitions in
each of those years but also by further developing the properties we have
acquired. We have acquired 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 of the Goldking Companies in 1997.
Due to substantial losses incurred in 1999 and 2001 and less than
anticipated results from PANACO's drilling program in late 2000 and most of
2001, the Company accumulated a significant working capital deficit as of
December 31, 2001. The deficit totaled $24.4 million. The lack of performance
from wells drilled during 2000 and 2001, along with decreased commodity prices
in late 2001, reduced estimated future net cash flows to a point at which there
is substantial doubt about the Company's ability to reduce this deficit in a
timely manner. See Note 2 to our financial statements.
2
In March 2002, the Credit Facility, with borrowings of $32.9 million,
was amended in order to cure covenants that we were not able to satisfy on
December 31, 2001. This amendment requires a working capital ratio (as defined
in the agreement) of 0.15 to 1.0 from January 1 to April 30, 2002, 0.20 to 1.0
from May 1 to January 1, 2003, and 0.25 to 1.0 thereafter. The amendment also
requires a trailing twelve-month EBITDA/interest coverage ratio ranging from a
monthly high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002, and 2.0 to
1.0 thereafter. Based on current projections, we believe we will be in
compliance with all of the terms of the Credit Facility through December 31,
2002. However, no assurances can be given that we will be in compliance through
December 31, 2002. PANACO's $100 million of Senior Notes require that we
maintain a total Adjusted Consolidated Net Tangible Asset Value ("ACNTA"),
as defined in the Indenture, 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. At December 31, 2001 PANACO did not meet this ratio. Actual
results through March 31, 2002 are not yet available, however, based on
increased market prices for oil and natural gas, we estimate that the Company
will be in compliance with the covenant at March 31, 2002. However, no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.
Given these issues, PANACO engaged an investment bank in early 2002 to
help the Company explore strategic financial alternatives. The outcome of this
process may result in asset sales or the sale of the Company as a whole. No
assurances can be made that the Company will be able to implement any plan that
will resolve the working capital deficit, ensure we maintain compliance with our
Credit Facility and Senior Note covenants, or that a plan will be implemented in
a timely manner and, as a result, the Company may not be able to continue as a
going concern. In addition, any of these alternatives will most likely require
approval from PANACO's Credit Facility lenders and may require the approval of
our Senior Note holders as well as Shareholder approval. See Note 2 to our
financial statements.
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 property acquisitions,
which are described below, we have an inventory of development and exploration
projects that provide additional reserve potential. The key elements of our
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, 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, have 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
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
ownership 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.
3
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 exploring on Gulf Coast Region
properties. We believe that we are regarded in the industry as a competent buyer
with the proven ability to close transactions in a timely manner. Below are
highlights of some of our more significant acquisitions.
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")
for $19.6 million in cash and accounted for the acquisition as a purchase. The
purchase included 3-D Seismic data which covers 20 offshore blocks. PANACO
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 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
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.
Amoco Acquisition
In October 1996 we acquired interests in six offshore fields from Amoco
Production Company, now BP Amoco ("BP"). We paid BP $32 million in cash and
issued them 2 million shares of common stock in consideration for the
properties. All of the properties we acquired from BP are operated by third
parties, which are Unocal, Texaco, Coastal Oil and Gas (now El Paso Energy
Corp.) and Newfield Exploration.
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 and 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 identified several developmental and exploratory drilling locations on
Blocks 109 and 110. During 2000 and 2001 PANACO spent approximately $30 million
drilling a total of five new or side-tracked wells in East Breaks Block 110 and
completed four of the six wells. The four new wells began production in late
2000 and early 2001 and increased production in the Fields from 2,000 Mcf of
natural gas and 10 barrels of condensate per day before the drilling began to a
4
high of over 20,000 Mcf of natural gas and 200 barrels of condensate per day.
The initial rates from the new wells were in line with our expectations,
however, production declined more rapidly than we had anticipated due to
reservoir depletion. Current production from the Fields is approximately 5,000
Mcf of natural gas and 40 barrels of condensate per day.
There are more prospective drilling locations identified in both Blocks
109 and 110, however, based on the recent results, we are continuing to evaluate
the data we have. PANACO is the operator of the Fields and we own a 100% working
interest.
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,
2001, 25% 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.
Marketing of Existing Infrastructure
A key element of several acquisitions 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 27 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 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 coastline in the Gulf of Mexico and are in 700' to 900' of water. 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.
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.
Historically we have allocated 10% to 20% of our capital budget to exploratory
projects. However, as oil and natural gas prices began to increase in late 1999
and continued to mid 2001, the prices for acquisitions began to increase
significantly. With those costs escalating and a large inventory of prospects
ready to develop, we devoted a more significant percentage of our capital budget
to both exploratory and developmental drilling.
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 a large percentage 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
5
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, identified further
development potential and led to several new wells completed in 2000 and 2001.
Significant Operating Control
We operate 69% 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
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 54 productive offshore wells and own all of the working
interests in a majority of those wells. Third party operators, including Unocal
Corporation, Coastal Oil & Gas Corp., Newfield Exploration, Texaco, Anadarko
Petroleum Corporation and Burlington, operate our 29 remaining productive
offshore wells. We also operate 44 productive onshore wells in which we own a
majority or all of the working interest. In addition, we own working interests
in 54 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
6
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
Geoscientists obtain 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. We own
our own seismic interpretation workstations and data processing equipment and
utilize the services of outside firms to process and reprocess 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 BP. BP has a call on all of the oil production
from our properties acquired from BP at their posted prices. If we have a bona
fide offer from a crude oil purchaser at a higher price than BP's posted price,
then BP must match that price or release the call. Oil from the Zapata
Properties is currently being sold to Unocal and BP, 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 18% of our total oil and natural gas revenues in 2001. 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 Enron North America Corp. accounted for 51% of
our total oil and natural gas revenues in 2001. 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. In fourth
quarter 2001, we wrote off a total of $3.0 million due from Enron, of which $1.8
million was for sales of natural gas production. PANACO currently markets
natural gas production to Reliant Resources.
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 approximately
$22 million. The Minerals Management Service of the U.S. Department of the
Interior ("MMS") requires operators of offshore platforms to provide evidence of
7
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 and East Breaks 109 and 110 Fields
In both the West Delta Fields and the East Breaks 109 and 110 Fields, we
have established an escrow in favor of the surety bond underwriter, who provides
a surety bond to the former owners of the West Delta Fields and to the MMS. The
balance in this escrow account was $5.6 million at December 31, 2001 and
requires quarterly deposits of $375,000 until the account balance reaches $7.8
million.
East Breaks 165 Fields
In the East Breaks 165 and 209 Fields we have established an escrow
account in favor of the surety bond underwriter, who provides surety bonds to
both the MMS and the former owner of the Fields. The balance in this escrow
account was $4.7 million at December 31, 2001 and requires quarterly deposits of
$250,000 until the account balance reaches $6.5 million.
BP Properties
We have also established an escrow account in favor of BP under which we
deposit 10% of the net cash flows from the properties purchased from them, as
defined in the agreement. This escrow account balance was $0.7 million at
December 31, 2001.
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 $65 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, and up to $50 million for wells in state and federal offshore
waters. The amounts are proportionately reduced if we own less than 100% of the
well. We also maintain $143 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
Working Capital Deficit
Due to substantial losses incurred in 1999 and 2001 and less than
anticipated results from our drilling program in late 2000 and most of 2001, we
accumulated a significant working capital deficit as of December 31, 2001. The
deficit totaled $24.4 million. The lack of performance from wells drilled during
8
2000 and 2001, along with decreased commodity prices in late 2001, reduced
estimated future net cash flows and availability under our Credit Facility to a
point at which there is substantial doubt about the Company's ability to reduce
this deficit in a timely manner. As a result, we may not be able to continue as
a going concern. See Note 2 to financial statements.
Given this situation, we engaged an investment bank in early 2002 to
help us explore strategic financial alternatives. The outcome of this process
may result in asset sales or the sale of the Company as a whole. PANACO is also
in discussions to increase the amount of our Credit Facility, which may require
a waiver from the holders of the Senior Notes. No assurances can be made that we
will be able to implement any plan that will resolve the working capital deficit
or that a plan will be implemented in a timely manner. In addition, some of
these alternatives may require approval from our Credit Facility lenders or the
approval of our Senior Note holders as well as Shareholder approval.
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 November 2001, we amended a Credit Facility that was originally put
in place in September 1999. The amendment reduced the facility from $60 million
to $40 million, in order to reduce interest and debt service costs associated
with the facility. The new facility is for two years and borrowings under the
facility bear interest at either the Wells Fargo prime rate plus 0.25% to 0.75%
or at LIBOR plus 2.25% to 2.75%, both depending on the percentage of the
facility used, and has a minimum interest rate of 6.75%. At December 31, 2001,
PANACO had $32.9 million borrowed under the Credit Facility, with $6.1 million
of availability, of which $1.3 million was reserved by a letter of credit.
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
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. The Credit Facility also contains certain
limitations on mergers, additional indebtedness and pledging or selling assets.
In March 2002, the Credit Facility was amended in order to cure
covenants that we were not able to satisfy on December 31, 2001. This amendment
requires a working capital ratio (as defined in the agreement) of 0.15 to 1.0
from January 1 to April 30, 2002, 0.20 to 1.0 from May 1 to January 1, 2003, and
0.25 to 1.0 thereafter. The amendment also requires a trailing twelve-month
EBITDA/interest coverage ratio ranging from a monthly high of 2.0 to 1.0 to a
monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0 thereafter. In addition, the
amendment eliminates the requirement for hedges until March 31, 2002. Based on
current projections, we believe we will be in compliance with all of the terms
of the agreement through December 31, 2002. However, no assurances can be given
that we will be in compliance through December 31, 2002. As a result, we may not
be able to continue as a going concern. See Note 2 to financial statements.
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 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. We can also redeem all or part of the
9
Senior Notes, at our option, after October 1, 2001, at certain prices, which are
specified in the indenture, plus accrued interest to date.
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 ("ACNTA"), as defined in the
Indenture, 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.
At December 31, 2001 PANACO did not meet this ratio. If this deficiency
continues through March 31, 2002, the Company will be required to make an offer
to repurchase an amount of the notes (at par plus accrued interest) sufficient
to meet the ratio required in the agreement. Actual results through March 31,
2002 are not yet available, however, based on increased market prices for oil
and natural gas, we estimate that the Company will be in compliance with this
covenant at March 31, 2002 and we will not be required to make such an offer to
the holders of the Senior Notes. However, no assurances can be given that we
will meet this covenant or that the Company will be able to repurchase the
amount of the notes required under the Indenture. As a result, we may not be
able to continue as a going concern. See Note 2 to financial statements.
In August of 2000, we were informed that High River Limited Partnership,
a Delaware limited partnership ("High River"), had purchased a sufficient number
of additional shares of common stock to be a Change of Control under the
Indenture, thus requiring the Company to make a Change of Control Offer for
Senior Notes. High River is an affiliate of Carl C. Icahn, whose aggregate
ownership of Company common stock with his affiliates after the acquisition was
6,545,400 shares or 26.9% of the outstanding common stock. Pursuant to an
agreement with the Company, in October of 2000 High River purchased all the
Senior Notes tendered, increasing High River's ownership in the Notes to
approximately 99% of the $100 million principal amount of Senior Notes
outstanding.
The Indenture contains certain restrictive covenants that limit us to,
among other things, incurring additional indebtedness, paying dividends or
making certain other restricted payments, consummating certain asset sales,
entering into certain transactions with affiliates and incurring liens. The
Indenture also restricts us from merging or consolidating with any other person
or selling, assigning, transferring, leasing, conveying or otherwise disposing
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.
Common and Preferred Stock
On December 31, 2001 there were 24,359,695 shares of $.01 par value
common stock issued and outstanding. 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 natural gas producing properties and securing experienced personnel.
10
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 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.
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 the supply and prices 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 the 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 former BP Properties, will generally sell their
natural gas for as much as $.12 below the index price.
Environmental and Other Regulation. Governmental laws and regulations,
including price control, energy, environmental, conservation, tax and other laws
and regulations relating to the petroleum industry, affect our business. 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 has 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.
11
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
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 Minerals 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."
12
Employees
We have 21 full time employees, four 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.
Risk Factors
The Company's business and the results of operations are affected by
numerous factors and uncertainties, many of which are beyond our control.
Following is a description of some of the factors that could cause actual
results of operations in the future to differ materially from those currently
experienced or expected.
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 acquire 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 incurred significant losses in 2001 and 1999 and are significantly
leveraged. PANACO's debt totaled $135.1 million at December 31, 2001 and our
stockholders' deficit was $29.8 million. A large part of our losses in prior
years 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, and (iv) the market price for
our common stock may be lower than companies in our peer group. We cannot 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."
In March 2002, the Credit Facility was amended in order to cure
covenants that we were not able to satisfy on December 31, 2001. This amendment
requires a working capital ratio (as defined in the agreement) of 0.15 to 1.0
from January 1 to April 30, 2002, 0.20 to 1.0 from May 1 to January 1, 2003, and
0.25 to 1.0 thereafter. The amendment also requires a trailing twelve-month
EBITDA/interest coverage ratio ranging from a monthly high of 2.0 to 1.0 to a
monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0 thereafter. In addition, the
13
amendment eliminates the requirement for hedges until March 31, 2002. Based on
current projections, we believe we will be in compliance with all of the terms
of the agreement through December 31, 2002.
We must maintain a total Adjusted Consolidated Net Tangible Asset Value
("ACNTA"), as defined in the Indenture, 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. At December 31, 2001 PANACO did not meet this
ratio. If this deficiency continues through March 31, 2002, the Company will be
required to make an offer to repurchase an amount of the notes (at par plus
accrued interest) sufficient to meet the ratio required in the agreement. Based
on increased market prices for oil and natural gas, we estimate that the Company
will be in compliance with this covenant at March 31, 2002 and we will not be
required to make such an offer to the holders of the Senior Notes. However, no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.
Due to substantial losses incurred in 1999 and 2001 and less than
anticipated results from our drilling program in late 2000 and most of 2001, we
accumulated a significant working capital deficit as of December 31, 2001. The
deficit totaled $24.4 million. The lack of performance from wells drilled during
2000 and 2001, along with decreased commodity prices in late 2001, reduced
estimated future net cash flows and availability under our Credit Facility to a
point at which there is substantial doubt about the Company's ability to reduce
this deficit in a timely manner. See Note 2 to financial statements.
Given this situation, we engaged an investment bank in early 2002 to
help us explore strategic financial alternatives. The outcome of this process
may result in asset sales or the sale of the Company as a whole. PANACO is also
in discussions to increase the amount of our Credit Facility, which may require
a waiver from the holders of the Senior Notes. No assurances can be made that we
will be able to implement any plan that will resolve the working capital deficit
or that a plan will be implemented in a timely manner. In addition, some of
these alternatives may require approval from our Credit Facility lenders or the
approval of our Senior Note holders as well as Shareholder approval. See Note 2
to financial statements.
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."
Uncertainty of Estimates of Reserves and Future Net Cash Flows
The basis for the success and long-term continuation of our Company is
the price 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
14
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,
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, 2001 and use costs for operating and capital
expenditures in effect at that same time. These assumptions are then used to
calculate a future cash flow stream that is discounted at a rate of 10%.
The base prices used for the Pretax PV-10 calculation were public spot
prices on December 31 adjusted by differentials to those spot market prices.
These price adjustments were done on a property-by-property basis for the
quality of the oil and natural gas and for transportation to the appropriate
location. The average prices in the Pretax PV-10 value at December 31, 2001 were
$2.69 per Mcf of natural gas and $18.56 per barrel of oil.
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 Acquisitions. 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 the 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
15
environment (including groundwater contamination), blowouts, fires, explosions,
pollution and other risks, any of which could result in personal injuries, loss
of life, damage to properties and substantial losses. Although 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, 2001, 51% of
total oil and natural gas revenue came from our largest natural gas purchaser
and 18% came from our largest oil purchaser. 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. For the year ended December
31, 2000, one natural gas purchaser accounted for approximately 39% of our oil
and natural gas revenues. During 1999 we consolidated a majority of our oil
production to one oil purchaser, who accounted for 23% of our oil and natural
gas revenues in 2000. During 1999 our largest oil purchaser and our largest
natural gas purchaser accounted for 37% and 39%, respectively, of total oil and
natural gas sales.
Hedging Risks
We typically hedge a portion of PANACO's oil and natural gas production
during periods when either market prices for our products are higher than
historical average prices or when we are required to do so by our lenders. We
have hedged as much as 80% of PANACO's oil and natural gas production on an
annualized basis. During 2001 we hedged 61% of annual natural gas production and
30% of annual oil production. On March 28, 2002 we put in place two hedges for
both oil and natural gas produced from May 1 through October 31, 2002. The
natural gas hedge is a cost-free collar on 3,000 MMbtu and contains a minimum
price of $3.00 per MMbtu and a maximum price of $3.45 per MMbtu to be received
for the quantity hedged. The oil hedge is a swap on 500 barrels of oil per day
with prices ranging from $24.96 per barrel to $25.87 per barrel for the quantity
hedged. The volumes hedged account for 21% and 18%, respectively, of PANACO's
current estimates of total production for the periods hedged.
Typically, we have used swaps, cost-free collars and options to put
products to a purchaser at a specified price (or a "floor"). In these
transactions, we will usually have the option to receive from the counterparty
to the hedge a specified price or the excess of a specified price over a
floating market price. If the floating price exceeds the fixed price, we are
required to pay the counterparty all or a portion of this difference multiplied
by the quantity hedged.
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,
less any cash deposited in escrow accounts for these obligations. These costs
are usually higher on offshore properties, as are most expenditures on offshore
properties. As of December 31, 2001, our total estimated abandonment costs, net
of $11.0 million already in escrow, were approximately $11.0 million. We account
for those future liabilities by accruing for them in our depreciation, depletion
and amortization expense over the lives 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,
16
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 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
cannot 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 ours.
Item 2. Properties.
At December 31, 2001 our Proved Reserves totaled 114 Bcfe and had a
Pretax PV-10 value of $89.2 million. Approximately 75% of these reserves are
classified as Proved Developed Reserves and approximately 59% 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 67 producing oil wells and 114 producing natural gas
wells.
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 seven acquisitions of producing
properties that had Proved Reserves of 169 Bcfe at the time of their respective
acquisitions. We paid a total of $111.2 million for the Proved Reserve component
17
of those acquisitions. By focusing on larger acquisitions, our reserve base is
concentrated in a small number of properties. The following is a summary of our
significant properties as of December 31, 2001. These properties represent 78%
of the aggregate Pretax PV-10 value of our Proved Reserves.
Total Proved Reserves
---------------------
% of
Pretax PV-10 PANACO Total
Field Oil (MBbls) Natural Gas (Bcf) Value(000s) Pretax PV-10
- ---------------------------------------------------------------------------------------------------------------------
East Breaks 160/161/205 1,054 10.5 $ 22,320 25%
West Delta 54 275 11.5 16,068 18
Umbrella Point 1,084 5.0 11,827 13
East Breaks 165 2,635 17.0 8,867 10
East Breaks 109 20 8.4 5,488 6
West Delta 52 669 1.7 4,994 6
- ---------------------------------------------------------------------------------------------------------------------
Total 5,737 54.1 $ 69,564 78%
East Breaks 160/161/205
The East Breaks 160 Field is located offshore Texas, approximately 100
miles south of Galveston, in water depths of approximately 930 feet. The Field
is owned equally by PANACO, BP, and Unocal, with Unocal as the operator.
The Field is comprised of two blocks, East Breaks Block 160 and East
Breaks Block 161, which were originally leased in 1974. Field production is
handled on the Cervesa platform, located on Block 160. The production from which
is currently at 23,930 Mcf of natural gas per day, 3,324 barrels of oil per day
and 3,728 barrels of water per day from 12 wells.
In the summer of 2001 PANACO participated in a two well drilling program
proposed by Unocal. The first well, a gas well drilled in Block 205, was put on
stream in December of 2001 at a production rate of 17,000 Mcfpd. During the
month of February, 2002 this well was producing at a daily rate of 21,754 Mcf of
natural gas. The second well in the program was an oil well drilled in Block 161
and also put on production in December, 2001 producing 1,200 barrels of oil per
day. During March 2002, this well averaged 1,800 barrels of oil per day. Both
wells are sub-sea completions and are tied back to the Block 160 Cervesa
platform.
