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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________
FORM 10-K/A
Amendment Number 1
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
[ ] 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 incorporation (I.R.S. Employe Identification
or organization) Number)
1050 West Blue Ridge Boulevard, PANACO Building,
Kansas City, MO 64145-1216
(Address of principal executive offices) (Zip Code)
Registrant telephone number, including area code: (816) 942 - 6300
Securities registered pursuant to Section 12(d) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.01 par value
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes ___X___ No _______ .
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value if the voting stock held by non-affiliates of
the registrant was approximately $54,010,954 as of July 11, 1996.
12,345,361 shares of the registrant Common Stock were outstanding as of July
11, 1996.
Documents Incorporated by Reference
None
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PART I
Item 1. Business.
General
PANACO, Inc. (the Company) is a Delaware corporation that was organized in
October 1991. Effective September 1, 1992, Pan Petroleum MLP was merged into the
Company. The Company is in the oil and gas business, acquiring, drilling and
operating oil and gas properties.
Between 1984 and 1988 a total of 114 limited partnerships were
consolidated into the Company. From time to time the Company bought additional
properties. With the acquisition of the West Delta properties in 1991 the
Company shifted its emphasis offshore. Additional offshore properties were
acquired in 1994 and 1995, and the Bayou Sorrel Field was acquired in 1995. In
recent years the Company has been disposing of numerous onshore properties.
These sales were part of management's plan to concentrate on more profitable
properties in the Gulf of Mexico and to operate those properties. The Company
plans to continue disposing of properties operated by others and to concentrate
on properties it operates.
The Company has fourteen full time employees, some of whom are officers.
The Company utilizes an additional thirty contract personnel in the operation of
the offshore and Bayou Sorrel properties, and uses numerous outside geologists,
production engineers, reservoir engineers, seismologists, geophysicists and
other professionals on a consulting basis.
The Company's headquarters are located at 1050 West Blue Ridge Boulevard,
PANACO Building, Kansas City, Missouri 64145-1216, and its telephone number is
(816) 942-6300, FAX (816) 942-6305. The Houston, Texas office is located at 1100
Louisiana, Suite 5110, Houston, Texas 77002-5220, telephone (713) 652-5110, FAX
(713) 651-0928.
Business Activities
Production of Proved Reserves. The Company owns interests in approximately
574 wells located offshore Louisiana and Texas and onshore in Kansas, Louisiana,
Oklahoma and Texas. As of December 31, 1995, these properties contained
estimated Proved Reserves of approximately 1,900,000 Bbls of oil and condensate
and approximately 46,711,000 Mcf of gas and the SEC 10 Value of such Proved
Reserves was approximately $72,432,000. Approximately 20% of such Proved
Reserves was attributable to oil and 80% to natural gas, based on six Mcf of gas
being equivalent to one Bbl of oil. Information included herein with respect to
Proved Reserves and the SEC 10 Value thereof, has been prepared by the Company,
including adjustments calculated by the Company, based upon information
contained in reserve reports prepared by professional reservoir engineering
firms. See "Item 2. Properties - Significant Proved Properties."
The Company expects to hold its producing properties until the
economically recoverable reserves attributable thereto are depleted, although
the Company may sell any of its properties if management believes that such sale
would be in the Company's best interest.
Well Operations. The Company operates approximately 250 wells and owns all
or substantially all of the working interests in those wells. The Company's
remaining 324 wells are operated by third party operators. The operator of an
oil and gas property supervises production, maintains production records,
employs field personnel, and performs other functions required in the production
and administration of such
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property. The compensation paid to the operator for such services customarily
varies from well to well, depending on the nature, depth, and location of the
well being operated. Where wells are operated by the Company, it generally owns
all of the working interests or a majority of the working interest in the
leases. Therefore, its revenue and expense associated with portions of leases it
operates for other working interest holders is not significant.
Acquisition, Development, and Other Activities. The Company utilizes its
capital budget for (a) reworks and recompletions of its existing wells, (b) the
acquisition of interests in other producing properties and (c) the drilling of
development and exploratory wells. In addition, the Company evaluates other
opportunities that arise and may spend a portion of its capital budget on other
types of oil and gas activities.