The East Breaks 160 property has significant exploration potential. The
operator is scheduled to drill two additional wells in the third quarter of
2002. Both wells can be drilled from the existing platform, possibly
sidetracking out of one of the original wellbores, and target multiple
objectives in the GA1 and GA3 sands.
Utilizing the Field's existing infrastructure, PANACO receives
processing fees from a former Mobil sub-sea well, now owned by BP Amoco, drilled
in Block 117. Because of the platform's strategic location on the edge of
deepwater, the facility has potential for additional processing and handling
fees as discoveries are made nearby and tied into the platform.
PANACO owns 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, as well as a
33.3% interest in a 17.47 mile 10" oil pipeline connecting the platform to the
High Island Pipeline System ("HIPS"), a crude oil pipeline system in the Gulf of
Mexico. Currently such firms as Exxon, Kerr-McGee and Samedan 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 even after the Field reserves are
depleted.
18
West Delta 54
PANACO acquired the West Delta Fields in May 1991 from Conoco, Atlantic
Richfield Company (now BP), Oxy USA, Inc. and Texaco Exploration and Production
Company. These Fields consist of 13,565 acres in Blocks 52 through 56 and Block
58 in the West Delta area, offshore Louisiana. The Field was originally
discovered in the mid 1950's and has continued to produce hydrocarbons since
then. Drilling and other activities continue in the West Delta area. There are
currently approximately 40 total wells in the Field, which produce from depths
ranging from 900' to 17,000'. PANACO operates the Field and generally owns 100%
of most of the area's wells. The production facility is a four-platform complex
located in Block 54 in water that ranges in depth from six to fifteen feet.
During 1996, a significant portion of the production facilities was rebuilt
after being damaged by a third party
The geology is characterized by multiple reservoirs, which we believe
provide more opportunities for successful drilling activities. Both 2001 and
2000 continued to be active periods at West Delta, with three completed
development wells by PANACO and four exploratory wells drilled under a farmout
agreement with Basin Exploration, three of which were completed. The three new
wells that we completed were typical for the Field in that the wells were all
set up to produce in several zones during the lives of the wells. The wells were
all drilled in Block 54 and continue to produce.
We have also allowed third party operators to drill on our Block 58
acreage in West Delta under farmout agreements. Typically these agreements
provide for PANACO to receive an overriding royalty interest, with an optional
back-in after payout in addition to processing fees for the handling of
production.
In the three wells completed by Basin Exploration, PANACO owns
overriding royalty interests ranging from 10% to 12.5%. Under the Basin
agreement we received a prepayment of processing fees for the five-year term of
the processing agreement. In addition to the $1.8 million prepayment, we receive
some incremental fees and reimbursement of expenses as the wells produce.
West Delta Block 54 was producing 180 barrels of oil per day, 4,800 Mcf
of natural gas per day and 5,600 barrels of water per day as of February 2002.
Umbrella Point
Umbrella Point Field is a well defined, low relief, 4-way structural
closure centered on State Tracts 73, 74, 87 and 88 in the Galveston/Trinity Bay
portion of Chambers County, Texas. It is located three miles from shore in
approximately ten feet of water, 32 miles east-southeast of Houston, Texas. The
Field was discovered in 1957 by Sun Oil Company. Sun, along with Tidewater,
initially developed the Field in the late 1950's and early 1960's. Field
development continued in the 1970's by Getty, in the early 1990's by French
Operating Company, and in the late 1990's by PANACO, Inc. Since its discovery in
1957, 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 the leases
that encompass the Field. Oil production is gathered on a small platform complex
and transported via PANACO's five-mile oil pipeline to our onshore production
facility at Cedar Point and gas production is transported through a Midcon
Pipeline Co. pipeline.
On January 21, 1998 we announced the successful completion of our first
new well in the Umbrella Point Field. The well flowed 11,500 Mcf of natural gas
per day and 220 barrels of condensate per day. The production from this well
peaked at 27,000 Mcf per day of natural gas and 460 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 19,000 Mcf of natural gas and 176 barrels of oil per
day. We own an 80% working interest in the well with Peoples Energy Production
owning the remaining 20%.
19
In 2001 PANACO drilled an exploratory well on the property, the State
Tract 73 No. 6 well, to test the Vicksburg sand. This well encountered no
productive pay zones and was plugged and abandoned.
Current production from the Umbrella Point Field is 1,000 Mcf of natural
gas per day and 240 barrels of oil per day.
West Delta 52
PANACO acquired a 100% working interest in a portion of West Delta Block
52 Field in April 2001 from Delta Petroleum Corporation.
The acquisition included seven producing oil wells, one salt-water
disposal well and 18 shut-in wells. At that time a 7,600' oil sand was the only
productive sand for the property, producing approximately 180-200 barrels of oil
per day. No gas was being sold.
The geology of the field was remapped immediately after PANACO acquired
the property, resulting in significant dry gas reserves from at least four
shallower sands from 3,000'-6,500'. Workovers performed during 2001 resulted in
three dry gas sand completions from three separate reservoirs. Other potential
dry gas reserves are expected when additional future workovers are completed.
In 2001 we completed three new gas wells with sufficient resulting
production to allow us to maintain operations of the oil wells without
purchasing additional gas. PANACO currently has six oil wells producing from the
7,600' oil sand and three dry gas wells producing from intervals between 4,780'
and 6,400'. February 2002 production averaged 900 Mcf of natural gas per day
and 220 barrels of oil per day.
East Breaks 165
East Breaks Block 165 was acquired by Sohio Petroleum Company at the
Federal OCS Lease Sale in August 1983. In mid 1984, significant hydrocarbons
were discovered in the first well on the block, including 111 feet of gas pay
and 156 feet of oil pay. BP bought Sohio Petroleum in the late 1980's, and by
January 1990 BP had drilled and completed well number 30. PANACO purchased the
East Breaks 165 platform (known as the "Snapper" platform) from BP in May 1998.
The East Breaks 165 geological structure is an interdomal faulted
paleostructure. The shallower horizons exhibit four-way dip closure, while at
deeper horizons a faulted anticline is mapped. The main reservoir sands at East
Breaks 165 are of excellent quality. Their apparent mineralogical and textural
maturity, within an otherwise deepwater sequence, suggests they were transported
some distance from a high-energy shelf area into a slope environment of
disposition. The massive nature of individual beds coupled with sparsely "fining
upwards" sands, indicate that sediment transport occurred mainly by bottom
traction within a major channel feeder system at the edge of the shelf, with
re-deposition in the East Breaks 165/209 area. There is a combination of
structural and stratigraphic traps in the 12 different main sands in the East
Breaks 165 area.
3-D Seismic was generated on the East Breaks 165 area and PANACO has
recently reprocessed this data. The new reprocessed data better defines the
structural morphology, improves the fault resolution, better images the
potentially productive upthrown fault block to the north, and clarifies limits
of the production.
Presently there are 30 wells on the platform, of which 16 are producing.
The total production per day from the platform is 1,150 barrels of oil per day,
1,600 Mcf of natural gas per day and 5,700 barrels of water per day.
20
PANACO has identified three drilling prospects on the E.B. 165 structure
which are supported by 3-D Seismic amplitude anomalies.
East Breaks 109
East Breaks 109/110 is located approximately 100 miles south of
Galveston Island, offshore Texas, in water depths of approximately 650 feet.
Blocks 109 and 110 were acquired by Texaco and Columbia Gas in July 1974 and the
companies proceeded to drill four wells on the two blocks. In early 1978, Texaco
farmed out its interest to Zapata. The platform was installed in 663' of water
in the summer of 1984 and Zapata and Columbia drilled five joint wells.
Effective January 1, 1985, Zapata purchased the interest of Columbia Gas and
went on to drill five additional wells.PANACO acquired 100% interest in East
Breaks 109/110 Field from Zapata in July of 1995. In addition to the mineral
interests acquired, PANACO purchased 100% interest in a 31 mile 10" natural gas
pipeline connecting the East Breaks 110 platform to the High Island Offshore
System as well as a 22 mile 4" oil pipeline that connects to the High Island
Pipeline System.
During 2001 PANACO drilled three new wells on the property and
sidetracked three others. The drilling and sidetrack program increased Field
production by 21,000 Mcf of natural gas per day. Currently, four additional
drilling prospects have been identified on the property. Production from the
Field at the time of this writing is 4,900 Mcf of natural gas per day, 37
barrels of oil per day and 600 barrels of water per day.
Oil and Gas Information
Third party engineering firms use information we provide them to prepare
our reserve estimates. 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 76% of the Pretax PV-10 of our reserve estimates.
Our proved oil reserves totaled 7.9 million barrels at December 31, 2001
compared to 8.1 million barrels at December 31, 2000. Our proved natural gas
reserves totaled 66.9 Bcf at December 31, 2001 as compared to 82.2 Bcf at
December 31, 2000. The Pretax PV-10 value of these reserves totaled $89 million
at December 31, 2001 compared to $533 million at December 31, 2000. The largest
impact on the PV-10 value of PANACO's reserves was lower prices for oil and
natural gas. Decreased commodity prices, net of changes in production costs,
accounted for over $400 million of the decrease, which was offset by $125
million of lower future estimated income taxes. 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.
21
Producing Wells(a)
The following table presents the number of producing oil and natural gas
wells attributable to our properties, as of December 31, 2001.
Producing Wells Company Operated
--------------- -----------------
Gross producing offshore wells(b):
Oil ......................................... 26 18
Natural Gas .................................. 57 36
--- ---
Total .................................... 83 54
Net producing offshore wells(c):
Oil ......................................... 24 18
Natural Gas .................................. 30 36
--- ---
Total .................................... 54 54
Gross producing onshore wells(b):
Oil ......................................... 41 31
Natural Gas .................................. 57 13
--- ---
Total .................................... 98 44
Net productive onshore wells(c):
Oil ......................................... 33 33
Natural Gas .................................. 3 3
--- ---
Total .................................... 36 36
<FN>
- ----------
(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.
</FN>
Leasehold Acreage
The following table presents the estimated developed acreage
attributable to our properties, as of December 31, 2001.
Developed onshore acreage(a):
Gross acres(b)........................................................... 3,626
Net acres(c)............................................................. 1,940
Undeveloped onshore acreage(a):
Gross acres(b)........................................................... 3,838
Net acres(c)............................................................. 2,713
Developed offshore acreage(a):
Gross acres(b)........................................................... 83,650
Net acres(c)............................................................. 40,972
Undeveloped offshore acreage(a)(d):
Gross acres(b)........................................................... 1,360
Net acres(c)............................................................. 560
<FN>
- ----------
(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.
(d) In addition to these acres, our undeveloped offshore potential exists at
greater depths beneath existing producing reservoirs.
</FN>
22
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, 2001. 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.
Developmental Wells Exploratory Wells
Completed Dry Completed Dry
Oil Gas Oil Gas Oil Gas Oil Gas
------------------------------- -----------------------------
1997 6 13 -- 1 -- -- -- --
1998 1 9 -- -- -- 3 -- 6
1999 1 -- -- -- -- 4 -- 3
2000 -- 6 -- -- -- 2 -- 1
2001 -- 3 -- -- 2 6 -- 2
--- --- --- --- --- --- --- ---
Total 8 31 -- 1 2 15 -- 12
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.
We are presently a party to several 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 24,359,695 shares are issued and
outstanding as of March 25, 2002 and are held by over 5,500 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.
23
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 secured
creditors and 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
non-assessable.
Warrants and Options
We also have outstanding options to acquire 425,000 Common Shares at a
price of $1.92 per share, which expire August 17, 2006. These options are all
held by current 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, 59 Maiden Lane, New
York, NY 10007.
Price Range of Common Shares
Since September 2000, our Common Shares have been traded on The American
Stock Exchange under the symbol "PNO." Prior to that, our Common Shares were
traded on the OTC Bulletin Board and on NASDAQ under the symbol "PANA." They
commenced trading September 21, 1989. The following table sets forth, for the
periods indicated, the high and low closing prices for the Common Shares.
2001
--------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
Low $ 2.19 $ 2.12 $ 0.93 $ 0.78
High $ 3.25 $ 2.85 $ 2.43 $ 1.72
2000
--------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
Low $ 0.34 $ 0.51 $ 1.38 $ 2.38
High $ 0.96 $ 1.66 $ 3.50 $ 3.75
On March 25, 2002, the last sale price of the Common Shares was $0.80
per share.
Potential De-listing
Due to significant losses in 1999 and 2001, PANACO's stockholder's
equity was reduced to a deficit of $29.8 million as of December 31, 2001. As a
result, the Company does not meet the requirements for continued listing on the
24
American Stock Exchange (the "Exchange"). Upon notification by the Exchange, we
would be required to present a plan that would bring the Company back into
compliance. No assurances can be made that the plan would be approved or that
such a plan could be successfully executed.
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 requires the consent of the lenders and the Senior Notes contain
limitations on any dividends or 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, 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 $0.005 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 only the Board of Directors may call special meetings of
shareholders, and that only business proposed by the Board of Directors may be
considered at special meetings of shareholders.
25
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) ten days after the first public notice of
the annual meeting is sent to common shareholders. In general, the notice must
also contain certain information about the shareholder proposing the business or
nomination, his interest in the business, and (with respect to nominations for
director) information about the nominee of the nature ordinarily required to be
disclosed in public proxy solicitations. The shareholder must also submit a
notarized letter from each of his nominees stating the nominee's acceptance of
the nomination and indicating the nominee's intention to serve as director if
elected.
The Certificate of Incorporation also restricts the ability of
shareholders to interfere with the powers of the Board of Directors in certain
specified ways, including the constitution and composition of committees and the
election and removal of officers.
The Certificate of Incorporation provides that approval by the holders
of at least two-thirds of the outstanding voting shares is required to amend the
provisions of the Certificate of Incorporation discussed in the preceding
paragraphs and certain other provisions, except that approval by the holders of
at least 80% of the outstanding voting shares, 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
26
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. See "Business - Senior Notes."
Item 6. Selected Financial Data.
The following historical data is derived from the 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, Item 8.
For the Years ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(amounts in thousands, except per share data)
Oil and natural gas sales $ 76,246 $ 88,550 $ 42,672 $ 50,291 $ 37,841
Gain on sale of assets 3,967 1,938 --- --- ---
Lawsuit recoveries --- 2,575 --- --- ---
-------------------------------------------------------------------------
Total revenues 80,213 93,063 42,672 50,291 37,841
Total costs and expenses before income
taxes and extraordinary item (1) 99,784 76,591 77,568 100,242 36,864
Income tax expense (benefit) (2) 22,734 (22,683) --- (3,100) ---
Extraordinary item-loss on early
retirement of debt --- --- 131 --- 934
-------------------------------------------------------------------------
Net Income (loss) (3) $ (42,305) $ 39,155 $ (35,027) $ (46,851) $ 43
=========================================================================
Net Income (loss) per Common Share $ (1.74) $ 1.61 $ (1.46) $ (1.96) $ ---
Total assets $ 146,064 $ 174,079 $ 135,438 $ 143,372 $ 179,629
Long-term debt $ 135,120 $ 121,693 $ 138,902 $ 115,749 $ 101,700
Stockholders' equity (deficit) $ (29,784) $ 12,408 $ (26,875) $ 7,902 $ 55,188
<FN>
(1) Results for the years ended December 31, 2001, 1999 and 1998 include
impairments of oil and gas properties of $9.1 million, $13.2 million and
$20.4 million, respectively.
(2) During 2001 the Company re-established a deferred tax valuation allowance
that had been eliminated in 2000. The change in the valuation allowance was
primarily due to lower volumes and market prices for oil and natural gas,
resulting in lower estimates of future net income, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
(3) No Common Share dividends have been paid in the five-year period ending
December 31, 2001. Results for each year presented may not necessarily be
comparative due to numerous acquisitions, see "Business strategy -
Strategic Acquisitions and Mergers" for further discussion of acquisitions.
</FN>
27
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.
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 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 cannot 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.
Liquidity and Capital Resources
As a result of much higher oil and natural gas prices during 2000 and
2001, PANACO realized record high cash flows from operations in 2000 and 2001.
With the market prices for acquisitions increasing, PANACO focused on
developmental and exploratory drilling in both of these years. During 2001, we
used all of our cash flows from operating activities for drilling new wells,
primarily in the Gulf of Mexico, and for the acquisition of an oil property
contiguous with a property that we already owned. While we were successful on a
percentage completion basis, (85%) of total new wells drilled, the reserves
discovered did not amount to the level anticipated. The result was lower
production during 2001 and lower reserves in place at the end of 2001.
Consequently, the combination of lower production and a decline in commodity
prices during 2001 resulted in lower than projected cash flows from operations.
PANACO's 2001 capital spending totaled $45.0 million, of which $3.9
million was for the acquisition of proved oil reserves and the remainder was for
exploratory and developmental drilling. We also sold an offshore, non-operated
property in 2001 and deposited $2.4 million of cash into restricted cash
accounts as required under agreements in place. Our cash flows from operations
were used to fund the 2001 expenditure program, which also required a net
increase in debt of $13.4 million, funded by PANACO's amended Credit Facility.
At December 31, 2001, PANACO's balance due under the Credit Facility was $32.9
million, leaving $4.8 million available after a $1.3 million letter of credit.
At December 31, 2001, 81% of PANACO's total assets were represented by
oil and natural gas properties, pipelines and equipment, net of accumulated
depletion, depreciation and amortization.
Working Capital
To reduce interest costs, we keep as little cash on hand as possible and
apply available cash to our Credit Facility. The timing of the receipt of monies
due us, the timing of payments we make to vendors, the timing of capital
expenditures and revenues all impact PANACO's working capital. PANACO's working
28
capital deficit totaled $24.4 million at December 31, 2001. Due to substantial
losses incurred in 1999 and 2001 and less than anticipated results from our
drilling program in late 2000 and most of 2001, we accumulated a significant
working capital deficit as of December 31, 2001. The deficit totaled $24.4
million. The lack of performance from wells drilled during 2000 and 2001, along
with decreased commodity prices in late 2001, reduced estimated future net cash
flows and availability under our Credit Facility to a point at which there is
substantial doubt about the Company's ability to reduce this deficit in a timely
manner. See Note 2 to financial statements.
Given this situation, we engaged an investment bank in early 2002 to
help us explore strategic financial alternatives. The outcome of this process
may result in asset sales or the sale of the Company as a whole. PANACO is also
in discussions to increase the amount of our Credit Facility, which may require
a waiver from the holders of the Senior Notes. No assurances can be made that we
will be able to implement any plan that will resolve the working capital deficit
or that a plan will be implemented in a timely manner. As a result, we may not
be able to continue as a going concern. In addition, some of these alternatives
may require approval from our Credit Facility lenders or the approval of our
Senior Note holders as well as Shareholder approval.
Financing Activities
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. 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.
At December 31, 2001 the Company was not in compliance with a financial
covenant in the Senior Notes indenture. The covenant requires a specified ratio
of assets (as defined in the agreement) to total indebtedness. Should this
condition continue to exist for two successive quarters, the Company is required
to make an offer to the Senior Note holders to repurchase an amount of the notes
(at par plus accrued interest) sufficient to meet the ratio required in the
indenture. Based on increased market prices for oil and natural gas, we estimate
that the Company will be in compliance with this covenant at March 31, 2002 and
we will not be required to make such an offer to the holders of the Senior
Notes. However, no assurances can be given that we will meet this covenant or
that the Company will be able to repurchase the amount of the notes required
under the Indenture. As a result, we may not be able to continue as a going
concern. See Note 2 to financial statements.
Contractual Obligations and Commercial Commitments
The following table sets forth PANACO's obligations and commitments to
make future payments under its debt agreements, lease agreements, and other
long-term obligations as of December 31, 2001.
PAYMENTS DUE BY PERIOD
(Amounts in Thousands)
----------------------------------------------------------------------------
Less than
Contractural Obligations Total 1 Year 1-3 Years 4-5 Years After 5 Years
- ---------------------------------------------------------------------------------------------------------------------------
Principal Payments on Long-Term Debt $ 132,871 $ -- $ 132,871 $ -- $ --
Interest Payments on Long-Term Debt 35,758 12,844 22,914 -- --
Operating Leases:
Office Space 1,339 459 880 -- --
------------- ------------- ------------- ------------- -------------
Total Contractual Cash Obligations $ 169,968 $ 13,303 $ 156,665 $ -- $ --
============= ============= ============= ============= =============
29
AMOUNT OF COMMITMENT EXPIRATION BY PERIOD
(Amounts in Thousands)
----------------------------------------------------------------------------
Total
Amount
Committed Less than
Other Commercial Commitments 1 Year 1-3 Years 4-5 Years After 5 Years
- ---------------------------------------------------------------------------------------------------------------------------
Standby Letters of Credit $ 1,300 $ -- $ -- $ -- $ 1,300
------------- ------------- ------------- ------------- --------------
Total Other Commercial Commitments $ 1,300 $ -- $ -- $ -- $ 1,300
============= ============= ============= ============= ==============
Contractual obligations excludes a production payment that is a property
specific, non-recourse, obligation of PANACO. Interest amounts due under
PANACO's Credit Facility are calculated assuming the rate and balance due remain
constant over the term of the facility.
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 November 2001, we amended a Credit Facility that was originally put
in place in September 1999. The amendment reduced the facility from $60 million
to $40 million, in order to reduce interest and debt service costs associated
with the facility. The new facility is for two years and borrowings under the
facility bear interest at either the Wells Fargo prime rate plus 0.25% to 0.75%
or at LIBOR plus 2.25% to 2.75%, both depending on the percentage of the
facility used, and has a minimum interest rate of 6.75%. At December 31, 2001,
PANACO had $32.9 million borrowed under the Credit Facility, with $6.1 million
of availability, of which $1.3 million was reserved by a letter of credit.
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
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. The Credit Facility also contains certain
limitations on mergers, additional indebtedness and pledging or selling assets.
In March 2002, the Credit Facility was amended in order to cure
covenants that we were not able to satisfy on December 31, 2001. This amendment
requires a working capital ratio (as defined in the agreement) of 0.15 to 1.0
from January 1 to April 30, 2002, 0.20 to 1.0 from May 1 to January 1, 2003, and
0.25 to 1.0 thereafter. The amendment also requires a trailing twelve-month
EBITDA/interest coverage ratio ranging from a monthly high of 2.0 to 1.0 to a
monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0 thereafter. In addition, the
amendment eliminates the requirement for hedges until March 31, 2002. Based on
current projections, we believe we will be in compliance with all of the terms
of the agreement through December 31, 2002. However, no assurances can be given
that we will be in compliance through December 31, 2002. As a result, we may not
be able to continue as a going concern. See Note 2 to financial statements.
Critical Accounting Policies
Application of generally accepted accounting principles requires the use
of estimates, judgments and assumptions that affect the reported amounts of
assets and liabilities as of the date of the financial statements and revenues
and expenses during the reporting period. In addition, alternatives can exist
among various accounting methods. In such cases, the choice of accounting method
can also have a significant impact on reported amounts.
The Company's estimates of proved oil and gas reserve quantities, the
application of the successful efforts method of accounting for our exploration
30
and production activities, the application of standards of accounting for
hedging activities, and the accounting method used for revenue recognition
require management to make numerous estimates and judgments.
Successful Efforts Method of Accounting for Oil and Gas Properties
The Company's exploration and production activities are accounted for
using the successful efforts method. We believe that the successful efforts
method is the most appropriate method to use to account for our oil and gas
production activities while allowing for comparable analysis with our peers.
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.
Non-drilling exploratory costs, including geological and geophysical costs and
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 depletion
is determined on a depletable unit basis using the unit-of-production method.
Estimated future abandonment costs are recorded by charges to depreciation and
depletion expense over the lives of the proved reserves of the properties.
The Company performs a review for impairment of proved oil and gas
properties on a depletable unit basis when circumstances suggest there is a need
for such a review. For each depletable unit determined to be impaired, an
impairment loss equal to the difference between the carrying value and the fair
value of the depletable unit will be recognized. Fair value, on a depletable
unit basis, is estimated to be the present value of expected future cash flows
computed by applying estimated future oil and gas prices, as determined by
management, to estimated future production of oil and gas reserves over the
economic lives of the reserves. Future cash flows are based upon the Company's
estimate of proved reserves.
Reserves
Estimates of PANACO's proved oil and gas reserves are prepared by our
third-party engineers in accordance with guidelines established by the SEC.
Those guidelines require that reserve estimates be prepared under existing
economic and operating conditions with no provisions for increases in commodity
prices except by contractual arrangement and assuming continuation of existing
operating conditions. Estimation of oil and gas reserve quantities is inherently
difficult and is subject to numerous uncertainties. Such uncertainties include
the projection of future rates of production and the timing of development
expenditures. The accuracy of the estimates depends on the quality of available
geological and geophysical data and requires interpretation and judgment.
Estimates may be revised either upward or downward by results of future
drilling, testing or production. In addition, estimates of volumes considered to
be commercially recoverable fluctuate with changes in commodity prices and
operating costs. Third party engineering firms calculate the quantity of
PANACO's reserves based on information we provide them. These reserve estimates
have a significant effect on DD&A expense and on asset impairment reviews.
Revenue Recognition
The Company recognizes its ownership interest in oil and gas production
as revenue. Revenues from the sales of crude oil and natural gas are recognized
when delivery to the customer has occurred and title has transferred. This
usually transpires when production has been delivered to the pipeline. The
Company may have an interest with other producers in certain properties, in
which case the Company uses the entitlements method to account for sales of
production and imbalances. At December 31, 2000 the Company's imbalance position
was an over-produced, or payable balance of 610,000 Mcf valued at $2.9 million.
At December 31, 2001 the Company's imbalance position was an over-produced, or
payable balance of 265,000 Mcf valued at $1.1 million.
31
Hedging Activities
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. 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. Realized gains and losses are recognized
monthly as adjustments to revenues in the same production period as the hedged
production. Contracts are placed with entities 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.
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. 133 ("SFAS133"), Accounting for Derivative Instruments
and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities, an amendment of FASB Statement No.
133. These statements establish accounting and reporting standards requiring
that derivative instruments (including certain derivative instruments embedded
in other contracts) be recorded at fair market value and included in the balance
sheet as assets or liabilities. The accounting for changes in the fair value of
a derivative instrument depends on the intended use of the derivative and the
resulting designation, which is established at the inception of a derivative.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in other comprehensive income
until the hedged item is recognized in earnings. Hedge effectiveness is measured
at least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time. Any change in fair value
resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings. On March 28, 2002 we put in place two hedges for both
oil and natural gas produced from May 1 through October 31, 2002. The natural
gas hedge is a cost-free collar on 3,000 MMbtu and contains a minimum price of
$3.00 per MMbtu and a maximum price of $3.45 per MMbtu to be received for the
quantity hedged. The oil hedge is a swap on 500 barrels of oil per day with
prices ranging from $24.96 per barrel to $25.87 per barrel for the quantity
hedged. The volumes hedged account for 21% and 18%, respectively, of PANACO's
current estimates of total production for the periods hedged.
32
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, 2001.
For the year ended December 31,
2001 2000 1999
------------------------------------------------------------------
Oil and Condensate:
Net production (Bbls)(a) 923,000 1,070,000 1,170,000
Revenue $ 23,291,000 $ 32,396,000 $ 22,025,000
Hedge gains (losses) $ --- $ (710,000) $ (1,784,000)
Average net Bbl per day 2,529 2,924 3,204
Average price per Bbl before hedges $ 25.23 $ 30.28 $ 18.83
Average price per Bbl including hedges $ 25.23 $ 29.62 $ 17.31
Natural Gas:
Net production (Mcf)(a) 10,703,000 13,547,000 11,114,000
Revenue $ 49,419,000 $ 57,246,000 $ 25,267,000
Hedge gains (losses) $ 3,536,000 $ (382,000) $ (2,836,000)
Average net Mcf per day 29,300 37,000 30,400
Average price per Mcf before hedges $ 4.62 $ 4.23 $ 2.27
Average price per Mcf including hedges $ 4.95 $ 4.20 $ 2.02
Total oil and natural gas sales $ 76,246,000 $ 88,550,000 $ 42,672,000
Production costs $ 24,658,000 $ 20,876,000 $ 17,740,000
Total production (Mcfe)(b) 16,241,000 19,996,000 18,132,000
Production cost per Mcfe(b) $ 1.52 $ 1.05 $ .98
<FN>
--------------
(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.
</FN>
Results of Operations
Revenues
One of the most significant factors affecting our business is the market
price of the oil and natural gas that we produce and sell. In late 1997 and
continuing through early 1999, both oil and natural gas prices were lower than
they had been in the proceeding years. A turnaround was seen in 1999 and
continued through early 2001 where we benefited from a steady increase in
realized prices. The average realized price, net of hedges, has increased 46%
for oil and 145% for natural gas from 1999 to 2001.
Primarily due to disappointing results from PANACO's drilling projects
in 2001, both oil and natural gas production declined from the previous years'
levels. These declines resulted in 14% lower oil and natural gas sales, which
totaled $76.2 million in 2001. While oil and natural gas production from the
East Breaks 110 and West Delta Fields increased, they did not offset natural
production declines on most of our other fields. Production at our East Breaks
160 Field began to increase in December 2001 with the addition of two new wells,
which should have a more meaningful impact on the first quarter of 2002. While
oil prices decreased 15% from 2000, natural gas prices continued their increase
from 1999 and averaged $4.95 per Mcf during 2001. The most significant price
gains were realized in the first half of 2001, however, by the end of 2001,
natural gas prices had dropped drastically.
33
Our oil and natural gas revenues reached an all-time high of $88.6
million in 2000, a 108% increase over 1999. Including hedges, we realized a 71%
increase in our average price per barrel. Natural gas prices also increased
dramatically in 2000, from $2.02 per Mcf in 1999 to $4.20 per Mcf in 2000.
Coupled with a 22% increase in natural gas production, natural gas revenues
increased to $56.9 million in 2000, a 154% increase over 1999. Once commodity
prices began to improve in late 1999, we increased spending in that year and
through 2000, which resulted in increased production.
During 2001 PANACO sold its interest in a non-operated offshore
property, which resulted in a gain of $4.0 million. During the fourth quarter of
2000 we also sold two offshore properties resulting in a gain of $1.9 million.
Also, two lawsuits were settled during 2000 for which we received a total of
$2.6 million.
Cost and Expenses
Lease operating expenses ("LOE"), totaled $24.7 million in 2001, an
increase of $3.8 million over the prior year. The increase is due to the
acquisition of the West Delta 52 Field in April 2001, which accounted for $2.2
million of additional LOE. Also, workover and repair expenses increased $1.2
million over 2000. These expenses are those outside of recurring monthly
operating expenses and are typically for well and platform maintenance and
repairs. Lease operating expenses also increased in 2000 when compared to 1999,
from $17.7 million to $20.9 million. The primary factor in the higher LOE in
2000 was an increase in workover and repair expenses, which began in late 1999
as PANACO began to increase overall capital spending. LOE for 2000 includes $5.7
million of workover and repair expenses as compared to $1.0 million for these
same expenses in 1999.
Depletion, depreciation and amortization ("DD&A"), increased to $34.5
million in 2001, from $27.0 million in 2000. While total production decreased
19% for the same period, PANACO's DD&A per Mcf equivalent ("Mcfe") of production
increased 57% to $2.12 per Mcfe in 2001, from $1.35 in 2000. The increase from
2000 is primarily due to the disappointing results at East Breaks 110, where
PANACO's finding cost for reserves increased significantly. DD&A increased 2% in
2000 to $27.0 million, compared to $26.4 million in 1999. The increase was due
to a 10% increase in total production, upon which our depletion is calculated.
However, this increased production was offset by a lower depletion rate per unit
of production, from $1.46 per Mcfe in 1999 to $1.35 per Mcfe in 2000. The
decrease in depletion per Mcfe was primarily due to property impairments in 1999
totaling $13.2 million. This impairment reduced the remaining capitalized costs
to be depleted in 2000.
General and administrative expenses ("G&A") decreased $0.9 million in
2001, to $4.0 million. The 2000 G&A was higher due to bonuses paid in 2000 and
higher staffing levels in that year. During 2001 PANACO reduced G&A expenses by
reducing the number of employees and focusing on controlling costs. We began
2001 with 37 employees and ended 2001 with 31 employees. G&A totaled $4.9
million and $3.9 million in 2000 and 1999, respectively. The increase in 2000 of
$1.0 million relates primarily to the $0.6 million of employee bonuses paid in
2000, as there were no bonuses paid in 1999.
Bad debt expense increased to $3.3 million in 2001, from $0.3 million in
2000 and $0.1 million in 1999. The increase in 2001 relates to the write-off of
a receivable from Enron of $3.0 million, $1.2 million of which was for the final
payment due under a natural gas swap agreement and $1.8 million for natural gas
sold to Enron through early December 2001. PANACO no longer sells any production
to Enron.
Production and ad valorem taxes remained relatively flat in 2001,
totaling $2.0 million, when compared to 2000, which totaled $2.1 million. When
comparing 2000 to 1999, the increase of $0.9 million is due to the increase in
total revenues. These taxes vary from year to year primarily based on our
production mix. Production from offshore properties is not subject to production
taxes, while onshore properties and those in state waters are. These taxes are
based on the value of the sales from the production or the number of units
produced, depending on the location of the properties.
34
Exploratory dry hole expense and geological and geophysical expense
(collectively referred to as "exploration expenses") totaled $9.3 million and
$5.7 million in 2001 and 2000, respectively. With the increase in drilling
activity by PANACO in 2001 and 2000, versus acquisitions, our exploration
expenses also increased. The two largest components of exploration expense in
2001 were unsuccessful wells drilled at East Breaks 110 ($3.9 million) and
Umbrella Point ($3.8 million). The increase of $3.2 million in exploration
expenses in 2000 over 1999, was due to three unsuccessful wells drilled, the
largest of which was also in the East Breaks 110 Field, and totaled $2.3
million.
During 2001 PANACO recognized an asset impairment of $9.1 million, $1.9
million of which related to an unproved property, based on the unsuccessful well
at Umbrella Point. The balance of the impairment was due to lower estimated
future net revenues for our proved properties primarily as a result of declining
oil and natural gas prices as well as reserve volume reductions. During 1999 we
recorded an oil and gas property impairment of $13.2 million, which related to
two property groups. Part of the impairment provision related to our unproved
property costs, for which we did not have planned development activity. The
other part of the impairment provision was recorded in connection with a reserve
reduction on a proved property. During 2000 we did not record an asset
impairment.
During 2000 a former officer and director resigned in accordance with
the terms of his employment agreement. Under the terms of this agreement, the
former employee received two years of his salary in addition to other benefits.
We recorded a $0.7 million charge in connection with the resignation.
PANACO's average borrowings during most of 2001 under the Credit
Facility were equal to or lower than the levels outstanding in 2000. In
addition, as the prime rate decreased in 2001, our average interest rate also
decreased, resulting in a $2.3 million decrease in net interest expense in 2001.
During 2000 net interest expense increased primarily due to higher borrowing
levels under our Credit Facility. During 2000 our weighted average interest
rates also increased due to two factors (1) the new Credit Facility put in place
in late 1999 and (2) increases in the prime rate, which is the base for our
Credit Facility interest rate.
Income Tax Expense/(Benefit)
As oil and natural gas prices increased during 2000, we were able to
project future net income sufficient to utilize our net operating loss
carry-forwards. As such, during 2000 we recorded an income tax benefit of $29
million by reversing a valuation allowance recorded against these assets. We
also recorded an income tax expense provision of $6.3 million during 2000 based
on pre-tax income for the year of $16.5 million, resulting in a net income tax
benefit of $22.7 million in 2000. No income tax expense or benefit was recorded
in 1999. During 2001, the decrease in oil and natural gas prices had the
opposite effect. In the latter part of 2001, future net income projections had
decreased to a point at which we were not able to project sufficient net income
to utilize any of the net operating loss carry-forwards. As such, a valuation
allowance of $30.1 million was re-established.
Extraordinary Item
During 1999 we recorded an extraordinary item for the early retirement
of long-term debt. This charge was recorded in connection with the prepayment of
our Credit Facility. We put in place a new Credit Facility in September 1999.
Outlook
As a relatively small, leveraged oil and natural gas exploration and
production company, the success and outcome of our business are highly dependent
on oil and natural gas prices. Not only are our revenues, cash flows, results of
operations and liquidity impacted by commodity prices, our ability to obtain
financing for our business is also influenced by these prices. The nature of our
business is capital intensive, typically requiring an investment up front and a
resulting return on that investment. The resulting return and success of that
investment will vary depending on the prices we receive for the oil and natural
gas. Also, due to the geographic area that we operate in, the levels of capital
spending are significant and the lives of the reserves that we own are
relatively short. Historically, our reserves have a five to seven year life,
which tends to amplify the effect oil and natural gas price fluctuations have on
our Company.
35
Due to results that were below expectations during 2001, we ended the
year with lower reserves than those at the beginning of the year, despite $45
million in capital expenditures. In addition, lower production and lower
commodity prices caused our total debt and working capital deficit to increase
by $13.4 million and $7.8 million, respectively. In an effort to reduce the
working capital deficit, we have delayed most of the 2002 approved capital
budget of $25 million until April 1, 2002, at which time we will evaluate our
financial situation and decide at that point whether to proceed with the capital
projects or delay them further. By doing so, production and cash flows for 2002
could be negatively impacted. The capital budget for 2002 of $25 million
consists primarily of drilling, 45% of which we estimate will be exploratory and
55% of which we estimate will be developmental. The execution of this budget
depends on PANACO's ability to pay for the projects with cash flows from
operations.
Given these issues, PANACO engaged an investment bank in early 2002 to
help the Company explore strategic financial alternatives. The outcome of this
process may result in asset sales or the sale of the Company as a whole. No
assurances can be made that the Company will be able to implement any plan that
will resolve the working capital deficit, ensure we maintain compliance with our
Credit Facility and Senior Note covenants, or that a plan will be implemented in
a timely manner and, as a result, the Company may not be able to continue as a
going concern. In addition, any of these alternatives will most likely require
approval from PANACO's Credit Facility lenders and may require the approval of
our Senior Note holders as well as Shareholder approval.
We were required to amend our Credit Facility during the first quarter
of 2002 due to the inability to meet certain covenants contained in those
agreements. We believe these changes will allow PANACO to meet the requirements
of these agreements, however, we cannot assure you that we will be able to do
so. In addition, availability under the Credit Facility will be limited due to
higher borrowings.
In March 2002, the Credit Facility, with borrowings of $32.9 million,
was amended in order to cure covenants that we were not able to satisfy on
December 31, 2001. This amendment requires a working capital ratio (as defined
in the agreement) of 0.15 to 1.0 from January 1 to April 30, 2002, 0.20 to 1.0
from May 1 to January 1, 2003, and 0.25 to 1.0 thereafter. The amendment also
requires a trailing twelve-month EBITDA/interest coverage ratio ranging from a
monthly high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002, and 2.0 to
1.0 thereafter. Based on current projections, we believe we will be in
compliance with all of the terms of the Credit Facility through December 31,
2002. However, no assurances can be given that we will be in compliance through
December 31, 2002. PANACO's $100 million of Senior Notes require that we
maintain a total Adjusted Consolidated Net Tangible Asset Value ("ACNTA"),
as defined in the Indenture, 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. At December 31, 2001 PANACO did not meet this ratio. Actual
results through March 31, 2002 are not yet available, however, based on
increased market prices for oil and natural gas, we estimate that the Company
will be in compliance with the covenant at March 31, 2002. However, no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.
Change in Accounting Method
In accordance with our hedging policy, we expect to continue using
derivative financial instruments as a means of hedging prices we receive for our
oil and natural gas production. We have generally used swaps, collars or options
with counter parties that are major financial institutions or commodities
trading institutions. Through December 31, 2000 gains and losses from these
financial instruments have been recognized in revenues for the periods to which
the production covered by the derivative financial instruments relate.
Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments and
Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities, an amendment of FASB Statement No.
133. These statements establish accounting and reporting standards requiring
that derivative instruments (including certain derivative instruments embedded
in other contracts) be recorded at fair market value and included in the balance
sheet as assets or liabilities. The accounting for changes in the fair value of
a derivative instrument depends on the intended use of the derivative and the
resulting designation, which is established at the inception of a derivative.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in other comprehensive income
until the hedged item is recognized in earnings. Hedge effectiveness is measured
at least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time. Any change in fair value
resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings. All of our derivative financial instruments subject to
SFAS 133 have been designated as cash flow hedges.
36
Impact of Recently Issued Accounting Pronouncements
During 2001, the Financial Accounting Standards Board issued four new
pronouncements:
Statement 141, Business Combinations ("SFAS 141"), requires that the
purchase method of accounting be used to account for all business combinations
and applies to all business combinations initiated after June 30, 2001. The
statement also establishes specific criteria for the recognition of intangible
assets separately from goodwill. The provisions of this statement would be
applied were we to enter into any future business combination. The statement has
no impact on PANACO's historical financial statements.
Statement 142, Goodwill and Other Intangible Assets ("SFAS 142"),
requires that goodwill no longer be amortized but tested for impairment at least
annually. Other intangible assets are to be amortized over their useful lives
and reviewed for impairment. An intangible asset with an indefinite useful life
will not be amortized until its useful life becomes determinable. The effective
date of this statement is January 1, 2002. The provisions of this statement
would be applied if we were to enter into any future business combination
pursuant to which goodwill or other intangible assets were recognized. The
statement has no impact on PANACO's historical financial statements.
Statement 143, Accounting for Asset Retirement Obligations ("SFAS 143"),
requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long-lived asset. The Company
will be required to adopt SFAS 143 effective January 1, 2003 using a cumulative
effect approach to recognize transition amounts for asset retirement
obligations, asset retirement costs and accumulated depreciation. Currently, we
record estimated costs of dismantlement, removal, site reclamation, and similar
activities as part of our depreciation, depletion, and amortization for oil and
gas properties without recording a separate liability for such amounts. We have
not yet completed our assessment of the impact of SFAS 143 on our financial
condition and results of operations. We expect that adoption of the statement
will result in increases in the capitalized costs of our oil and gas properties
and in the recognition of additional liabilities related to asset retirement
obligations.
Statement 144, Accounting for the Impairment or Disposal of Long-Lived
Assets ("SFAS 144"), retains the fundamental provisions of SFAS 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of, for recognizing and measuring impairment losses while resolving significant
implementation issues associated with SFAS 121. SFAS 144 also expands the basic
provisions of APB Opinion No. 30, Reporting the Results of Operations -
Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary,
Unusual and Infrequently Occurring Events and Transactions, regarding
presentation of discontinued operations in the income statement. The scope for
reporting a discontinued operation has been expanded to include a "component" of
an entity. A component comprises operations and cash flows that can be clearly
distinguished from the rest of the entity. It could be a segment, a reporting
unit, a consolidated subsidiary, or an asset group. We have not yet completed
our evaluation of SFAS 144 and it's impact on our financial condition and
results of operations. We believe that the implementation will be largely
unchanged from SFAS 121.
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, to ensure sufficient revenues for debt service and capital expenditures
or to take advantage of unusual strength in the market. The type of hedge
agreement we enter into varies, based on among other factors, the market
conditions at the time.
During 2001, 2000 and 1999 we hedged the following percentages of our
oil and natural gas production. During 2001 PANACO entered into a swap for 61%
of our natural gas production and an option to put oil to a purchaser at a fixed
price on 30% of our oil production. During 2000 we entered into agreements to
put oil and natural gas to a purchaser at predetermined prices. During 1999 we
37
entered into a combination of options to put produced volumes to a purchaser at
a predetermined price and swaps based on a single predetermined price or a range
of high and low predetermined prices. Following is a summary of the results of
those years' hedging activities.
Volume Hedged Percentage of Actual Production Realized
Year Natural Gas (Bcf) Oil (MBbl) Natural Gas Oil Gain/(Loss)
---- ------------------------------- ------------------- -----------
1999 8.8 540 79% 46% ($4.6 million)
2000 3.7 422 27% 39% ($1.1 million)
2001 6.6 273 61% 30% $3.5 million
At December 31, 2001 we had $100 million in Senior Notes outstanding
with a fixed interest rate of 10 5/8%. We also had $32.9 million outstanding
under our Credit Facility at December 31, 2001. The Credit Facility is a
floating rate facility, with a fair value of $32.9 million. We did not have any
interest rate hedge agreements at December 31, 2001. On March 28, 2002 we put in
place two hedges for both oil and natural gas produced from May 1 through
October 31, 2002. The natural gas hedge is a cost-free collar on 3,000 MMbtu and
contains a minimum price of $3.00 per MMbtu and a maximum price of $3.45 per
MMbtu to be received for the quantity hedged. The oil hedge is a swap on 500
barrels of oil per day with prices ranging from $24.96 per barrel to $25.87 per
barrel for the quantity hedged. The volumes hedged account for 21% and 18%,
respectively, of PANACO's current estimates of total production for the periods
hedged.
Item 8. Financial Statements and Supplementary Data.
The Financial Statements are included beginning at F-1.
The following unaudited summarized quarterly financial data should be
read in conjunction with the Financial Statements, beginning on F-1 and Item 7.
- - "Managements Discussion and Analysis of Financial Condition and Results of
Operations." Amounts are in thousands, except per share data.
2001
----------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
Total revenues $ 26,316 $ 24,024 $ 16,685 $ 13,188
Operating income (loss) 8,272 (1,245) (1,498) (12,307)
Income (loss) before extraordinary item 3,366 (2,492) (26,608) (16,571)
Net income (loss) $ 3,366 $ (2,492) $ (26,608) $ (16,571)
=========== =========== =========== ==========
Net income (loss) per share $ 0.14 $ (0.10) $ (1.10) $ (0.68)
=========== =========== =========== ==========
2000
----------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
----------- ----------- ----------- -----------
Total revenues $ 15,619 $ 21,280 $ 24,911 $ 26,740
Operating income 3,853 6,939 7,784 12,787
Income before extraordinary item 253 30,639 2,462 5,801
Net income $ 253 $ 30,639 $ 2,462 $ 5,801
=========== =========== =========== ==========
Net income per share $ 0.01 $ 1.26 $ 0.10 $ 0.24
=========== =========== =========== ==========
Quarterly Periods Ending December 31, 2001
During the first quarter of 2001 PANACO drilled an unsuccessful well at
East Breaks 110, the primary factor in $3.9 million of exploratory dry hole
expense during the quarter.
38
In the second quarter of 2001, an impairment of oil and natural gas
properties totaling $6.5 million was recognized. The impairment was due to lower
estimates of future net revenues for our assets, due primarily to lower oil and
natural gas prices.
As oil and natural gas prices continued to decrease in the third quarter
of 2001, we were not able to project sufficient net income to utilize PANACO's
net operating loss carry-forwards. As such, a valuation allowance was
re-established for our deferred tax assets, resulting in a net charge to income
tax expense of $23 million.
During the fourth quarter of 2001 an additional $3.8 million of
exploratory dry hole expense was recorded based on an unsuccessful exploratory
well at Umbrella Point. In addition, this well required an impairment to
PANACO's unproved property. The impairment for the fourth quarter totaled $2.3
million, the majority of which is related to Umbrella Point.
Quarterly Periods Ending December 31, 2000
During the second and fourth quarters we received lawsuit settlements
totaling $1.0 million and $1.6 million, respectively. During the third quarter
of 2000 we recorded a $0.7 million severance charge in connection with the
resignation of a former employee and director.
During the second quarter we also recorded an income tax benefit of
$29.0 million due to the reversal of a deferred tax asset valuation allowance.
In the second quarter and the subsequent two quarters of 2000 we also began
recording income tax expense which totaled $1.1 million, $1.5 million and $3.7
million for the second, third and fourth quarters, respectively.
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, 2001. 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, 2001. 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, 2001. Such information is incorporated herein by reference.
39
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, 2001. Such information is incorporated herein by reference.
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.
None.
(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.
40
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.
10.25 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.
10.25.1 Second amendment to the Company's credit agreement filed as an exhibit on the Form 10-Q on
November 10, 2000, and incorporated herein by reference.
10.25.2 Third amendment to the Company's credit agreement.
10.25.3**** Sixth amendment to the Company's credit agreement.
10.25.4**** Seventh amendment to the Company's credit agreement.
10.27 Employment agreement between the Company and Robert G. Wonish filed as an exhibit on the
Form 10-Q on November 10, 2000, and incorporated herein by reference.
10.28 Form of stock option agreement between the Company and key employees.
*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.
41
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, and/or to find a new reservoir in a field previously found to be
productive of oil or natural gas in known reservoirs.
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.
42
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.
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 net 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, 2001, 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,
2001, 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.
43
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 an existing casing string at some selected depth.
The drill 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.
44
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\ Robert G. Wonish April 15, 2002
--------------
Robert G. Wonish, President and
Chief Operating 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\ Robert G. Wonish April 15, 2002
--------------
Robert G. Wonish, President and
Chief Operating Officer and Director
By: \s\ Todd R. Bart April 15, 2002
--------------
Todd R. Bart
Chief Financial Officer and
Principal Accounting Officer
By: \s\ Harold First April 15, 2002
--------------
Harold First, Director
By: \s\ A. Theodore Stautberg April 15, 2002
--------------
A. Theodore Stautberg, Jr., Director
By: \s\ James B. Kreamer April 15, 2002
--------------
James B. Kreamer, Director
By: \s\ Felix A. Pardo April 15, 2002
--------------
Felix A. Pardo, Director
By: \s\ Stanley Nortman April 15, 2002
--------------
Stanley Nortman, Director
By: \s\ George W. Hebard III April 15, 2002
--------------
George W. Hebard III, Director
45
PANACO, Inc.
INDEX TO FINANCIAL STATEMENTS
Beginning on
PANACO, Inc. - AUDITED FINANCIAL STATEMENTS Page Number
- ------------------------------------------- ------------
Independent Auditors' Report F-2
Consolidated Balance Sheets, December 31, 2001 and 2000 F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2000 and 1999 F-5
Consolidated Statements of Changes in Stockholders' Equity (Deficit)
for the Years Ended December 31, 2001, 2000 and 1999 F-6
Consolidated Statements of Changes in Comprehensive Income (Loss)
for the Year Ended December 31, 2001 F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999 F-8
Notes to Consolidated Financial Statements for the Years Ended
December 31, 2001, 2000 and 1999 F-9
F-1
Independent Auditors' Report
The Board of Directors and Shareholders of
PANACO, Inc.:
We have audited the accompanying consolidated balance sheets of PANACO, Inc. as
of December 31, 2001 and 2000, and the related consolidated statements of
operations, changes in stockholders' equity (deficit), changes in comprehensive
income (loss), and cash flows for each of the years in the three-year period
ended December 31, 2001. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of PANACO, Inc. as of
December 31, 2001 and 2000, and the results of its operations and its cash flows
for each of the years in the three-year period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States of
America.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 2 to the
financial statements, the Company has suffered recurring losses from operations,
has a net capital deficiency and restrictive debt covenants that raise
substantial doubt about its ability to continue as a going concern. Management's
plans in regard to these matters are also described in Note 2. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.
KPMG LLP
Houston, Texas
April 15, 2002
F-2
PANACO, Inc.
CONSOLIDATED BALANCE SHEETS
ASSETS
------
December 31,
------------
2001 2000
---- ----
CURRENT ASSETS
Cash $ 5,582,000 $ 2,878,000
Accounts receivable, net of an allowance
of $3,440,000 and $554,000, respectively 8,363,000 17,680,000
Accounts receivable-related party --- 300,000
Prepaid and other 917,000 907,000
--------------- ---------------
Total current assets 14,862,000 21,765,000
--------------- ---------------
OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
Oil and gas properties, proved 286,453,000 289,892,000
Less accumulated depreciation, depletion and amortization (183,867,000) (193,135,000)
Net unproved oil and gas properties 232,000 2,888,000
--------------- ---------------
Net oil and gas properties 102,818,000 99,645,000
--------------- ---------------
PIPELINES AND EQUIPMENT
Pipelines and equipment 26,532,000 26,409,000
Less accumulated depreciation (10,939,000) (8,256,000)
--------------- ---------------
Net pipelines and equipment 15,593,000 18,153,000
--------------- ---------------
OTHER ASSETS
Restricted deposits 11,011,000 8,625,000
Deferred financing costs, net 1,780,000 3,128,000
Deferred income taxes --- 22,763,000
--------------- ---------------
Total other assets 12,791,000 34,516,000
--------------- ---------------
TOTAL ASSETS $146,064,000 $174,079,000
=============== ===============
(Continued)
See accompanying notes to consolidated financial statements.
F-3
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
----------------------------------------------
December 31,
2001 2000
---- ----
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 35,185,000 $ 31,963,000
Interest payable 2,864,000 2,917,000
Gas imbalance payable 1,149,000 2,860,000
Restricted cash payable 25,000 629,000
-------------- --------------
Total current liabilities 39,223,000 38,369,000
-------------- --------------
DEFERRED CREDITS 1,505,000 1,609,000
LONG-TERM DEBT 135,120,000 121,693,000
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;
24,359,695 and 24,323,521 shares
issued and outstanding, respectively 247,000 246,000
Additional paid-in capital 69,089,000 68,977,000
Accumulated deficit (99,120,000) (56,815,000)
-------------- --------------
Total stockholders' equity (deficit) (29,784,000) 12,408,000
-------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) $ 146,064,000 $ 174,079,000
============= =============
See accompanying notes to consolidated financial statements.
F-4
PANACO, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
-----------------------------
2001 2000 1999
---- ---- ----
REVENUES
Oil and natural gas sales $ 76,246,000 $ 88,550,000 $ 42,672,000
Gain on property sales 3,967,000 1,938,000 ---
Lawsuit recoveries --- 2,575,000 ---
-------------- -------------- --------------
Total 80,213,000 93,063,000 42,672,000
COSTS AND EXPENSES
Lease operating expense 24,658,000 20,876,000 17,740,000
Depreciation, depletion and amortization 34,486,000 27,030,000 26,439,000
General and administrative expense 4,047,000 4,878,000 3,930,000
Bad debt expense 3,348,000 344,000 139,000
Production and ad valorem taxes 1,997,000 2,089,000 1,202,000
Exploratory dry hole expense 8,375,000 4,361,000 1,050,000
Geological and geophysical expense 945,000 1,376,000 1,429,000
Impairment of oil and gas properties 9,135,000 --- 13,202,000
Severance expense --- 746,000 ---
-------------- -------------- --------------
Total 86,991,000 61,700,000 65,131,000
-------------- -------------- --------------
OPERATING INCOME (LOSS) (6,778,000) 31,363,000 (22,459,000)
-------------- -------------- --------------
OTHER INCOME (EXPENSE)
Interest income 568,000 497,000 255,000
Interest expense (13,088,000) (15,388,000) (12,692,000)
Other (273,000) --- ---
-------------- -------------- --------------
Total (12,793,000) (14,891,000) (12,437,000)
-------------- -------------- --------------
INCOME (LOSS) BEFORE INCOME
TAXES AND EXTRAORDINARY ITEM (19,571,000) 16,472,000 (34,896,000)
INCOME TAXES (BENEFIT) 22,734,000 (22,683,000) ---
-------------- -------------- --------------
INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM (42,305,000) 39,155,000 (34,896,000)
EXTRAORDINARY ITEM - Loss on early
retirement of debt --- --- (131,000)
-------------- -------------- ---------------
NET INCOME (LOSS) $ (42,305,000) $ 39,155,000 $ (35,027,000)
============== ============== ===============
BASIC AND DILUTED EARNINGS (LOSS)
PER SHARE
Income (loss) before extraordinary item $ (1.74) $ 1.61 $ (1.45)
Extraordinary item --- --- (.01)
--------------- -------------- ---------------
Net income (loss) $ (1.74) $ 1.61 $ (1.46)
=============== ============== ===============
BASIC SHARES OUTSTANDING 24,349,784 24,261,830 23,940,785
=============== ============== ===============
DILUTED SHARES OUTSTANDING 24,349,784 24,317,942 23,940,785
=============== ============== ===============
See accompanying notes to consolidated financial statements.
F-5
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Total
Number of Common Additional Stockholders'
Common Share Paid-In Treasury Accumulated Equity
Shares Par Value Capital Stock Deficit (Deficit)
---------- --------- ---------- -------- ------------ --------------
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)
---------- ------- ---------- -------- ----------- -----------
Net income --- --- --- --- 39,155,000 39,155,000
Shares issued under Employee
Stock Ownership Plan 337,000 3,000 125,000 --- --- 128,000
---------- ------- ---------- -------- ----------- -----------
Balances, December 31, 2000 24,323,521 246,000 68,977,000 --- (56,815,000) 12,408,000
---------- ------- ---------- -------- ----------- -----------
Net loss --- --- --- --- (42,305,000) (42,305,000)
Shares issued under Employee
Stock Ownership Plan 36,174 1,000 112,000 --- --- 113,000
---------- ------- ---------- -------- ----------- -----------
Balances, December 31, 2001 24,359,695 $247,000 $69,089,000 $ --- $(99,120,000) $(29,784,000)
========== ======= ========== ======== =========== ===========
See accompanying notes to consolidated financial statements.
F-6
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN COMPREHENSIVE INCOME (LOSS)
FOR THE YEAR ENDED DECEMBER 31, 2001
Accumulated Other Comprehensive Income (Loss), December 31, 2000 $ --
Net Loss (42,305,000)
Accumulated Other Comprehensive Income
Cumulative effect of change in accounting principle - January 1, 2001 (9,881,000)
Changes in fair value of outstanding hedging positions 13,417,000
Financial derivative settlements transferred from
Accumulated Other Comprehensive Income (3,536,000)
-------------
Accumulated Other Comprehensive Income --
-------------
Comprehensive Income (Loss) $ (42,305,000)
=============
There were no other items in Comprehensive Income (Loss) during 2001.
F-7
PANACO, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (42,305,000) $ 39,155,000 $ (35,027,000)
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Extraordinary item --- --- 131,000
Depreciation, depletion and amortization 34,486,000 27,030,000 26,439,000
Impairment of oil and gas properties 9,135,000 --- 13,202,000
Exploratory dry hole expense 8,375,000 4,361,000 1,050,000
Deferred income tax benefit 22,763,000 (22,763,000) ---
ESOP stock contribution expense 113,000 128,000 250,000
Gain on property sales (3,967,000) (1,938,000) ---
Plug and abandoning of wells and platforms (6,930,000) --- ---
Changes in operating assets and liabilities:
Accounts receivable 9,285,000 (8,005,000) (1,343,000)
Related party note receivable 300,000 16,000 2,000
Prepaid and other (501,000) (177,000) (347,000)
Accounts payable 3,947,000 11,555,000 3,682,000
Deferred credits (104,000) 1,609,000 ---
Gas imbalance payable (348,000) 2,860,000 ---
Interest payable (53,000) (86,000) 258,000
------------ ------------ -------------
Net cash provided by operating activities 34,196,000 53,745,000 8,297,000
------------ ------------ -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the sale of oil and gas properties 2,843,000 783,000 1,036,000
Capital expenditures and acquisitions (45,012,000) (37,192,000) (26,429,000)
Increase in restricted deposits (2,386,000) (2,395,000) (1,883,000)
------------ ------------ ------------
Net cash used in investing activities (44,555,000) (38,804,000) (27,276,000)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Long-term debt proceeds 24,768,000 22,791,000 47,153,000
Repayment of long-term debt (11,341,000) (40,000,000) (24,000,000)
Deferred financing costs (364,000) (429,000) (2,051,000)
------------ ------------ ------------
Net cash provided by (used in) financing activities 13,063,000 (17,638,000) 21,102,000
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH $ 2,704,000 $ (2,697,000) $ 2,123,000
CASH AT BEGINNING OF YEAR 2,878,000 5,575,000 3,452,000
------------ ------------ ------------
CASH AT END OF YEAR $ 5,582,000 $ 2,878,000 $ 5,575,000
============ ============ ============
See accompanying notes to consolidated financial statements.