Depending on the sales prices of oil and gas and its ability to finance
such activities, the Company may also drill exploratory wells on properties it
acquires. The Company does not currently have plans to drill exploratory wells
during 1996 but will evaluate potential prospects to determine the economic
benefit to the Company and may drill exploratory wells if the benefit to the
Company is reasonable when measured against the risks involved. The Company owns
approximately 10,180 gross onshore acres (1,685 net acres) that do not contain
Proved Developed Reserves.
The number and type of wells drilled by the Company will vary from period
to period depending on the amount of the capital budget available for drilling,
the cost of each well, the Company's commitment to participate in the wells
drilled on properties operated by third parties (as described in "The Company
Proposed Business activities"), the size of the fractional working interest
acquired by the Company in each well, and the estimated recoverable reserves
attributable to each well.
The Company anticipates that the funds utilized by the Company for
drilling in 1996 will be expended for drilling activities on onshore and
offshore Louisiana properties; however, the Company may engage in drilling
activities in any geographic area. The Company and its predecessors engaged in
oil and gas exploration, development, and production in sixteen states since
1974 and have participated in drilling numerous oil and gas wells, most of which
were completed as commercially productive wells. The Company currently operates
250 onshore and offshore wells. The Company believes that its management
experience will enable it to effectively utilize relatively low-risk development
drilling to increase its cash flow and reserves.
Acquisitions of properties may include acquisitions of working interests,
royalty interests, net profits interests, production payments, and other forms
of direct or indirect ownership interest in oil and gas production. The Company
may also acquire general or limited partner interest in general or limited
partnerships and interest in joint ventures, corporations, or other entities
that own, manage, or are formed to acquire, explore for, or develop oil and gas
properties or conduct other activities associated with the ownership of oil and
gas production. The Company may also acquire or participate in the expansion of
natural gas processing plants and natural gas transportation or gathering
systems. The Company currently anticipates that any properties it acquires
through its acquisition program will consist of both Producing Properties and
Unproved Properties or properties to which Proved Undeveloped Reserves are
attributable in areas it believes have potential for successful development.
The success of the Company's acquisitions will depend on (a) the Company's
ability to establish accurately the volumes of reserves and rates of future
production from producing properties being considered for acquisition and the
future net revenues attributable to reserves from such properties, taking into
account future operating costs, market prices for oil and gas, rates of
inflation, risks attendant to production of oil and gas, and a suitable return
on investment, and (b) the Company's ability to purchase properties and produce
and market oil and gas therefrom at prices and rates that over time will
generate cash flows resulting in an
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attractive return on the initial investment. The Company's cash flow and return
on investment will vary to the extent that the Company's production from an
acquired property is greater or less than that estimated at the time of
acquisition because of, for example, the results of drilling or improved
recovery programs, the demand for oil and gas, or changes in the prices of oil
and gas from those used to calculate the purchase price for producing
properties. The Company will evaluate any economically feasible project that
would enhance the value of its properties. Such a project may involve both the
acquisition of developed and undeveloped properties and the drilling of infield
and water injection wells.
The Company expects that its primary activities will continue to be
concentrated onshore and offshore Louisiana. The Company can, if it so chooses,
invest in any geographic area. Drilling on and production from offshore
properties often involves higher costs than does drilling on and production from
onshore properties, but the production achieved is much greater.
The Company may also seek to acquire oil and gas companies through stock
purchases, asset purchases, and purchases of interests in partnerships. The
Company intends to pay for those acquisitions with its own securities, cash or
any other property, or any combination of the foregoing. The consent of the
Company's lenders may be required for such purchases.
Marketing of Production. Production from the Company's properties is
marketed consistently with industry practices, which include the sale of oil at
the wellhead to third parties and the sale of gas to third parties at prices
based on factors normally considered in the industry, such as the spot price for
gas or the posted price for oil, and the quality of the oil and gas.