F-8
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
For the year ended December 31, 2001:
- -------------------------------------
The Company issued 36,174 common shares valued at $113,000 to the ESOP. The
change in accounts payable from December 31, 2000 to December 31, 2001 excludes
this non-cash reduction of the liability.
For the year ended December 31, 2000:
- -------------------------------------
The Company issued 337,000 common shares valued at $128,000 to the ESOP. The
change in accounts payable from December 31, 1999 to December 31, 2000 excludes
this non-cash reduction of the liability.
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.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year ended December 31:
2001 2000 1999
---- ---- ----
Interest (gross interest paid) $ 13,257,000 $ 15,682,000 $ 12,978,000
============= ============= =============
Income taxes $ --- $ 145,000 $ ---
============= ============= =============
F-9
PANACO, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 and 1999
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
------------------------------------------
Nature of Business
- ------------------
PANACO, Inc. (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. The Company operates a majority of its assets in order
to control the operations and the timing of expenditures. The majority of the
Company's properties are located in state or federal waters of the Gulf of
Mexico, where the costs of operations, productions rates and reserve potential
are generally greater than properties located onshore. The Company's assets and
operations are primarily concentrated on a small group of properties. The
Company has grown primarily by acquiring properties that have additional
development potential and improving the economics of those properties by
exploiting the oil and natural reserves and reducing operating costs and making
them more efficient.
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, 2001 the Company's
imbalance position was an over-produced, or payable balance of 265,000 Mcf
valued at $1.1 million. At December 31, 2000 the Company's imbalance position
was an over-produced, or payable balance of 610,000 Mcf valued at $2.9 million.
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 9). 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. Realized gains and losses are recognized
monthly as adjustments to revenues in the same production period as the hedged
production. Contracts are placed with entities 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.
Effective January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133 ("SFAS133"), Accounting for Derivative Instruments and Hedging
Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and
Certain Hedging Activities, an amendment of FASB Statement No. 133. These
statements establish accounting and reporting standards requiring that
derivative instruments (including certain derivative instruments embedded in
other contracts) be recorded at fair market value and included in the balance
sheet as assets or liabilities. The accounting for changes in the fair value of
a derivative instrument depends on the intended use of the derivative and the
resulting designation, which is established at the inception of a derivative.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective, are recognized in other comprehensive income
until the hedged item is recognized in earnings. Hedge effectiveness is measured
at least quarterly based on the relative changes in fair value between the
derivative contract and the hedged item over time. Any change in fair value
resulting from ineffectiveness, as defined by SFAS 133, is recognized
immediately in earnings. On December 31, 2001 the Company did not have any hedge
agreements in place.
F-10
Gains and losses on hedging instruments related to Accumulated Other
Comprehensive Income/Loss and adjustments to carrying amounts on hedged
production are included in natural gas or crude oil production revenues in the
period that the related production is delivered. Gains and losses of hedging
instruments, which represent hedge ineffectiveness and changes in the time value
component of options, are included in Other Income/Loss in the period in which
they occur.
For the Company's natural gas swap, on January 1, 2001, in accordance with the
transition provisions of SFAS 133, the Company recorded a loss of $9.9 million
in Other Comprehensive Income/Loss representing the cumulative effect of an
accounting change to recognize the fair value of the natural gas swap. The
Company also recorded cash flow hedge derivative liabilities of $9.9 million in
accounts payable and accrued liabilities.
All hedge transactions are subject to the Company's risk management policy and
are approved by the Board of Directors, which does not permit speculative
positions. The Company formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objectives and
strategy for undertaking the hedge. This process includes specific
identification of the hedging instrument and the hedge transaction, the nature
of the risk being hedged and how the hedging instrument's effectiveness will be
assessed. Both at the inception of the hedge and on an ongoing basis, the
Company assesses whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in cash flows of hedged items.
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 carry-forwards. 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.
Non-drilling exploratory costs, including geological and geophysical costs and
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 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 depletion is
determined on a depletable unit basis using the unit-of-production method.
Estimated future abandonment costs are recorded by charges to depreciation and
depletion expense over the lives of the proved reserves of the properties.
The Company performs a review for impairment of proved oil and gas properties on
a depletable unit basis when circumstances suggest there is a need for such a
review. For each depletable unit determined to be impaired, an impairment loss
equal to the difference between the carrying value and the fair value of the
depletable unit will be recognized. Fair value, on a depletable unit basis, is
estimated to be the present value of expected future cash flows computed by
applying estimated future oil and gas prices, as determined by management, to
estimated future production of oil and gas reserves over the economic lives of
the reserves. Future cash flows are based upon the Company's estimate of proved
reserves.
F-11
During 2001 the Company recorded asset impairments totaling $9.1 million. The
unsuccessful development of potential reserves in the Umbrella Point Field
accounted for $1.9 million of the impairment in 2001. The balance of the
impairment was primarily due to lower estimates of future net revenues from the
Company's proved reserves caused mainly by lower prices for oil and natural gas
along with reserve revisions. The Company also recorded an asset impairment in
1999 of $13.2 million for unproved properties that the Company did not develop
and for lowered reserve estimates in the High Island 309 Fields. During 2001,
the Company sold the High Island 309 Fields and recognized a gain of $4.0
million on the sale. The Company also recognized a net gain of $1.9 million from
the sale of three properties in 2000.
Environment Liabilities
- -----------------------
The Company accrues for losses associated with environmental remediation
obligations when such losses are probable and can be reasonably estimated.
Accruals for estimated losses from environmental remediation obligations
generally are recognized no later than the time of the completion of the
remedial feasibility study. These accruals are adjusted as further information
develops or circumstances change. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value. Recoveries of
environmental remediation costs from other parties are recorded as assets when
their receipt is deemed probable.
Capitalized Interest
- --------------------
The Company capitalizes interest costs associated with unproved properties under
development. Interest capitalized in 2001, 2000 and 1999 was $116,000, $208,000,
and $544,000, 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.
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. During all
or part of the periods presented, the Company had options outstanding that were
exercisable at prices above the market and are not included in per share
calculations. In addition, due to losses incurred in 1999 and 2001, common stock
equivalents would be anti-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 10.
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.
F-12
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 Receivable - Related Party
- -----------------------------------
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. On October 1, 2000 the officer resigned from all of his
positions with the Company. As part of the severance agreement, $300,000 of the
amount due the employee was withheld by the Company and interest on the note
stopped accruing. The $300,000 due the employee was used to repay this note in
January 2001.
Note 2 - WORKING CAPITAL DEFICIT AND RESTRICTIVE COVENANTS
-------------------------------------------------
Due to substantial losses incurred in 1999 and 2001 and less than anticipated
results from PANACO's drilling program in late 2000 and most of 2001, the
Company accumulated a significant working capital deficit as of December 31,
2001. The deficit totaled $24.4 million. The lack of performance from wells
drilled during 2000 and 2001, along with decreased commodity prices in late
2001, reduced estimated future net cash flows and availability under the
Company's Credit Facility to a point at which there is substantial doubt about
the Company's ability to reduce this deficit in a timely manner.
Given this situation, PANACO engaged an investment bank in early 2002 to help
the Company explore strategic financial alternatives. The outcome of this
process may result in asset sales or the sale of the Company as a whole. The
Company is also in discussions to increase the amount of its Credit Facility,
which may require a waiver from the holders of the Senior Notes. No assurances
can be made that the Company will be able to implement any plan that will
resolve the working capital deficit or that a plan will be implemented in a
timely manner. In addition, some of these alternatives may require approval from
PANACO's Credit Facility lenders or the approval of our Senior Note holders as
well as Shareholder approval.
In March 2002, the Credit Facility, with borrowings of $32.9 million,
was amended in order to cure covenants that we were not able to satisfy on
December 31, 2001. This amendment requires a working capital ratio (as defined
in the agreement) of 0.15 to 1.0 from January 1 to April 30, 2002, 0.20 to 1.0
from May 1 to January 1, 2003, and 0.25 to 1.0 thereafter. The amendment also
requires a trailing twelve-month EBITDA/interest coverage ratio ranging from a
monthly high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002, and 2.0 to
1.0 thereafter. Based on current projections, we believe we will be in
compliance with all of the terms of the Credit Facility through December 31,
2002. However, no assurances can be given that we will be in compliance through
December 31, 2002. PANACO's $100 million of Senior Notes require that we
maintain a total Adjusted Consolidated Net Tangible Asset Value ("ACNTA"),
as defined in the Indenture, 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. At December 31, 2001 PANACO did not meet this ratio. Actual
results through December 31, 2002 are not yet available, however, based on
increased market prices for oil and natural gas, we estimate that the Company
will be in compliance with the covenant at March 31, 2002. However, no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.
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
$195,000, $330,000, and $337,000 in costs for the years ended December 31, 2001,
2000 and 1999, respectively.
Note 4 - RESTRICTED DEPOSITS
-------------------
Pursuant to existing agreements with former property owners and in accordance
with requirements of the U.S. Department of Interior's Minerals Management
Service ("MMS"), the Company has put in place surety bonds and/or escrow
agreements to provide satisfaction of its eventual responsibility to plug and
abandon wells and remove structures when certain fields are no longer in use. As
part of its agreement with the underwriter of the surety bonds, the Company has
established bank trust and escrow accounts in favor of either the surety bond
underwriter or the former owners of the particular fields.
F-13
In the West Delta Fields and the East Breaks 109 and 110 Fields, the Company
established an escrow for both Fields in favor of the surety bond underwriter,
who provides a surety bond to the former owners of the West Delta Fields and to
the MMS. The balance in this escrow account was $5.6 million at December 31,
2001 and requires quarterly deposits of $375,000 until the account balance
reaches $7.8 million.
In the East Breaks 165 and 209 Fields the Company established an escrow account
in favor of the surety bond underwriter, who provides surety bonds to both the
MMS and the former owner of the Fields. The balance in this escrow account was
$4.7 million at December 31, 2001 and requires quarterly deposits of $250,000
until the account balance reaches $6.5 million.
The Company has also established an escrow account in favor of BP under which
the Company will deposit 10% of the net cash flows from the properties, as
defined in the agreement, from the properties acquired from BP. This escrow
account balance was $0.7 million at December 31, 2001.
Note 5 - LAWSUIT RECOVERIES
------------------
During 2000 the Company settled two lawsuits it had filed, for which it received
a total of $2.6 million. The first suit was settled with the insurance carrier
of a third party that caused a fire at the West Delta Fields in 1996. The
proceeds of $1.0 million were for the lost revenues during the period which the
Company was not able to produce and sell its oil and natural gas. The second
suit was the recovery of net revenues from a well based on an incorrect payout
calculation by the operator, resulting in a settlement received by the Company
totaling $1.6 million.
Note 6 - LONG-TERM DEBT
--------------
2001 2000
---- ----
10 5/8 % Senior Notes due 2004(a) $ 100,000,000 $ 100,000,000
Revolving credit facility due 2003(b) 32,871,000 19,444,000
Production payment(c) 2,249,000 2,249,000
---------------- ---------------
135,120,000 121,693,000
Less current portion --- ---
---------------- ---------------
Long-term debt $ 135,120,000 $ 121,693,000
================ ===============
(a) In October 1997 the Company issued $100 million of 10.625% Senior Notes due
2004. Interest is payable semi-annually April 1 and October 1 of each year.
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 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. The Company must maintain a total Adjusted Consolidated Net
Tangible Asset Value ("ACNTA"), as defined in the Indenture, equal to 125%
of indebtedness at the end of each quarter. At December 31, 2001 the
Company did not meet this ratio. Should this condition continue to exist
for two successive quarters, the Company is required to make an offer to
F-14
the Senior Note holders to repurchase an amount of the notes (at par plus
accrued interest) sufficient to meet the ratio required in the indenture.
Based on increased market prices for oil and natural gas, the Company
estimates that it will be in compliance with this covenant at March 31,
2002 and will not be required to make such an offer to the holders of the
Senior Notes. However, no assurances can be given that the Company will
meet this covenant or that PANACO will be able to repurchase the amount of
the notes required under the Indenture. As a result, the Company may not be
able to continue as a going concern. See Note 2.
(b) In November 2001, the Company amended a Credit Facility originally entered
into in October 1999. The facility is for two years and provides up to $40
million, depending on the borrowing base as calculated in accordance with
the agreement. The borrowing base is calculated as a percentage of the
future net cash flows from its oil and natural gas reserves, discounted at
10% annually. The Company's borrowing base at December 31, 2001 was $40
million, with availability of $6.1 million, of which $1.3 million was
reserved for a letter of credit. Interest on the loan is computed at Wells
Fargo's prime rate plus 0.25% to 0.75%, or at LIBOR plus 2.25% to 2.75%,
with the percentage increases depending on the percentage of the facility
being used, and in any event, a minimum interest rate of 6.75%. The Credit
Facility is collateralized by a first mortgage on the Company's properties.
In March 2002, the Credit Facility was amended in order to cure covenants
that the Company was not able to satisfy on December 31, 2001. This
amendment requires a working capital ratio (as defined in the agreement) of
0.15 to 1.0 from January 1 to April 30, 2002, 0.20 to 1.0 from May 1 to
January 1, 2003, and 0.25 to 1.0 thereafter. The amendment also requires a
trailing twelve-month EBITDA/interest coverage ratio ranging from a monthly
high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0
thereafter. In addition, the amendment eliminates the requirement for
hedges until March 31, 2002. Based on current projections, the Company
believes it will be in compliance with all of the terms of the agreement
through December 31, 2002. However, no assurances can be given that the
Company will be in compliance through December 31, 2002. As a result,
PANACO may not be able to continue as a going concern. See Note 2. The
agreement also contains limitations on dividends, mergers and asset sales.
(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
upon acquisition. The agreement requires repayment of principal plus an
amount sufficient to provide an internal rate of return of 18%.
Note 7 - EXTRAORDINARY ITEM-LOSS ON EARLY RETIREMENT OF DEBT
---------------------------------------------------
In 1999 the Company replaced its Credit Facility, see Note 6. In connection with
the prepayment of the previous Credit Facility, the Company wrote off the
remaining deferred financing costs associated with the previous facility.
Note 8 - SEVERANCE EXPENSE
-----------------
Effective October 1, 2000 the Company's President and Chief Executive Officer
resigned his position as an employee and director of the Company. Pursuant to an
employment contract between the Company and the employee, the employee was
entitled to receive two years of salary and benefits. The Company had the right
to offset the amounts due the employee with principal and interest on a
promissory note due the Company. The severance charge incurred in the third
quarter of 2000 relates to the settlement of all amounts due the employee under
the agreement, including the remaining salary and coverage under the Company's
various insurance policies. The employee was paid a portion of this amount due
in October 2000 and the remaining amount due the employee was offset against the
principal amount of the promissory note in January 2001. Effective October 1,
2000, the Company's Chief Operating Officer took over as President of the
Company.
Note 9 - ADOPTION OF SFAS 133
--------------------
On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
F-15
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. Currently, the Company
uses only cash flow hedges and the remaining discussion will relate exclusively
to this type of derivative instrument. If the derivative qualifies for hedge
accounting, the gain or loss on the derivative is deferred in Accumulated Other
Comprehensive Income/Loss, a component of Stockholders' Equity (Deficit), to the
extent the hedge is effective.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. The Company measures effectiveness on a quarterly basis. Hedge accounting
is discontinued prospectively when a hedge instrument becomes ineffective. Gains
and losses deferred in Accumulated Other Comprehensive Income/Loss related to
cash flow hedges that become ineffective remain unchanged until the related
production is delivered. If the Company determines that it is probable that a
hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately.
The Company periodically enters into derivative commodity instruments to hedge
its exposure to price fluctuation on natural gas and crude oil production. For
2001, the Company entered into an option to put 1,000 barrels of oil per day at
$25.00 per barrel to a purchaser through September 30, 2001 for a total of
273,000 barrels. In addition, the Company entered into a natural gas price swap
covering 6.6 Bcf of production for the entire twelve months of 2001 at an
average price of $4.91 per MMbtu. On December 31, 2001, the Company did not have
any hedge agreements in place.
The Company has historically 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, cost free collars, or put options. 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. Put options insured a minimum
price to be received for the Company's oil. The following is a summary of those
years' hedging activities.
Volume Hedged Percentage of Actual Production Realized
Year Natural Gas (Bcf) Oil (MBbl) Natural Gas Oil Gain/(Loss)
- ---- ----------------- ---------- ----------- --- -----------
2001 6.6 273 61% 30% $3.5 million
2000 3.7 422 27% 39% ($1.1 million)
1999 8.8 540 79% 46% ($4.6 million)
Note 10 - STOCK OPTIONS
-------------
During 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 option's grant.
F-16
During 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
expired June 20, 2000.
During 2000 the Company issued 500,000 options at $1.92 per share, the market
closing price on the grant date of August 16, 2000, to officers of the Company.
The options vest ratably over five years and expire six years from the grant
date.
2001 2000 1999
------------------------ ----------------------- -----------------------
Wtd. Wtd. Wtd.
Avg. Avg. Avg.
Shares Ex. Price Shares Ex. Price Shares Ex. Price
------ --------- ------ --------- ------ ---------
Outstanding at beginning of year 500,000 $ 1.92 1,150,000 $ 4.45 1,150,000 $ 4.45
Granted --- --- 500,000 1.92 --- ---
Exercised --- --- --- --- --- ---
Forfeited (75,000) 1.92 (1,150,000) 4.45 --- 4.45
------- ----- --------- ----- --------- -----
Outstanding at end of year 425,000 1.92 500,000 1.92 1,150,000 4.45
Exercisable at end of year 85,000 $ 1.92 --- $ 1.92 1,150,000 $ 4.45
Fair value of options granted N/A $1.71 N/A
The fair value of each option granted in 2000 was estimated at the date of grant
using the Black-Scholes Modified American Option Pricing Model with the
following assumptions:
Expected option life-years 5
Risk-free interest rate 6.13%
Dividend yield 0%
Volatility 137%
Fair-value $1.71
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 unaudited net income (loss) and earnings (loss) per share for
2001, 2000 and 1999 would have been as shown below:
(Unaudited) (Unaudited) (Unaudited)
2001 2000 1999
------------- ------------ -------------
Net income (loss) As reported $(42,305,000) $ 39,155,000 $(35,027,000)
- -----------------
Pro forma $(42,450,000) $ 39,027,000 $(35,311,000)
Net income (loss) per share: As reported, basic
- ----------------------------
and diluted: $ (1.74) $ 1.61 $ (1.46)
Pro forma:
Basic $ (1.74) $ 1.61 $ (1.47)
Diluted $ (1.74) $ 1.60 $ (1.47)
Note 11 - MAJOR CUSTOMERS
---------------
During 2001, Plains Resources, the purchaser of a majority of the Company's oil
production, accounted for 18% of total oil and natural gas sales and the
purchaser of a majority of the Company's natural gas production, Enron North
America, accounted for 51% of total oil and natural gas sales. In 2000, Plains
Resources accounted for 23% of total oil and natural gas sales, while Enron
North America accounted for 39% of total oil and natural gas sales. During 1999,
the Company's largest oil and natural gas purchasers accounted for 37% and 39%,
respectively, of total oil and natural gas sales.
During 2001 the Company wrote off a receivable from Enron North America, the
natural gas purchaser that accounted for 51% of total oil and natural gas sales.
F-17
The amount written off included $1.8 million for natural gas sold to Enron and
$1.2 million for the final payment due under a natural gas swap agreement. Since
December 2001 the Company has replaced Enron as a natural gas purchaser.
Note 12 - INCOME TAXES
------------
At December 31, 2001, the Company had net operating loss carry forwards for
federal income tax purposes of approximately $108 million which are available to
offset future federal taxable income through 2021. 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, the
purchase of common stock of an entity acquired in 1997 and other changes in
stock ownership.
Significant components of the Company's deferred tax assets (liabilities) as of
December 31 are as follows:
2001 2000
------------------ ------------------
Deferred tax assets (liabilities)
Fixed asset basis differences $ (12,474,000) $ (14,733,000)
Net operating loss carry forwards 37,675,000 35,130,000
State Taxes 2,566,000 2,001,000
Other 2,298,000 365,000
------------------ ------------------
Net deferred tax assets 30,065,000 22,763,000
------------------ ------------------
Valuation allowance for deferred tax assets (30,065,000) ---
------------------ ------------------
Total net deferred tax assets (liabilities) $ --- $ 22,763,000
================== ==================
At December 31, 2001 the Company determined that it is more likely than not that
the deferred tax assets will not be realized, consequently the valuation
allowance was increased by $30 million. This determination was based on the
Company's estimates of future net income, which were not sufficient to utilize
the net operating loss carry-forwards.
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:
2001 2000 1999
------ ------ ------
Statutory federal income tax rate (35%) 35% (35%)
State income taxes, net of federal benefit (3) 3 (3)
Adjustments to valuation allowance 154 (176) 38
Effective rate 116% (138%) 0%
Note 13 - COMMITMENTS AND CONTINGENCIES
-----------------------------
The Company is subject to various legal proceedings and claims which arise in
the ordinary course of business. In the opinion of management, the amount of
liability, if any, with the respect to these actions would not materially affect
the financial position of the Company or its results of operation.
The Company has commitments under an operating lease agreement for office space
through November 30, 2004. At December 31, 2001, the future minimum rental
payments due under the lease are as follows:
2002 $ 459,000
2003 459,000
2004 421,000
--------------
Total $ 1,339,000
==============
F-18
Note 14 - 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:
2001 2000 1999
--------------- --------------- ----------------
Property acquisition costs, proved $ 3,873,000 $ 3,395,000 $ ---
Property acquisition costs, unproved 349,000 208,000 544,000
Exploration expenses 9,320,000 5,737,000 2,479,000
Development costs 32,292,000 28,613,000 24,777,000
Quantities of Oil and Gas Reserves
- ----------------------------------
The estimates of proved reserve quantities at December 31, 2001, are based upon
reports of third party petroleum engineers (Ryder Scott Company, Netherland,
Sewell & Associates, Inc., W.D. Von Gonten & Co. and McCune Engineering, P.E.)
and do not purport to reflect realizable values or fair market values of
reserves. It should be emphasized that reserve estimates are inherently
imprecise and accordingly, these estimates are expected to change as future
information becomes available. These are estimates only and should not be
construed as exact amounts. All reserves are located in the United States.
Proved reserves are estimated reserves of natural gas and crude oil and
condensate that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those expected
to be recovered through existing wells, equipment and operating methods.
Proved developed and undeveloped reserves: Oil Gas
(BBLS) (MCF)
------ -----
Estimated reserves as of December 31, 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
Production (1,070,000) (13,547,000)
Extensions and discoveries 154,000 14,807,000
Sale of minerals in-place --- (637,000)
Purchase of minerals in-place 650,000 658,000
Revisions of previous estimates (290,000) (1,827,000)
------------ ------------
Estimated reserves as of December 31, 2000 8,137,000 82,222,000
Production (923,000) (10,703,000)
Extensions and discoveries 354,000 7,705,000
Sale of minerals in-place (3,000) (2,191,000)
Purchase of minerals in-place 1,134,000 289,000
Revisions of previous estimates (846,000) (10,382,000)
------------ ------------
Estimated reserves as of December 31, 2001 7,853,000 66,940,000
============ ============
F-19
Proved developed reserves: Oil Gas
(BBLS) (MCF)
------ -----
December 31, 1999 5,351,000 40,627,000
=========== ==========
December 31, 2000 4,460,000 49,945,000
=========== ==========
December 31, 2001 4,247,000 33,607,000
=========== ==========
Standardized Measure of Discounted Future Net Cash Flows
- --------------------------------------------------------
Future cash inflows are computed by applying year-end prices of oil and gas
(with consideration of price changes only to the extent provided by contractual
arrangements) to the year-end estimated future production of proved oil and gas
reserves. The base prices used for the Pretax PV-10 calculation were public
market prices on December 31 and adjusted by differentials to those market
prices. These price adjustments were done on a property-by-property basis for
the quality of the oil and natural gas and for transportation to the appropriate
location. The average net prices in the Pretax PV-10 value at December 31, 2001
were $2.69 per Mcf of natural gas and $18.56 per barrel of oil. 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:
2001 2000 1999
-----------------------------------------------------------
Future cash inflows $ 326,718,000 $ 1,017,214,000 $ 420,060,000
Future costs:
Production (117,225,000) (167,180,000) (98,972,000)
Development (76,232,000) (88,604,000) (68,659,000)
----------------- ------------------- ------------------
Future production and development costs (193,457,000) (255,784,000) (167,631,000)
----------------- ------------------- ------------------
Net cash flows-before tax 133,261,000 761,430,000 252,429,000
Future income tax expenses --- (204,875,000) ---
----------------- ------------------- ------------------
Future net cash flows 133,261,000 556,555,000 252,429,000
10% annual discount for estimated
timing of cash flows (44,018,000) (148,540,000) (71,163,000)
----------------- ------------------- ------------------
Standardized measure of discounted
Net cash flows $ 89,243,000 $ 408,015,000 $ 181,266,000
================= =================== ==================
F-20
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:
2001 2000 1999
----------------- ----------------- -----------------
Beginning balance $ 408,015,000 $ 181,266,000 $ 94,580,000
Sales, net of production costs (49,591,000) (65,301,000) (23,632,000)
Increase due to passage of time
(accretion of discount) 53,291,000 18,127,000 9,454,000
Purchase of minerals in place 8,199,000 10,785,000 ---
Sales of minerals in place (2,595,000) (345,000) (1,037,000)
Net change in sales prices, net of
production costs (413,885,000) 327,247,000 77,935,000
Revisions of quantity estimates (19,647,000) (16,026,000) 24,111,000
Extensions and discoveries, net of future
production and development costs 15,091,000 109,442,000 17,864,000
Net changes in income taxes 124,892,000 (124,892,000) ---
Changes in future development costs 1,006,000 (9,987,000) (7,789,000)
Changes of production rates (timing)
and other (35,533,000) (22,302,000) (10,179,000)
-------------- -------------- -------------
Net increase (decrease) (318,772,000) 226,748,000 86,727,000
-------------- -------------- -------------
Ending balance $ 89,243,000 $ 408,014,000 $ 181,307,000
============== ============== =============
F-21
EXHIBIT 10.25.3
SIXTH AMENDMENT TO AMENDED AND RESTATED
LOAN AND SECURITY AGREEMENT
---------------------------
THIS SIXTH AMENDMENT TO AMENDED AND RESTATED LOAN AND SECURITY
AGREEMENT (this "Amendment") is made and entered into as of November ____, 2001,
by and among: PANACO, INC., a Delaware corporation ("Borrower") which is the
sole surviving corporation of the merger by Panaco Production Company, a Texas
corporation ("PPC") and Goldking Acquisition Corporation, a Delaware corporation
("GAC"), with and into Borrower and is the successor-by-merger to PPC and GAC
thereunder; the financial institutions listed on the signature pages hereof
(such financial institutions, together with their respective successors and
assigns, are referred to hereinafter each individually as a "Lender" and
collectively as the "Lenders"); and FOOTHILL CAPITAL CORPORATION, a California
corporation, as agent for the Lenders ("Agent").
RECITALS
--------
A. Borrower, PPC (prior to its merger with and into Borrower), Agent
and Lenders have entered into that certain Amended and Restated Loan and
Security Agreement, dated as of September 30, 1999, as amended by that certain
First Amendment to Amended and Restated Loan and Security Agreement, dated
November 30, 1999, as amended by that certain Second Amendment to Amended and
Restated Loan and Security Agreement, dated September 29, 2000, as amended by
that certain Third Amendment to Amended and Restated Loan and Security
Agreement, dated December 21, 2000, as amended by that certain Fourth Amendment
to Amended and Restated Loan and Security Agreement, dated September 30, 2001,
and as amended by that certain Fifth Amendment to Amended and Restated Loan and
Security Agreement, dated October 29, 2001 (as so amended, the "Loan
Agreement").
B. Capitalized terms used in this Amendment are used as
defined in the Loan Agreement, as amended hereby, unless otherwise stated.
C. Borrower, Agent and Lenders desire that: (i) the Commitments
be increased from $30,000,000 to $40,000,000; and (ii)other modifications be
made to the Loan Agreement as set forth in this Amendment.
D. Borrower, Agent and Lenders desire to amend the Loan Agreement
as hereinafter set forth.
NOW, THEREFORE, in consideration of the premises herein contained and
other good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged, the parties, intending to be legally bound, agree as
follows:
AGREEMENT
---------
EXHIBIT 10.25.4
ARTICLE I
Amendments to Loan Agreement
----------------------------
1.01 Amendment to Section 1.1 of the Loan Agreement. Effective as of
----------------------------------------------
the date hereof, Section 1.1 of the Loan Agreement is hereby amended by (a)
substituting the definitions below of "Business Day," "Default Margin," and
"Maximum Revolving Amount" in lieu of the definitions thereof set forth in
Section 1.1 of the Loan Agreement, (b) adding the definitions below of "Average
Outstandings," "Base LIBOR Rate," "Capital Expenditures," "Capitalized Lease
1
Obligation," "Funding Losses," "Interest Period," "LIBOR Deadline," "LIBOR
Notice," "LIBOR Option," "LIBOR Rate," "LIBOR Rate Loan," "LIBOR Rate Margin,"
"Reference Rate Loan," "Reference Rate Margin," and "Reserve Percentage" to
Section 1.1 of the Loan Agreement and (c) deleting the definition of "Margin"
set forth in Section 1.1 of the Loan Agreement:
" `Average Outstandings' means, as of the last day of each
--------------------
month, the sum of (i) the amount of the average Daily Balance of
Advances (including Agent Advances and Foothill Loans) that were
outstanding (including any amounts that the Lender Group may have paid
for the account of Borrower pursuant to any of the Loan Documents and
that have not been reimbursed by Borrower) during such month (the
"Averaging Period"), plus (ii) the average Daily Balance of the Letter
of Credit/Hedging Arrangement Usage during such month; provided,
however, that with respect to any determinations of the Average
Outstandings during the period beginning on the Closing Date and ending
on the last day of the month in which the Closing Date occurs, the
Averaging Period used for such purpose shall instead be the period
beginning with the Closing Date and ending on the last day of such
month.
`Base LIBOR Rate' means the rate per annum, determined by
---------------
Agent in accordance with its customary procedures, and utilizing such
electronic or other quotation sources as it considers appropriate
(rounded upwards, if necessary, to the next 1/16%), on the basis of the
rates at which Dollar deposits are offered to major banks in the London
interbank market on or about 11:00 a.m. (California time) 2 Business
Days prior to the commencement of the applicable Interest Period, for a
term and in amounts comparable to the Interest Period and amount of the
LIBOR Rate Loan requested by Borrower in accordance with this
Agreement, which determination shall be conclusive in the absence of
manifest error.
`Business Day' means any day that is not a Saturday, Sunday,
------------
or other day on which national banks are authorized or required to
close, except that, if a determination of a Business Day shall relate
to LIBOR Rate Loan, the term `Business Day' also shall exclude any day
on which banks are closed for dealings in Dollar deposits in the London
interbank market.
`Capital Expenditures' means expenditures made or liabilities
--------------------
incurred for the acquisition of any fixed assets or improvements,
replacements, substitutions or additions thereto, which have a useful
life of more than one year, including the total principal portion of
Capitalized Lease Obligations.
`Capitalized Lease Obligation' means any Indebtedness
----------------------------
represented by obligations under a lease that is required to be
capitalized for financial reporting purposes in accordance with GAAP.
`Default Margin' means, as of any date of determination, four
--------------
(4) percentage points above the then applicable Reference Rate Margin,
as the case may be and as the applicable Reference Rate Margin may
change from time to time.
`Funding Losses' has the meaning set forth in Section 2.14(b)(ii).
--------------
`Interest Period' means, with respect to each LIBOR Rate Loan,
---------------
a period commencing on the date of the making of such LIBOR Rate Loan
2
and ending 1, 2, or 3 months thereafter; provided, however, that (a) if
any Interest Period would end on a day that is not a Business Day, such
Interest Period shall be extended (subject to clauses (c)-(e) below) to
the next succeeding Business Day, (b) interest shall accrue at the
applicable rate based upon the LIBOR Rate from and including the first
day of each Interest Period to, but excluding, the day on which any
Interest Period expires, (c) any Interest Period that would end on a
day that is not a Business Day shall be extended to the next succeeding
Business Day unless such Business Day falls in another calendar month,
in which case such Interest Period shall end on the next preceding
Business Day, (d) with respect to an Interest Period that begins on the
last Business Day of a calendar month (or on a day for which there is
no numerically corresponding day in the calendar month at the end of
such Interest Period), the Interest Period shall end on the last
Business Day of the calendar month that is 1, 2, or 3 months after the
date on which the Interest Period began, as applicable, and (e)
Borrower may not elect an Interest Period which will end after the
Maturity Date.
`LIBOR Deadline' has the meaning set forth in Section 2.14(b)(i).
-------------- ----------
`LIBOR Notice' means a written notice in the form of Exhibit L-1.
------------ -----------
`LIBOR Option' has the meaning set forth in Section 2.14(a).
------------ --------------
`LIBOR Rate' means, for each Interest Period for each LIBOR
----------
Rate Loan, the rate per annum determined by Agent (rounded upwards, if
necessary, to the next 1/16%) by dividing (a) the Base LIBOR Rate for
such Interest Period, by (b) 100% minus the Reserve Percentage. The
LIBOR Rate shall be adjusted on and as of the effective day of any
change in the Reserve Percentage.
`LIBOR Rate Loan' means each portion of an Advance owed by
---------------
Borrower that bears interest at a rate determined by reference to the
LIBOR Rate.
`LIBOR Rate Margin' means, as of any date of determination
-----------------
during any month with respect to any and all LIBOR Rate Loans, which
are outstanding during such month, the rate of interest per annum
specified below as the `Applicable LIBOR Rate Margin' which corresponds
to the Average Outstandings set forth below as of such date:
------------------------------------ -----------------------------
Average Outstandings Applicable LIBOR Rate Margin
------------------------------------ -----------------------------
<$20,000,000 2.25%
------------------------------------ -----------------------------
------------------------------------ -----------------------------
= or >$20,000,000 2.50%
and <$30,000,000
------------------------------------ -----------------------------
------------------------------------ -----------------------------
= or >$30,000,000 2.75%
------------------------------------ -----------------------------
`Maximum Revolving Amount' means $40,000,000.
------------------------
`Reference Rate Loan' means each portion of an Advance or
-------------------
other Obligations owed by Borrower that bears interest at a rate
determined by reference to the Reference Rate.
3
`Reference Rate Margin' means, as of any date of determination
---------------------
during any month with respect to any and all Reference Rate Loans,
which are outstanding during such month, the rate of interest per annum
specified below as the `Applicable Reference Rate Margin' which
corresponds to the Average Outstandings set forth below as of such
date:
-------------------------------- -----------------------------
Average Outstandings Applicable Reference
Rate Margin
-------------------------------- -----------------------------
-------------------------------- -----------------------------
<$20,000,000 0.25%
-------------------------------- -----------------------------
-------------------------------- -----------------------------
= or >$20,000,000 0.50%
and <$30,000,000
-------------------------------- -----------------------------
-------------------------------- -----------------------------
= or >$30,000,000 0.75%
-------------------------------- -----------------------------
`Reserve Percentage' means, on any day, for any Lender, the
------------------
maximum percentage prescribed by the Board of Governors of the Federal
Reserve System (or any successor Governmental Authority) for
determining the reserve requirements (including any basic,
supplemental, marginal, or emergency reserves) that are in effect on
such date with respect to eurocurrency funding (currently referred to
as "eurocurrency liabilities") of that Lender, but so long as such
Lender is not required or directed under applicable regulations to
maintain such reserves, the Reserve Percentage shall be zero."
1.02 Amendment to Section 2.1(f)(i) of the Loan Agreement. Effective as
----------------------------------------------------
of the date hereof, the second sentence contained in Section 2.1(f)(i) of the
Loan Agreement is hereby amended and restated to read in its entirety as
follows:
"Each Foothill Loan is an Advance hereunder and shall be
subject to all the terms and conditions applicable to other Advances,
except that all payments on any Foothill Loan shall be payable to
Foothill as a Lender solely for its own account (and for the account of
the holder of any participation interest with respect to such Foothill
Loan)."
1.03 Amendment to Section 2.1(g)(i) of the Loan Agreement. Effective as
----------------------------------------------------
of the date hereof, Section 2.1(g)(i) of the Loan Agreement is hereby amended by
adding a second sentence thereto immediately following the first sentence
contained in Section 2.1(g)(i), which second sentence shall read in its entirety
as follows:
"Each Agent Advance is an Advance hereunder and shall be subject to all
the terms and conditions applicable to other Advances, except that no
such Agent Advance shall be eligible for the LIBOR Option and all
payments thereon shall be payable to Agent solely for its own account
(and for the account of the holder of any participation interest with
respect to such Agent Advance)."
1.04 Amendment to Section 2.1(k) of the Loan Agreement. Effective as of
-------------------------------------------------
the date hereof, the third sentence contained in Section 2.1(k) of the Loan
Agreement is hereby amended and restated to read in its entirety as follows:
"The Advances and Foothill Loans, as applicable, that are made pursuant
to this Section 2.1(k) shall be subject to the same terms and
conditions as any other Advance or Foothill Loan, as applicable, except
that they shall not be eligible for the LIBOR Option and the rate of
4
interest applicable thereto shall be the rate applicable to Advances
that are Reference Rate Loans under Section 2.6(c) hereof without
regard to the presence or absence of a Default or Event of Default;
provided, that the Required Lenders may, at any time during the
continuance of an Event of Default or if Borrower fails to satisfy any
other material lending condition, revoke Agent's authorization
contained in this Section 2.1(k) to make Overadvances (except for and
excluding amounts charged to the Loan Account for interest, fees, or
Lender Group Expenses), any such revocation to be in writing and to
become effective upon Agent's receipt thereof."
1.05 Amendment to Section 2.6(a) of the Loan Agreement. Effective as of
-------------------------------------------------
the date hereof, Section 2.6(a) of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:
"(a) Interest Rate. Except as provided in clause (c) and
clause (d) below, all Obligations (except for amounts undrawn under
Letters of Credit and Hedging Arrangement Usage) shall bear interest on
the Daily Balance as follows: (i) if the relevant Obligation is a LIBOR
Rate Loan, at a per annum rate equal to the LIBOR Rate plus the
applicable LIBOR Rate Margin as the applicable LIBOR Rate Margin may
change from time to time, and (ii) otherwise, at a per annum rate equal
to the Reference Rate plus the applicable Reference Rate Margin as the
applicable Reference Rate Margin may change from time to time."
1.06 Amendment to Section 2.6(d) of the Loan Agreement. Effective as of
-------------------------------------------------
the date hereof, Section 2.6(d) of the Loan Agreement is hereby amended by
deleting "8% per annum" therefrom and substituting in its place "6.75% per
annum".
1.07 Amendment to Section 2.11(c) of the Loan Agreement. Effective as
--------------------------------------------------
of the date hereof, Section 2.11(c) of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:
"(c) Annual Facility Fee. For the sole and separate account of
Agent, on each anniversary of the Closing Date occurring after
September 30, 2001, an annual loan facility fee in an amount equal to
$200,000, which amount shall be fully earned and nonrefundable in
advance on such date."
1.08 Amendment to Section 2.11(e) of the Loan Agreement. Effective as
--------------------------------------------------
of the date hereof, Section 2.11(e) of the Loan Agreement is hereby amended by
deleting "$10,000" therefrom and substituting in its place "$3,000".
1.09 Amendment to Section 2.14 of the Loan Agreement. Effective as of
-----------------------------------------------
the date hereof, Section 2.14 of the Loan Agreement is hereby added to the Loan
Agreement immediately following Section 2.13, which Section 2.14 reads in its
entirety as follows:
"2.14 LIBOR Option.