The Company markets most of its oil production to Texaco, Vastar, Citgo,
Conoco, Shell and Koch Industries, and is not dependent upon any single
customer. Natural gas is mostly sold on the spot market. Offshore gas is sold on
the spot market. There are numerous potential purchasers for offshore gas,
including in one instance an affiliate of the pipeline on which some of the gas
is transported. There are numerous gas purchasers doing business in the areas
involved and natural gas brokers and clearing houses. Furthermore, the Company
can contract to sell the gas directly to end users. For these reasons the
Company is not dependent upon any one customer or group of customers for the
purchase of natural gas.
The Company from time to time has entered into swap transactions, in
effect selling natural gas on the NYMEX, to assure future prices for natural gas
and protect its ability to service long term debt. In 1994 the Company utilized
natural gas floor price transactions to protect prices and suffered a small
loss. No hedging transactions were entered into in 1995 as debt was reduced to
such low levels management did not feel price protection was necessary. For 1996
the Company has entered into natural gas swap transactions at prices ranging
from $1.7511 per MMBTU to $2.253 per MMBTU, for an average price of $1.876 per
MMBTU on 15,000 MMBTU's per day.
Insurance. The Company maintains insurance coverage as is customary for
companies of a similar size engaged in operations similar to the Company's. The
Company's insurance coverage includes comprehensive general liability insurance
in the amount of $50,000,000 per occurrence for personal injury and property
damage and cost of control and operators extra expense insurance generally up to
$50,000,000 per occurrence. The Company maintains $38,000,000 in property
insurance on its offshore properties.
Funding of Business Activities
Cash Flow from Operations. Funding for the Company's activities is
provided primarily by cash flow from operations; however, the Company may use
its borrowing facilities described below and other sources.
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Generally, cash flow from properties declines over time as production declines.
The cash flow generated by the Company's activities, therefore, would decline in
the absence of increases in the prices that the Company receives for oil and gas
production or increases in the Company's production of oil and gas resulting
from the development of its properties, the acquisition of additional producing
properties, the successful implementation of improved recovery projects, or the
acquisition and development of other oil and gas properties.
Issuance of Additional Common Stock and Other Securities. The Company may
issue additional shares of Common Stock or other securities for cash, to the
extent that market and other conditions permit, and use the proceeds to fund its
activities. Additional securities issued by the Company may be of a class
preferred as to the Common Stock with respect to such matters as dividends and
liquidation rights and may also have other rights and preferences as determined
by the Board of Directors. The Certificate of Incorporation and By-laws of the
Company generally do not require the Company to obtain the consent of
stockholders for the issuance and sale of shares of Common Stock or other
securities.
Borrowings and Obligations. The Company is permitted to incur indebtedness
for any Company purpose. It is currently expected that Company indebtedness will
consist primarily of borrowings from commercial banks and credit corporations,
the sale of debt instruments, and advances from oil, gas, pipeline and other
companies.
On July 1, 1994 the Company entered into a Credit Agreement with the First
Union National Bank of North Carolina, as the agent for lenders signatory
thereto ("Primary Credit Facility"). Initially the only lender was First Union
National Bank of North Carolina. Banque Paribas has since become a 35%
participant. The loan is a reducing revolver designed to provide the Company up
to $30 million depending upon the Company's borrowing base, $22 million as of
April 1, 1996. The principal amount of the loan is due July 1, 1998. However, at
no time may the Company have outstanding borrowings under the Credit Agreement
in excess of its borrowing base. Should the borrowing base ever be determined to
be less than the outstanding principal owed under the Credit Agreement the
Company must immediately pay that difference to the lenders. Interest on the
loan is computed at base rate (the bank's prime rate) or at 1.00% to 1.75% over
the applicable Libor rate on Eurodollar loans, presently less than the bank's
prime rate. Eurodollar loans can be for terms of either one, two, three or six
months and interest on such loans is due at the expiration of the terms of such
loans, but no less frequently than every three months. Management feels that
this loan arrangement greatly facilitates its ability to make necessary capital
expenditures to maintain and improve production from its properties and makes
available to the Company additional funds for future acquisitions.
Effective December 31, 1993 the Company entered into a Senior Second
Mortgage Term Loan Agreement with a group of seven lenders represented by Kayne
Anderson Investment Management, Inc. The loan agreement permitted the Company to
borrow $5,000,000 to fund capital projects in 1994. At the discretion of the
lenders, a second $5,000,000 can be borrowed in connection with an acquisition.