---------------------
(a) Interest and Interest Payment Dates. In lieu of having
-----------------------------------
interest charged at the rate based upon the Reference Rate, Borrower
shall have the option (the "LIBOR Option") to have interest on all or a
portion of the Advances be charged at the LIBOR Rate. Interest on LIBOR
Rate Loans shall be payable on the earliest of (i) the last day of the
Interest Period applicable thereto, (ii) the occurrence of an Event of
Default in consequence of which the Required Lenders or Agent on behalf
5
thereof elect to accelerate the maturity of the Obligations, (iii)
termination of this Agreement pursuant to the terms hereof, or (iv) the
first day of each month that such LIBOR Rate Loan is outstanding. On
the last day of each applicable Interest Period, unless Borrower
properly has exercised the LIBOR Option with respect thereto, the
interest rate applicable to such LIBOR Rate Loan automatically shall
convert to the rate of interest then applicable to Reference Rate Loans
of the same type hereunder. At any time that an Event of Default has
occurred and is continuing, Borrower no longer shall have the option to
request that Advances bear interest at the LIBOR Rate and Agent shall
have the right to convert the interest rate on all outstanding LIBOR
Rate Loans to the rate then applicable to Reference Rate Loans
hereunder.
(b) LIBOR Election.
--------------
(i) Borrower may, at any time and from time to time,
so long as no Event of Default has occurred and is continuing, elect to
exercise the LIBOR Option by notifying Agent prior to 11:00 a.m.
(California time) at least 3 Business Days prior to the commencement of
the proposed Interest Period (the "LIBOR Deadline"). Notice of
Borrower's election of the LIBOR Option for a permitted portion of the
Advances and an Interest Period pursuant to this Section shall be made
by delivery to Agent of a LIBOR Notice received by Agent before the
LIBOR Deadline, or by telephonic notice received by Agent before the
LIBOR Deadline (to be confirmed by delivery to Agent of a LIBOR Notice
received by Agent prior to 5:00 p.m. (California time) on the same
day). Promptly upon its receipt of each such LIBOR Notice, Agent shall
provide a copy thereof to each of the Lenders having a Commitment.
(ii) Each LIBOR Notice shall be irrevocable and
binding on Borrower. In connection with each LIBOR Rate Loan, Borrower
shall indemnify, defend, and hold Agent and the Lenders harmless
against any loss, cost, or expense incurred by Agent or any Lender as a
result of (a) the payment of any principal of any LIBOR Rate Loan other
than on the last day of an Interest Period applicable thereto
(including as a result of an Event of Default), (b) the conversion of
any LIBOR Rate Loan other than on the last day of the Interest Period
applicable thereto, or (c) the failure to borrow, convert, continue or
prepay any LIBOR Rate Loan on the date specified in any LIBOR Notice
delivered pursuant hereto (such losses, costs, and expenses,
collectively, "Funding Losses"). Funding Losses shall, with respect to
Agent or any Lender, be deemed to equal the amount determined by Agent
or such Lender to be the excess, if any, of (i) the amount of interest
that would have accrued on the principal amount of such LIBOR Rate Loan
had such event not occurred, at the LIBOR Rate that would have been
applicable thereto, for the period from the date of such event to the
last day of the then current Interest Period therefor (or, in the case
of a failure to borrow, convert or continue, for the period that would
have been the Interest Period therefor), minus (ii) the amount of
interest that would accrue on such principal amount for such period at
the interest rate which Agent or such Lender would be offered were it
to be offered, at the commencement of such period, Dollar deposits of a
comparable amount and period in the London interbank market. A
certificate of Agent or a Lender delivered to Borrower setting forth
any amount or amounts that Agent or such Lender is entitled to receive
pursuant to this Section shall be conclusive absent manifest error.
6
(iii) Borrower shall have not more than 5 LIBOR Rate
Loans in effect at any given time. Borrower only may exercise the LIBOR
Option for LIBOR Rate Loans of at least $1,000,000 and integral
multiples of $500,000 in excess thereof.
(c) Prepayments. Borrowers may prepay LIBOR Rate Loans at any
-----------
time; provided, however, that in the event that LIBOR Rate Loans are
prepaid on any date that is not the last day of the Interest Period
applicable thereto, including as a result of any automatic prepayment
through the required application by Agent of proceeds of Collections in
accordance with Section 2.4(b) or for any other reason, including early
termination of the term of this Agreement or acceleration of the
Obligations pursuant to the terms hereof, Borrower shall indemnify,
defend, and hold Agent and the Lenders and their Participants harmless
against any and all Funding Losses in accordance with clause (b) above.
(d) Special Provisions Applicable to LIBOR Rate.
-------------------------------------------
(i) The LIBOR Rate may be adjusted by Agent with
respect to any Lender on a prospective basis to take into account any
additional or increased costs to such Lender of maintaining or
obtaining any eurodollar deposits or increased costs due to changes in
applicable law occurring subsequent to the commencement of the then
applicable Interest Period, including changes in tax laws (except
changes of general applicability in corporate income tax laws) and
changes in the reserve requirements imposed by the Board of Governors
of the Federal Reserve System (or any successor), excluding the Reserve
Percentage, which additional or increased costs would increase the cost
of funding loans bearing interest at the LIBOR Rate. In any such event,
the affected Lender shall give Borrower and Agent notice of such a
determination and adjustment and Agent promptly shall transmit the
notice to each other Lender and, upon its receipt of the notice from
the affected Lender, Borrower may, by notice to such affected Lender
(y) require such Lender to furnish to Borrower a statement setting
forth the basis for adjusting such LIBOR Rate and the method for
determining the amount of such adjustment, or (z) repay the LIBOR Rate
Loans with respect to which such adjustment is made (together with any
amounts due under clause (b)(ii) above).
(ii) In the event that any change in market
conditions or any law, regulation, treaty, or directive, or any change
therein or in the interpretation of application thereof, shall at any
time after the date hereof, in the reasonable opinion of any Lender,
make it unlawful or impractical for such Lender to fund or maintain
LIBOR Rate Loans or to continue such funding or maintaining, or to
determine or charge interest rates at the LIBOR Rate, such Lender shall
give notice of such changed circumstances to Agent and Borrower and
Agent promptly shall transmit the notice to each other Lender and (y)
in the case of any LIBOR Rate Loans of such Lender that are
outstanding, the date specified in such Lender's notice shall be deemed
to be the last day of the Interest Period of such LIBOR Rate Loans, and
interest upon the LIBOR Rate Loans of such Lender thereafter shall
accrue interest at the rate then applicable to Reference Rate Loans,
and (z) Borrowers shall not be entitled to elect the LIBOR Option until
such Lender determines that it would no longer be unlawful or
impractical to do so.
(e) No Requirement of Matched Funding. Anything to the
---------------------------------
contrary contained herein notwithstanding, neither Agent, nor any
Lender, nor any of their Participants, is required actually to acquire
eurodollar deposits to fund or otherwise match fund any Obligation as
7
to which interest accrues at the LIBOR Rate. The provisions of this
Section shall apply as if each Lender or its Participants had match
funded any Obligation as to which interest is accruing at the LIBOR
Rate by acquiring eurodollar deposits for each Interest Period in the
amount of the LIBOR Rate Loans."
1.10 Amendment to Section 3.4 of the Loan Agreement. Effective as of
----------------------------------------------
the date hereof, Section 3.4 of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:
"3.4 Term. This Agreement shall become effective upon the
execution and delivery hereof by Borrower and the Lender Group and
shall continue in full force and effect for a term ending on September
30, 2003 (the "Maturity Date"). The foregoing notwithstanding, the
Lender Group, upon the election of the Required Lenders, shall have the
right to terminate its obligations under this Agreement immediately and
without notice upon the occurrence and during the continuation of an
Event of Default."
1.11 Amendment to Section 3.6 of the Loan Agreement. Effective as of
----------------------------------------------
the date hereof, Section 3.6 of the Loan Agreement is hereby amended and
restated in its entirety as follows:
"3.6 Early Termination by Borrower. Borrower has the option,
at any time upon 90 days prior written notice to Agent, to terminate
this Agreement by paying to Agent, for the ratable benefit of the
Lender Group, in cash, the Obligations (including an amount equal to
110% of the undrawn amount of the Letters of Credit and the Hedging
Arrangement Usage), in full, together with a premium (the "Early
Termination Premium") equal to the greater of (a) the total interest
and Letter of Credit fees and Hedging Agreement Undertaking fees for
the immediately preceding 6 months, and (b) if the termination occurs
(i) on or before the third anniversary of the Closing Date, an amount
equal to one percent (1%) of the Maximum Revolving Amount, and (ii) if
the termination occurs at any time after the third anniversary of the
Closing Date (other than the Maturity Date), an amount equal to one
half of one percent (0.5%) of the Maximum Revolving Amount."
1.12 Amendment to Section 6.19 of the Loan Agreement. Effective as of
-----------------------------------------------
the date hereof, Section 6.19 of the Loan Agreement is hereby amended by
deleting "September 30, 2001" therefrom and substituting in its place "the
Maturity Date".
1.13 Amendment to Section 7.20(b) of the Loan Agreement. Effective as
--------------------------------------------------
of the date hereof, Section 7.20(b) of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:
"(b) Consolidated Interest Coverage Ratio. As of the last day of each
month, a ratio of (i) Borrower's consolidated EBITDA for the 12
consecutive fiscal month period then ended, to (ii) Borrower's
consolidated Interest Expense for the 12 consecutive fiscal month
period then ended, of at least 2.0 to 1.0."
1.14 Amendment to Section 7.21 of the Loan Agreement. Effective as of
-----------------------------------------------
the date hereof, Section 7.21 of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:
"7.21 Capital Expenditures. Make Capital Expenditures in
--------------------
excess of (a) $40,000,000 during Borrower's fiscal year ending December
31, 2000, (b) $45,000,000 during Borrower's fiscal year ending December
31, 2001, or (iii) $35,000,000 during any fiscal year of Borrower
ending on or after January 1, 2002."
8
1.15 Amendment of Schedule C-1 of the Loan Agreement. Effective as of
-----------------------------------------------
the date hereof, Schedule C-1 the Loan Agreement is hereby amended and restated
to read in its entirety as set forth on Annex I to this Amendment.
1.16 Addition of Schedule L-1 to the Loan Agreement. Effective as of
----------------------------------------------
the date hereof, the Loan Agreement is hereby amended to add Schedule L-1 to the
Loan Agreement, which Schedule L-1 shall read in its entirety as set forth on
Annex II to this Amendment.
ARTICLE II
Conditions Precedent
--------------------
2.01 Conditions to Effectiveness. The effectiveness of this Amendment
---------------------------
is subject to the satisfaction of the following conditions precedent in a manner
satisfactory to Agent, unless specifically waived in writing by Agent:
(a) Agent shall have received this Amendment, duly executed by
Borrower and each Lender.
(b) Agent shall have received the Amendment Fee described in
Section 4.11 of this Amendment.
(c) The representations and warranties contained herein and in the Loan
Agreement and the other Loan Documents, as each is amended hereby, shall be true
and correct as of the date hereof, as if made on the date hereof.
(d) No Default or Event of Default shall have occurred and be
continuing, unless such Default or Event of Default has been otherwise
specifically waived in writing by Agent and to the extent required by the Loan
Agreement, the Lenders.
(e) All corporate proceedings taken in connection with the transactions
contemplated by this Amendment and all documents, instruments and other legal
matters incident thereto shall be satisfactory to Agent and its legal counsel.
ARTICLE III
Ratifications, Representations and Warranties
---------------------------------------------
3.01 Ratifications. The terms and provisions set forth in this
-------------
Amendment shall modify and supersede all inconsistent terms and provisions set
forth in the Loan Agreement and the other Loan Documents, and, except as
expressly modified and superseded by this Amendment, the terms and provisions of
the Loan Agreement and the other Loan Documents are ratified and confirmed and
shall continue in full force and effect. Borrower, Agent and Lenders agree that
the Loan Agreement and the other Loan Documents, as amended hereby, shall
continue to be legal, valid, binding and enforceable in accordance with their
respective terms.
3.02 Representations and Warranties. Borrower hereby represents and
------------------------------
warrants to Agent and each Lender that (a) the execution, delivery and
performance of this Amendment and any and all other Loan Documents executed
and/or delivered in connection herewith have been authorized by all requisite
corporate action on the part of Borrower and will not violate the Articles of
Incorporation or Bylaws of Borrower; (b) attached hereto as Annex III is a true,
correct and complete copy of presently effective resolutions of Borrower's Board
of Directors authorizing the execution, delivery and performance of this
9
Amendment and any and all other Loan Documents executed and/or delivered in
connection herewith, certified by the Secretary of Borrower; (c) the
representations and warranties contained in the Loan Agreement, as amended
hereby, and any other Loan Document are true and correct on and as of the date
hereof; (d) no Default or Event of Default under the Loan Agreement, as amended
hereby, has occurred and is continuing, unless such Default or Event of Default
has been specifically waived in writing by Agent and to the extent required by
the Loan Agreement, the Lenders; (e) Borrower is in full compliance with all
covenants and agreements contained in the Loan Agreement and the other Loan
Documents, as amended hereby; and (f) Borrower has not amended its Articles of
Incorporation or its Bylaws since the Closing Date.
ARTICLE IV
Miscellaneous Provisions
------------------------
4.01 Survival of Representations and Warranties. All representations
------------------------------------------
and warranties made in the Loan Agreement or any other Loan Document, including,
without limitation, any document furnished in connection with this Amendment,
shall survive the execution and delivery of this Amendment and the other Loan
Documents, and no investigation by Agent or any closing shall affect the
representations and warranties or the right of Agent and the Lenders to rely
upon them.
4.02 Amendment to References in all Loan Documents. Effective as of the
---------------------------------------------
date hereof, any reference in the Loan Documents to the capitalized terms "Loan
Agreement" or "Credit Agreement" or to the Amended and Restated Loan and
Security Agreement, dated as of September 30, 1999, by and among the Borrower,
PPC (prior to its merger with and into Borrower), the Lenders and the Agent,
shall be deemed a reference to the Loan Agreement (as defined in this
Amendment), as amended hereby.
4.03 Expenses of Agent and Lenders. As provided in the Loan Agreement,
-----------------------------
Borrower agrees to pay on demand all costs and expenses incurred by Agent and
Lenders in connection with the preparation, negotiation, and execution of this
Amendment and the other Loan Documents executed pursuant hereto and any and all
amendments, modifications, and supplements thereto, including, without
limitation, the costs and fees of Agent's and Lenders' legal counsel, and all
costs and expenses incurred by Agent and Lenders in connection with the
enforcement or preservation of any rights under the Loan Agreement, as amended
hereby, or any other Loan Documents, including, without, limitation, the costs
and fees of Agent's and Lenders' legal counsel.
4.04 Severability. Any provision of this Amendment held by a court of
------------
competent jurisdiction to be invalid or unenforceable shall not impair or
invalidate the remainder of this Amendment and the effect thereof shall be
confined to the provision so held to be invalid or unenforceable.
4.05 Successors and Assigns. This Amendment is binding upon and shall
----------------------
inure to the benefit of Agent, each Lender and Borrower and their respective
successors and assigns, except that Borrower may not assign or transfer any of
its rights or obligations hereunder without the prior written consent of Agent.
4.06 Counterparts. This Amendment may be executed in one or more
------------
counterparts, each of which when so executed shall be deemed to be an original,
but all of which when taken together shall constitute one and the same
instrument.
10
4.07 Effect of Waiver. No consent or waiver, express or implied, by
----------------
Agent or any Lender to or for any breach of or deviation from any covenant or
condition by Borrower shall be deemed a consent to or waiver of any other breach
of the same or any other covenant, condition or duty.
4.08 Headings. The headings, captions, and arrangements used
--------
in this Amendment are for convenience only and shall not affect the
interpretation of this Amendment.
4.09 Applicable Law. THIS AMENDMENT AND ALL OTHER LOAN DOCUMENTS
--------------
EXECUTED PURSUANT HERETO SHALL BE DEEMED TO HAVE BEEN MADE AND TO BE PERFORMABLE
IN AND SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE
STATE OF NEW YORK.
4.10 Final Agreement. THE LOAN AGREEMENT AND THE OTHER LOAN DOCUMENTS,
---------------
EACH AS AMENDED HEREBY, REPRESENT THE ENTIRE EXPRESSION OF THE PARTIES WITH
RESPECT TO THE SUBJECT MATTER HEREOF ON THE DATE THIS AMENDMENT IS EXECUTED. THE
LOAN AGREEMENT AND THE OTHER LOAN DOCUMENTS, AS AMENDED HEREBY, MAY NOT BE
CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS
OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. NO
MODIFICATION, RESCISSION, WAIVER, RELEASE OR AMENDMENT OF ANY PROVISION OF THIS
AMENDMENT SHALL BE MADE, EXCEPT BY A WRITTEN AGREEMENT SIGNED BY EACH BORROWER
AND AGENT.
4.11 Amendment Fee. In consideration of the execution of this
-------------
Amendment, Borrower agrees to pay to Agent on the date of this Amendment, for
the sole and separate account of Agent, an amendment fee of $50,000, which fee
shall be fully earned and non-refundable as of the date of this Amendment.
[remainder of page intentionally left blank; signature page follows]
11
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed as of the date first written above.
BORROWER:
--------
PANACO, INC.
By:
--------------------------------------
Name:
--------------------------------------
Title:
--------------------------------------
AGENT:
-----
FOOTHILL CAPITAL CORPORATION,
as Agent for the Lenders
By:
--------------------------------------
Jeffrey Stanek
Vice President
LENDERS:
-------
FOOTHILL CAPITAL CORPORATION, as a Lender
By:
--------------------------------------
Jeffrey Stanek
Vice President
12
ANNEX I
TO
SIXTH AMENDMENT TO AMENDED AND RESTATED
LOAN AND SECURITY AGREEMENT
"EXHIBIT C-1
COMMITMENTS
-----------
Name of Lender Commitment
-------------- ----------
Foothill Capital Corporation $40,000,000"
13
ANNEX II
TO
SIXTH AMENDMENT TO AMENDED AND RESTATED
LOAN AND SECURITY AGREEMENT
"EXHIBIT L-1
FORM OF LIBOR NOTICE
--------------------
Foothill Capital Corporation, as Agent for the Lenders
2450 Colorado Avenue
Suite 3000 West
Santa Monica, California 90404
Attention: Jeff Stanek
Ladies and Gentlemen:
Reference hereby is made to that certain Amended and Restated Loan and
Security Agreement, dated as of September 30, 1999 (the "Loan Agreement"), by
and among PANACO, INC., a Delaware corporation ("Borrower") which is the sole
surviving corporation of the merger by Panaco Production Company, a Texas
corporation ("PPC") and Goldking Acquisition Corporation, a Delaware corporation
("GAC"), with and into Borrower and is the successor-by-merger to PPC and GAC
thereunder; the financial institutions signatory thereto (together with their
successors and assigns, individually, "Lender" and, collectively, "Lenders"),
and FOOTHILL CAPITAL CORPORATION, a California corporation, as agent for the
Lenders (in such capacity, together with its successors, if any, "Agent") (as
amended, restated or otherwise modified from time to time, the "Loan
Agreement"). Any and all initially capitalized terms which are used but not
specifically defined herein shall have the meanings ascribed to them in the Loan
Agreement.
This LIBOR Notice represents Borrower's request to elect the LIBOR
Option with respect to outstanding Advances in the amount of $__________ (the
"LIBOR Rate Loan")[, and is a written confirmation of the telephonic notice of
such election given to Agent].
Such LIBOR Rate Loan will have an Interest Period of [1, 2 or 3]
month(s) commencing on ________________.
This LIBOR Notice further confirms Borrower's acceptance, for purposes
of determining the rate of interest based on the LIBOR Rate under the Loan
Agreement, of the LIBOR Rate as determined pursuant to the Loan Agreement.
Borrower represents and warrants that (i) as of the date hereof, each
representation or warranty contained in or pursuant to any Loan Document, any
agreement, instrument, certificate, document or other writing furnished at any
time under or in connection with any Loan Document, and as of the effective date
of any advance, continuation or conversion requested above is true and correct
in all material respects (except to the extent any representation or warranty
expressly related to an earlier date), (ii) each of the covenants and agreements
contained in any Loan Document have been performed (to the extent required to be
performed on or before the date hereof or each such effective date), and (iii)
no Default or Event of Default has occurred and is continuing on the date
hereof, nor will any thereof occur after giving effect to the request above.