Funds loaned to the Company under this loan agreement require payments of
interest only, 45 days after the end of each calendar quarter, at a rate of 12%
per annum. The Company may deliver PIK (payment in kind) notes in satisfaction
of up to $1,000,000 in interest obligations on any funds advanced. The loan
agreement contains certain financial covenants including restrictions on other
indebtedness and the payment of dividends. The note matures on December 31, 1999
and is secured by a second mortgage on a portion of the offshore oil and gas
properties of the Company. The lenders were issued warrants to acquire 815,526
(816,526 after adjustment) shares of Common Stock at an exercise price of $2.25
per share, anytime prior to December 31, 1998. These warrants were all exercised
early in 1996.
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Competition, Markets, and Regulation
Competition. There are a large number of companies and individuals engaged
in the exploration for and development of oil and gas properties. Competition is
particularly intense with respect to the acquisition of oil and gas producing
properties. The Company encounters competition from various independent oil
companies in raising capital and in acquiring producing properties. Many of the
Company's competitors have financial resources and staffs considerably larger
than the Company.
Markets. The ability of the Company to produce and market oil and gas
profitably depends on numerous factors beyond the control of the Company. The
effect of these factors cannot be accurately predicted or anticipated. These
factors include the availability of other domestic and foreign production, the
marketing of competitive fuels, the proximity and capacity of pipelines,
fluctuations in supply and demand, the availability of a ready market, the
effect of federal and state regulation of production, refining, transportation,
and sales of oil and gas, political instability or armed conflict in
oil-producing regions, and general national and worldwide economic conditions.
In recent years, worldwide oil production capacity and gas production capacity
in the United States exceeded demand and resulted in a substantial decline in
the price of oil and natural gas in the United States.
Since early 1986, certain members of the Organization of Petroleum
Exporting Countries ("OPEC") have, at various times, dramatically increased
their production of oil, causing a significant decline in the price of oil in
the world market. The Company cannot predict future levels of production by the
OPEC nations, the prospects for war or peace in the Middle East, or the degree
to which oil and gas prices will be affected, and it is possible that prices for
any oil, natural gas liquids, or gas produced by the Company will be lower than
those currently available.
The demand for 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,
gas, and refined petroleum products, the Company is unable to predict future oil
and gas prices. In order to minimize these uncertainties the Company hedges
prices with futures contracts.
Seasonality. Historically the nature of the demand for natural gas caused
prices and demand to vary on a seasonal basis. Prices and production volumes
were generally higher during the first and fourth quarters of each calendar
year. For example, from a high of $1.78 per Mcf in January of 1991 the average
price of the Company's natural gas reached a low of $1.09 in July and a new high
of $1.95 in December, averaging $1.46 for the year. However, the substantial
amount of gas storage becoming available in the U.S. is altering this
seasonality. During 1993, 1994 and 1995 the Company's gas prices ranged
from$2.78 to $1.64, $2.43 to $1.39 and $2.37 to $1.37, averaging $2.13, $1.88
and $1.58, respectively.
Regulation. The production of oil and gas is subject to federal and state
laws and regulations governing a wide variety of matters, including the drilling
and spacing of wells on producing acreage, allowable rates of production,
marketing of oil and gas, prevention of waste and pollution, and protection of
the environment.
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Possible Legislation. Currently there are legislative proposals pertaining
to the regulation and taxation of the oil and gas industry. Any of such
proposals may directly or indirectly affect the activities of the Company. No
prediction can be made as to what additional energy legislation may be proposed,
if any, enacted into law or when any such bills, if enacted, would become
effective.
Regulation of the Environment. The exploration, development, production,
and processing of oil and gas are subject to various federal and state laws and
regulations to protect the environment. Various state and governmental agencies
are considering, and some have adopted, other laws and regulations regarding
environmental control that could adversely affect the business of the Company.
These laws and regulations require the acquisition of a permit before drilling
commences, prohibit drilling activities on certain lands lying within wilderness
and other protected areas, and impose substantial liabilities for pollution
resulting from the operation of facilities owned by the Company. Compliance with
such legislation and regulations, together with any penalties resulting from
noncompliance therewith, may increase the cost of oil and gas development,
production, and processing. The Company does not currently believe that
compliance with federal, state, and local environmental regulations will have a
material adverse effect upon the Company.
Offshore Operations. Offshore operations of the Company are conducted on
both federal and state lease blocks. In all offshore areas the more stringent
regulation of the federal system, as implemented by the Mineral Management
Service of the Department of the Interior are now applicable to state leases as
well as federal leases.
The Oil Pollution Act of 1990 requires operators of oil and gas leases on
or near navigable waterways to provide $150 million in financial responsibility
by the year 1995. Implementation of this legislation has been delayed. At
present the financial responsibility requirement is $35 million and the Company
is satisfying that requirement with an insurance policy. The cost of the
additional insurance will be born by the Company.
Item 2. Properties.
The Company's properties consist of producing properties located offshore
Louisiana and Texas and onshore in Kansas, Louisiana, Oklahoma and Texas.
Significant Proved Properties. The following table sets forth certain
information with respect to the Company's properties. Such properties account
for 96% of the aggregate SEC 10 Value of the Company's properties as of December
31, 1995.
SIGNIFICANT PROVED PROPERTIES
As of December 31, 1995
Proved Reserves
Oil Gas SEC 10
Property Area (Bbls) (Bcf) Value(a)
WEST DELTA PROPERTIES Offshore LA 448,000 26.2 $34,920,410
FORMER ZAPATA PROPERTIES Offshore TX & LA 222,000 15.3 $23,896,874
BAYOU SORREL FIELD Onshore LA 898,000 3.1 $10,517,826
(a) Calculated in accordance with the rules and regulations of the SEC.
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West Delta Properties. These properties consist of 14,312 acres in Blocks
52-56 and Block 58 in the West Delta Area, Offshore Louisiana. The properties
have 35 wells, five of which were recently drilled. In 1995 the Company spent
$6.9 million on a drilling and recompletion program on these properties. The
Company is the operator and owns 100% of the working interest, with a 87.5% net
revenue interest, in the wells. Presently, most of the wells produce from depths
ranging from 1,200 feet to 12,500 feet, from Miocene age deltaic deposits.
Because of the existing surface structures and production equipment, additional
wells can be added on the properties with lower completion costs.
In recent years, major oil companies have been selling offshore properties
to independent oil companies because these properties do not have the remaining
reserve potential needed by a major oil company. Numerous independent oil
companies have acquired these offshore properties and achieved significant
success in further exploitation of these properties. 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 and to other countries where they can find and produce
the super-fields that fit their criteria.
The West Delta properties were acquired from Conoco, Inc., Atlantic
Richfield Company (now Vastar Resources, Inc.), OXY USA, Inc. and Texaco
Exploration and Production, Inc. in May 1991. During 1995 the properties had net
production averaging approximately 20,643 Mcf of natural gas and 264 barrels of
oil and condensate per day.
During 1994 the Company farmed out the deep rights (below 11,300 feet) to
an 1,800 acre parcel in Block 58 to Energy Development Corporation which drilled
a successful well to 16,500 feet. Production commenced in April 1995. The
Company retained a 12 1/2% overriding royalty interest in that acreage. The well
produces 21,000 Mcf per day and 1,500 barrels of condensate per day. Energy
Development Corporation has commenced drilling a second well.
The main production facility on the West Delta properties is a four
platform complex designated as Tank Battery #3. There are four ancillary
platforms in the eastern portion of the properties connected to Tank Battery #3.
Three wells are on one of these platforms. In the western portion there is one
production platform designated as Platform "D" in Block 58, with three wells.
The remaining 29 wells are located on satellite structures connected to Tank
Battery #3 or one of its ancillary platforms. Eight wells produce oil and
natural gas. The remaining wells produce natural gas.