14
Dated: ________________ PANACO, INC.
By:
----------------------------------------
Name:
----------------------------------------
Title:
----------------------------------------
Acknowledged by:
FOOTHILL CAPITAL CORPORATION,
as Agent for the Lenders
By:
---------------------------------------
Name:
---------------------------------------
Title:
---------------------------------------
15
ANNEX III
TO SIXTH AMENDMENT TO AMENDED AND RESTATED
LOAN AND SECURITY AGREEMENT
CERTIFIED RESOLUTIONS OF PANACO, INC.'S BOARD OF DIRECTORS
----------------------------------------------------------
RESOLVED: That any officer of Panaco, Inc., a Delaware corporation (the
"Corporation"), acting alone, by his signature be, and the same hereby is,
authorized and directed, in the name of and on behalf of the Corporation (a) to
amend that certain Amended and Restated Loan and Security Agreement by and among
the Corporation, Panaco Production Company, Lenders signatory thereto and
Foothill Capital Corporation, a California corporation, as agent for Lenders
("Agent"), as amended by that certain First Amendment to Amended and Restated
Loan and Security Agreement, dated November 30, 1999, by and among the same
parties, as amended by that certain Second Amendment to Amended and Restated
Loan and Security Agreement, dated September 29, 2000, by and among the same
parties, as amended by that certain Third Amendment to Amended and Restated Loan
and Security Agreement, dated December 21, 2000, by and among the same parties,
as amended by that certain Fourth Amendment to Amended and Restated Loan and
Security Agreement, dated September 30, 2001, by and among the same parties, and
as amended by that certain Fifth Amendment to Amended and Restated Loan and
Security Agreement, dated October 29, 2001, by and among the same parties, (b)
to execute and deliver to Agent with such changes in the terms and provisions
thereof as the officer executing same shall, in his sole discretion, deem
advisable, (i) a certain proposed Sixth Amendment to Amended and Restated Loan
and Security Agreement to be executed by Corporation, Lenders and Agent, a draft
of which has been reviewed and discussed by the Board of Directors of the
Corporation, and (ii) such other Loan Documents, instruments, statements and
writings as the officer or officers executing the same may deem desirable or
necessary in connection therewith, and (c) to perform such other acts as the
officer or officers performing such acts on behalf of the Corporation may deem
desirable or necessary in connection therewith; and be it
FURTHER RESOLVED: That said agreements will benefit the
Corporation, both directly and indirectly, and are in the best interests of
the Corporation; and be it
FURTHER RESOLVED: That said agreements and other statements in
writing executed in the name and on behalf of the Corporation by any
officer of the Corporation shall be presumed conclusively to be the
instruments, the execution of which is authorized by these resolutions; and
be it
FURTHER RESOLVED: That the officers of the Corporation be, and the same
hereby are, authorized and directed to execute, in the name of and on behalf of
the Corporation, security agreements, financing statements, mortgages, deeds of
trust, assignments, collateral reports, loan statements, confirmations of
delivery, lien statements, pledge certificates, release certificates, removal
reports, guaranties, cross-collateralization agreements and such other writings
and to take such other actions as are necessary in their dealings with Agent,
and any such papers executed and any such actions taken by any of them prior to
this time are approved, ratified and confirmed; and be it
FURTHER RESOLVED: That the Secretary or any Assistant Secretary of the
Corporation, by the signature of any one or more of them, be, and the same
hereby are, authorized and directed to attest the execution by the Corporation
of the papers signed pursuant to these resolutions, to affix the seal of the
Corporation thereto, if required by Agent, and to certify to Agent the adoption
of these resolutions.
CERTIFICATION
-------------
The undersigned hereby certifies that the within and foregoing
resolutions are in effect as of the date hereof, without modification, and that
the person signing the within and foregoing Amendment on behalf of the
Corporation is the duly elected officer stated below his name, that he is
authorized to sign such Amendment, and that his signature thereon is genuine.
DATED: November ___, 2001
---------------------------------------
Assistant] Secretary of the Corporation
16
SEVENTH AMENDMENT TO
AMENDED AND RESTATED LOAN AND SECURITY AGREEMENT
------------------------------------------------
THIS SEVENTH AMENDMENT TO AMENDED AND RESTATED LOAN AND SECURITY
AGREEMENT (this "Amendment") is made and entered into as of March ____, 2002, by
---------
and among: PANACO, INC., a Delaware corporation ("Borrower") which is the sole
--------
surviving corporation of the merger by Panaco Production Company, a Texas
corporation ("PPC") and Goldking Acquisition Corporation, a Delaware corporation
---
("GAC"), with and into Borrower and is the successor-by-merger to PPC and GAC
---
thereunder; the financial institutions listed on the signature pages hereof
(such financial institutions, together with their respective successors and
assigns, are referred to hereinafter each individually as a "Lender" and
------
collectively as the "Lenders"); and FOOTHILL CAPITAL CORPORATION, a California
-------
corporation, as agent for the Lenders ("Agent").
-----
RECITALS
--------
A. Borrower, PPC (prior to its merger with and into Borrower),
Agent and Lenders have entered into that certain Amended and Restated Loan and
Security Agreement, dated as of September 30, 1999, as amended by that certain
First Amendment to Amended and Restated Loan and Security Agreement, dated
November 30, 1999, as amended by that certain Second Amendment to Amended and
Restated Loan and Security Agreement, dated September 29, 2000, as amended by
that certain Third Amendment to Amended and Restated Loan and Security
Agreement, dated December 21, 2000, as amended by that certain Fourth Amendment
to Amended and Restated Loan and Security Agreement, dated September 30, 2001,
as amended by that certain Fifth Amendment to Amended and Restated Loan and
Security Agreement, dated October 29, 2001, and as amended by that certain Sixth
Amendment to Amended and Restated Loan and Security Agreement, dated November 9,
2001 (as so amended, the "Loan Agreement").
--------------
B. Capitalized terms used in this Amendment are used as defined in
the Loan Agreement, as amended hereby, unless otherwise stated.
C. Borrower has requested that Lenders (i) waive certain Events of
Default that occurred from Borrower's failure to comply with (a) Section 6.19
------------
of the Loan Agreement from January 1, 2002 through the date hereof and (b)
Section 7.20(a) of the Loan Agreement on December 31, 2001 and January 31, 2002
- ---------------
(collectively, the "Specified Events of Default"), (ii) waive Borrower's
obligation to comply with Section 6.19 of the Loan Agreement from the date
-------------
hereof through March 31, 2002 (the "Hedging Obligation"), and (iii) make certain
------------------
modifications to the Loan Agreement.
D. Borrower, Agent and Lenders desire to amend the Loan Agreement
as hereinafter set forth.
NOW, THEREFORE, in consideration of the premises herein contained and
other good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged, the parties, intending to be legally bound, agree as
follows:
1
AGREEMENT
---------
ARTICLE I
Limited Waiver
--------------
1.01 Limited Waiver. Upon satisfaction of the conditions
---------------
precedent set forth in Article III hereof, the Lenders signatory hereto, hereby
waive the Hedging Obligation from the date hereof through March 31, 2002 and the
Specified Events of Default. Except as specifically provided herein, nothing
contained in this Amendment shall be construed as a waiver by any Lender of any
covenant or provision of the Loan Agreement, the other Loan Documents, this
Amendment or of any other contract or instrument between the Borrower and any
Lender, and the failure of the Lenders at any time or times hereafter to require
strict performance by the Borrower of any provision thereof shall not waive,
affect or diminish any right of the Lenders to hereafter demand strict
compliance therewith. Each Lender hereby reserves all rights granted under the
Loan Agreement, the other Loan Documents, this Amendment and any other contract
or instrument between the Borrower and any Lender.
ARTICLE II
Amendments to Loan Agreement
----------------------------
2.01 Amendment to Section 7.20(a) of the Loan Agreement.
---------------------------------------------------------
Effective as of the date hereof, Section 7.20(a) of the Loan Agreement is hereby
amended and restated to read in its entirety as follows:
"(a) Current Ratio. As of the last day of each month, a ratio of
Consolidated Current Assets divided by Consolidated Current
Liabilities of at least (i) 0.15:1.0 for each month ending between
January 1, 2002 and April 30, 2002, (ii) 0.20:1.0 for each month ending
between May 1, 2002 and January 1, 2003, and (iii) 0.25:1.0 for each
month ending after January 1, 2003;"
2.02 Amendment to Section 7.20(b) of the Loan Agreement.
---------------------------------------------------------
Effective as of the date hereof, Section 7.20(b) of the Loan Agreement is hereby
amended and restated to read in its entirety as follows:
"(b) Consolidated Interest Coverage Ratio. As of the last day
of each month, a ratio of (i) Borrower's consolidated EBITDA for the
12 consecutive fiscal month period then ended, to (ii)
Borrower's consolidated Interest Expense for the 12 consecutive fiscal
month period then ended, of at least the ratio set forth below for the
month ending corresponding to such ratio:
2
- ---------------------------------------- --------------------------------------
Month Ratio
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
January 2002 2.00:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
February 2002 1.90:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
March 2002 1.95:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
April 2002 1.70:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
May 2002 1.50:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
June 2002 1.20:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
July 2002 1.20:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
August 2002 1.00:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
September 2002 0.85:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
October 2002 0.70:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
November 2002 0.55:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
December 2002 1.00:1.0
- ---------------------------------------- --------------------------------------
- ---------------------------------------- --------------------------------------
January 2003 and 2.00:1.0
each month thereafter
- ---------------------------------------- --------------------------------------
ARTICLE III
Conditions Precedent
--------------------
3.01 Conditions to Effectiveness. The effectiveness of this
-----------------------------
Amendment is subject to the satisfaction of the following conditions precedent
in a manner satisfactory to Agent, unless specifically waived in writing by
Agent:
(a) Agent shall have received this Amendment, duly executed by
Borrower and each Lender.
(b) Agent shall have received the Amendment Fee described in
Section 5.11 of this Amendment.
- ------------
(c) The representations and warranties contained herein and in
the Loan Agreement and the other Loan Documents, as each is amended hereby,
shall be true and correct as of the date hereof, as if made on the date hereof.
(d) No Default or Event of Default shall have occurred and be
continuing, unless such Default or Event of Default has been otherwise
specifically waived in writing by Agent and to the extent required by the Loan
Agreement, the Lenders.
(e) All corporate proceedings taken in connection with the
transactions contemplated by this Amendment and all documents, instruments and
other legal matters incident thereto shall be satisfactory to Agent and its
legal counsel.
ARTICLE IV
Ratifications, Representations and Warranties
---------------------------------------------
4.01 Ratifications. The terms and provisions set forth in this
-------------
Amendment shall modify and supersede all inconsistent terms and provisions set
forth in the Loan Agreement and the other Loan Documents, and, except as
3
expressly modified and superseded by this Amendment, the terms and provisions of
the Loan Agreement and the other Loan Documents are ratified and confirmed and
shall continue in full force and effect. Borrower, Agent and Lenders agree that
the Loan Agreement and the other Loan Documents, as amended hereby, shall
continue to be legal, valid, binding and enforceable in accordance with their
respective terms.
4.02 Representations and Warranties. Borrower hereby represents
------------------------------
and warrants to Agent and each Lender that (a) the execution, delivery and
performance of this Amendment and any and all other Loan Documents executed
and/or delivered in connection herewith have been authorized by all requisite
corporate action on the part of Borrower and will not violate the Articles of
Incorporation or Bylaws of Borrower; (b) attached hereto as Annex I is a true,
-------
correct and complete copy of presently effective resolutions of Borrower's Board
of Directors authorizing the execution, delivery and performance of this
Amendment and any and all other Loan Documents executed and/or delivered in
connection herewith, certified by the Secretary of Borrower; (c) the
representations and warranties contained in the Loan Agreement, as amended
hereby, and any other Loan Document are true and correct on and as of the date
hereof; (d) no Default or Event of Default under the Loan Agreement, as amended
hereby, has occurred and is continuing, unless such Default or Event of Default
has been specifically waived in writing by Agent and to the extent required by
the Loan Agreement, the Lenders; (e) Borrower is in full compliance with all
covenants and agreements contained in the Loan Agreement and the other Loan
Documents, as amended hereby; and (f) Borrower has not amended its Articles of
Incorporation or its Bylaws since the Closing Date.
ARTICLE V
Miscellaneous Provisions
------------------------
5.01 Survival of Representations and Warranties. All
--------------------------------------------------
representations and warranties made in the Loan Agreement or any other Loan
Document, including, without limitation, any document furnished in connection
with this Amendment, shall survive the execution and delivery of this Amendment
and the other Loan Documents, and no investigation by Agent or any closing shall
affect the representations and warranties or the right of Agent and the Lenders
to rely upon them.
5.02 Amendment to References in all Loan Documents. Effective as of
-------------------------------------------------
the date hereof, any reference in the Loan Documents to the capitalized
terms "Loan Agreement" or "Credit Agreement" or to the Amended and Restated
Loan and Security Agreement, dated as of September 30, 1999, by and among the
Borrower, PPC (prior to its merger with and into Borrower), the Lenders
and the Agent, shall be deemed a reference to the Loan Agreement (as defined
in this Amendment), as amended hereby.
5.03 Expenses of Agent and Lenders. As provided in the Loan
-------------------------------
Agreement, Borrower agrees to pay on demand all costs and expenses incurred by
Agent and Lenders in connection with the preparation, negotiation, and execution
of this Amendment and the other Loan Documents executed pursuant hereto and any
and all amendments, modifications, and supplements thereto, including, without
limitation, the costs and fees of Agent's and Lenders' legal counsel, and all
costs and expenses incurred by Agent and Lenders in connection with the
enforcement or preservation of any rights under the Loan Agreement, as amended
hereby, or any other Loan Documents, including, without, limitation, the costs
and fees of Agent's and Lenders' legal counsel.
4
5.04 Severability. Any provision of this Amendment held by a
------------
court of competent jurisdiction to be invalid or unenforceable shall not impair
or invalidate the remainder of this Amendment and the effect thereof shall be
confined to the provision so held to be invalid or unenforceable.
5.05 Successors and Assigns. This Amendment is binding upon and
----------------------
shall inure to the benefit of Agent, each Lender and Borrower and their
respective successors and assigns, except that Borrower may not assign or
transfer any of its rights or obligations hereunder without the prior written
consent of Agent.
5.06 Counterparts. This Amendment may be executed in one or more
------------
counterparts, each of which when so executed shall be deemed to be an original,
but all of which when taken together shall constitute one and the same
instrument.
5.07 Effect of Waiver. No consent or waiver, express or implied,
----------------
by Agent or any Lender to or for any breach of or deviation from any covenant or
condition by Borrower shall be deemed a consent to or waiver of any other breach
of the same or any other covenant, condition or duty.
5.08 Headings. The headings, captions, and arrangements used in
--------
this Amendment are for convenience only and shall not affect the interpretation
of this Amendment.
5.09 Applicable Law. THIS AMENDMENT AND ALL OTHER LOAN DOCUMENTS
--------------
EXECUTED PURSUANT HERETO SHALL BE DEEMED TO HAVE BEEN MADE AND TO BE PERFORMABLE
IN AND SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE
STATE OF NEW YORK.
5.10 Final Agreement. THE LOAN AGREEMENT AND THE OTHER LOAN
----------------
DOCUMENTS, EACH AS AMENDED HEREBY, REPRESENT THE ENTIRE EXPRESSION OF THE
PARTIES WITH RESPECT TO THE SUBJECT MATTER HEREOF ON THE DATE THIS AMENDMENT IS
EXECUTED. THE LOAN AGREEMENT AND THE OTHER LOAN DOCUMENTS, AS AMENDED HEREBY,
MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL
AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE
PARTIES. NO MODIFICATION, RESCISSION, WAIVER, RELEASE OR AMENDMENT OF ANY
PROVISION OF THIS AMENDMENT SHALL BE MADE, EXCEPT BY A WRITTEN AGREEMENT SIGNED
BY EACH BORROWER AND AGENT.
5.11 Amendment Fee. In consideration of the execution of this
--------------
Amendment, Borrower agrees to pay to Agent on the date of this Amendment, for
the sole and separate account of Agent, an amendment fee of $75,000, which fee
shall be fully earned and non-refundable as of the date of this Amendment;
provided, however, that in the event (i) substantially all of the capital stock
- -------- -------
of Borrower is sold in a transaction and (ii) all Obligations owed to each
Lender and Agent are paid in full, in each case prior to June 28, 2002, Agent
agrees promptly thereafter to refund to Borrower a $37,500 portion of such
amendment fee.
[remainder of page intentionally left blank; signature page follows]
5
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
executed as of the date first written above.
BORROWER:
PANACO, INC.
By:
--------------------------------------
Name:
--------------------------------------
Title:
--------------------------------------
AGENT:
FOOTHILL CAPITAL CORPORATION,
as Agent for the Lenders
By:
-------------------------------------
Jeffrey Stanek
Vice President
LENDERS:
FOOTHILL CAPITAL CORPORATION, as a Lender
By:
-------------------------------------
Jeffrey Stanek
Vice President
6
ANNEX I
TO SEVENTH AMENDMENT TO
AMENDED AND RESTATED LOAN AND SECURITY AGREEMENT
CERTIFIED RESOLUTIONS OF PANACO, INC.'S BOARD OF DIRECTORS
----------------------------------------------------------
RESOLVED: That any officer of Panaco, Inc., a Delaware corporation (the
"Corporation"), acting alone, by his signature be, and the same hereby is,
authorized and directed, in the name of and on behalf of the Corporation (a) to
amend that certain Amended and Restated Loan and Security Agreement by and among
the Corporation, Panaco Production Company, Lenders signatory thereto (the
"Lenders") and Foothill Capital Corporation, a California corporation, as agent
-------
for Lenders ("Agent"), as the same may be amended, restated or otherwise
-----
modified from time to time, (b) to execute and deliver to Agent with such
changes in the terms and provisions thereof as the officer executing same shall,
in his sole discretion, deem advisable, (i) a certain proposed Seventh Amendment
to Amended and Restated Loan and Security Agreement to be executed by
Corporation, Lenders and Agent, a draft of which has been reviewed and discussed
by the Board of Directors of the Corporation, and (ii) such other loan
documents, instruments, statements and writings as the officer or officers
executing the same may deem desirable or necessary in connection therewith, and
(c) to perform such other acts as the officer or officers performing such acts
on behalf of the Corporation may deem desirable or necessary in connection
therewith; and be it
FURTHER RESOLVED: That said agreements will benefit the Corporation,
both directly and indirectly, and are in the best interests of the Corporation;
and be it
FURTHER RESOLVED: That said agreements and other statements in
writing executed in the name and on behalf of the Corporation by any officer
of the Corporation shall be presumed conclusively to be the instruments, the
execution of which is authorized by these resolutions; and be it
FURTHER RESOLVED: That the officers of the Corporation be, and the same
hereby are, authorized and directed to execute, in the name of and on behalf of
the Corporation, security agreements, financing statements, mortgages, deeds of
trust, assignments, collateral reports, loan statements, confirmations of
delivery, lien statements, pledge certificates, release certificates, removal
reports, guaranties, cross-collateralization agreements and such other writings
and to take such other actions as are necessary in their dealings with Agent,
and any such papers executed and any such actions taken by any of them prior to
this time are approved, ratified and confirmed; and be it
FURTHER RESOLVED: That the Secretary or any Assistant Secretary of the
Corporation, by the signature of any one or more of them, be, and the same
hereby are, authorized and directed to attest the execution by the Corporation
of the papers signed pursuant to these resolutions, to affix the seal of the
Corporation thereto, if required by Agent, and to certify to Agent the adoption
of these resolutions.
CERTIFICATION
-------------
The undersigned hereby certifies that the within and foregoing
resolutions are in effect as of the date hereof, without modification, and that
the person signing the within and foregoing Amendment on behalf of the
Corporation is the duly elected officer stated below his name, that he is
authorized to sign such Amendment, and that his signature thereon is genuine.
DATED: March ___, 2002
-------------------------------------
Secretary of the Corporation
7