In connection with its acquisition of the West Delta offshore properties
the Company has provided the sellers with a $4,700,000 plugging bond
Former Zapata Properties. On July 12th, 1995, the Company entered into a
Purchase and Sale Agreement with Zapata Exploration Company ("Zapata") to
acquire all of Zapata's offshore oil and gas properties in the Gulf of Mexico.
The properties consist of East Breaks Blocks 109 and 110, East Cameron Block
359, Eugene Island block 372, South Timbalier Block 185 and West Cameron Block
538, totaling 31,134 gross acres. The transaction was closed July 26, 1995. The
Company took over as operator of the East Breaks and West Cameron properties
effective at closing. The East Cameron property is operated by Anadarko
Petroleum Corporation. The Eugene Island property is operated by UNOCAL and the
South Timbalier property is operated by Louisiana Land & Exploration Company.
Proved reserves at December 31, 1995 attributable to the oil and gas interests
acquired, net to the Company's interest, were 222,000 Bbls and 15.3 Bcf of
natural gas. Management has identified probable and possible reserves
attributable to these properties. During 1995, subsequent to July 26th, the
properties produced 20,000 barrels and 1.8 Bcf of natural gas, net to the
Company's interest.
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In addition to the mineral interests acquired, the Company purchased a
100% interest in a 31 mile natural gas pipeline connecting the Company's East
Breaks 110 platform to the High Island Offshore System ("HIOS") and a 22 mile
oil pipeline which connects the East Breaks 110 platform with the High Island
Pipeline System ("HIPS"). HIOS and HIPS are the primary natural gas and crude
oil systems in that part of the Gulf of Mexico.
The Company's East Breaks 110 platform has significant excess capacity for
both crude oil and natural gas. Earlier in 1995, Zapata had entered into a
Facilities Sharing Agreement with AGIP Petroleum Company, Inc. ("AGIP") under
which AGIP will pay certain fees to the Company and split the cost of operating
the East Breaks 110 platform with the Company, based upon each company's
proportion of production. A portion, not to exceed $6 million, of the monies
earned pursuant to this Facilities Sharing Agreement will be paid to Zapata by
the Company.
The purchase price for the assets acquired in this transaction was
$2,748,000 in cash and the obligation to pay a production payment to Zapata
based upon future production. The production payment is based upon production
from the East Breaks 109 Field after production of 12 Bcfe gross (10 Bcfe net)
measured from October 1, 1994. The Company will pay to Zapata $.4167 per Mcfe on
the next 27 Bcfe produced, if that much is produced. Payments to Zapata on this
production payment are to be made by the Company when it is paid for the oil or
gas. Oil and gas reserves attributable to this production payment are not
included in the reserves for the properties set forth herein.
Bayou Sorrel Field. As of November 30, 1995, the Company entered into a
Purchase and Sale Agreement with Shell Western E&P Inc. ("Shell") to acquire all
of Shell's interest in the Bayou Sorrel Field in Iberville Parish, Louisiana.
The transaction closed December 27, 1995 and PANACO took over as operator from
Shell. Proved reserves attributable to the field at December 31, 1995 were
898,000 barrels and 3.1 Bcf of natural gas. In addition to the proven reserves
management has identified significant probable and possible reserves
attributable to this field. The purchase price of the field and a related
receivable of $600,000 was $10,455,000, including a $205,000 brokers' fee. This
amount was paid with funds borrowed using the Company's Primary Credit Facility.
See "Funding of Business Activities - Borrowing and Obligations," herein.
The Bayou Sorrel Field is located approximately 80 miles west of New
Orleans in Township 10 South and Ranges 10 and 11 East, Iberville Parish,
Louisiana. Cumulative production from the field as of April 30, 1995, was 35
million barrels of oil and condensate and 206 Bcf of gas.
The field was discovered by Shell in August 1954 with the drilling of the
Shell Schwing No. 1 which penetrated seven pay sands including the "D" sand
reservoir, which is the major accumulation at Bayou Sorrel.
The initial production from the field began in 1955.
Since completion of the discovery well, hydrocarbons have been encountered
in 36 sands that include 48 separate reservoirs. Production has been established
from 28 sands and 37 reservoirs. Productive sands range in depth from 7,000 feet
to 11,100 feet ("W" through "L4" sands) and range in age from Lower Miocene to
the Heterostegina zone of Upper Oligocene.
The most recent well drilled in the field was a horizontal test, the Baist
Cooperage State Unit No. 1-6 Sidetrack, which was successfully completed in the
"D" Sand during July 1995. One well was drilled in 1994 (BCSU 1-8), one drilled
in 1986, several were drilled in 1982. Most wells in this field were drilled in
the 1950's and 1960's. There are 31 wells in the field at the present time and
five salt-water disposal wells.
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The Company's current lease position in the field totals 2,120 (gross and
net) acres from eight leases. The weighted-average royalty interest of the
acreage is 14%. There are 13 active producing sand units in the field. There are
currently three areas farmed out to others.
PRO FORMA FINANCIAL INFORMATION
On July 26, 1995, the Company completed the acquisition of five offshore
producing properties from Zapata Exploration Company ("Zapata"). The purchase
price for the Zapata properties and a related receivable of $174,000 ($84,000 at
year end 1995) was $2,748,000 in cash and an obligation to pay a production
payment to Zapata based on future production. On December 26, 1995, the Company
completed the acquisition of the Bayou Sorrel Field in Iberville Parish,
Louisiana from Shell Western E & P, Inc. The purchase price of Bayou Sorrel,
$10,455,000 which included a related receivable of $600,000 and a broker's fee
of $205,000, was paid using the Company's Primary Credit Facility.
Effective December 31, 1995, the Company changed its method of accounting
for oil and gas operations from the full cost method to the successful efforts
method. The information provided below reflects this change and will not agree
with previously reported financial information.
The unaudited pro forma statement of income (operations) for the year
ended December 31, 1995 assumes the Zapata and Bayou Sorrel acquisitions had
been consummated January 1, 1995. The unaudited pro forma statement of income
(operations) includes certain adjustments to give effect to the acquisitions of
the oil and gas properties.
The pro forma statement do not purport to be indicative of the results of
the Company had these acquisitions occurred on the date assumed, nor is the pro
forma statement necessarily indicative of the future results of the Company. The
pro forma statement should be read together with the Financial Statements of the
Company, including the notes thereto and included elsewhere in this Statement.
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<TABLE>
PANACO, INC.
Unaudited Pro Forma Combined Statement of Income (Operations)
For the Year Ended December 31, 1995
<CAPTION>
Zapata Bayou PANACO, Inc.
PANACO, Inc. Properties Sorrel Field Pro Forma Pro Forma
(As Restated) 1/1 - 7/26/95 1/1 - 12/26/95 Adjustments Combined
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REVENUES
<S> <C>
Oil and gas sales 18,447,000 3,623,000 3,326,000 $ 25,396,000
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Futures contracts - - - - -
------------- -------------- ------------- -------------- -------------
Total 18,447,000 3,623,000 3,326,000 - 25,396,000
------------- -------------- ------------- -------------- -------------
COSTS AND EXPENSES
Lease operating 8,055,000 1,460,000 867,000 280,000 (a) 10,662,000
Depreciation, depletion and amortization 8,064,000 - - 1,812,000 (b) 9,876,000
Exploration expenses 8,112,000 - - - 8,112,000
Provision for losses and (gains) on
disposition and write-down of assets 751,000 - - - 751,000
General and administrative 690,000 - 297,000 - 987,000
Production and ad valorem taxes 1,078,000 - - - 1,078,000
------------- -------------- ------------- -------------- -------------
Total 26,750,000 1,460,000 1,164,000 2,092,000 31,466,000
------------- -------------- ------------- -------------- -------------
NET OPERATING INCOME (LOSS) (8,303,000) 2,163,000 2,162,000 (2,092,000) (6,070,000)
------------- -------------- ------------- -------------- -------------
OTHER INCOME (EXPENSE)
Interest income 5,000 - - - 5,000
Interest expense (992,000) - - (651,000) (c) (1,643,000)
------------- -------------- ------------- -------------- -------------
Total (987,000) - - (651,000) (1,638,000)
------------- -------------- ------------- -------------- -------------
NET INCOME (LOSS) BEFORE INCOME TAXES (9,290,000) 2,163,000 2,162,000 (2,743,000) (7,708,000)
INCOME TAXES (BENEFIT) - - - - -
------------- -------------- ------------- -------------- -------------
NET INCOME (LOSS) (9,290,000) 2,163,000 2,162,000 (2,743,000) (7,708,000)
============= ============== ============= ============== =============
EARNINGS (LOSS) PER COMMON SHARE
Primary
Net earnings (loss) (0.81) (0.67)
============= =============
Assuming full dilution
Net earnings (loss) (0.81) (0.67)
============= =============
Weighted average shares outstanding
Primary
11,504,615 11,504,615
============= =============
Assuming full dilution 11,504,615 11,504,615
============= =============
The accompanying notes to pro forma financial statements are an integral part of this statement
10
</TABLE>
<PAGE>
NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME (OPERATIONS)
1. Basis of Presentation
The Unaudited Pro Forma Statement of Income (Operations) of PANACO, Inc.
presents the combined effects of the acquisition of the Zapata properties and
Bayou Sorrel Field as if the acquisitions had been consummated January 1, 1995.
2. Pro Forma Entries
(a) To record the estimated additional insurance expense.
(b) To record the additional depletion and depreciation expense for the
increased property costs and production volumes (see Note 4 below).
(c) To record the additional interest expense for increased term of
borrowing (see Note 5 below).
3. Taxes
No additional operating taxes are included for the Zapata properties as
the production from these properties is from federal offshore waters and are not
subject to severance taxes.
4. Depletion, Depreciation & Amortization
Additional depletion and depreciation expense is included to reflect the
additional property costs and production volumes assuming the transaction was
consummated January 1. The original purchase prices are used for the cost of the
properties. The actual purchase prices of the properties were reduced by the net
income of the properties from the effective dates of the purchases until the
closing dates.
5. Interest
Additional interest expense is included as if the transactions had taken
place January 1. It is assumed that the Zapata acquisition price was paid in
cash and the Bayou Sorrel acquisition price was paid for using the Company's
Primary Credit Facility. Interest is computed on the additional borrowings at
the estimated rates in effect at January 1.
Undeveloped Acreage and Unproved Properties. The Company holds interest in
10,180 gross onshore acres (1,685 net acres) of Undeveloped Acreage to which no
Proved Developed Reserves have been assigned. The Company may undertake
development activities on certain of this acreage, although it is not likely at
this time.
The Undeveloped Acreage and Unproved Properties consist of interests in
undeveloped nonproducing oil and gas leases, undeveloped oil and gas leases held
by production, and certain nonproducing royalty interests. The development
potential of these leases varies greatly. The nonproducing royalty acreage
consists of royalty and overriding royalty interests.
11
<PAGE>
Oil and Gas Information.
The following tables set forth selected oil and gas information for the
Company. The Company's offshore and Bayou Sorrel reserve reports were prepared
by Ryder Scott Company and the onshore reserve report was prepared by McCune
Engineering. Future results may vary significantly from the amounts reflected in
the information set forth herein because of normal production declines and
future acquisitions.
Estimated Proved Reserves. The following table sets forth information as
of December 31, 1995 as to the estimated Proved Reserves attributable to the
Company's properties.
PROVED RESERVES (a)
As of December 31, 1995
Oil and liquids (Bbls):
Proved Developed Reserves ............................. 1,794,000
Proved Undeveloped Reserves ........................... 106,000
Total Proved Reserves ............................. 1,900,000
Natural gas (Mcf):
Proved Developed Reserves ............................. 40,323,000
Proved Undeveloped Reserves ........................... 6,388,000
Total Proved Reserves ............................. 46,711,000
(a) Calculated in accordance with the rules and regulations of the SEC, based
upon year end prices of $17.75 per barrel of oil and $2.24 per MMBTU of
gas, adjusted for basis differentials, BTU content of gas and specific
gravity of oil. The Company prepares a reserve report as of the end of
each calendar year.
Estimated Future Net Revenues from Proved Reserves. The following table
sets forth information as of December 31, 1995 as to the estimated future net
revenues (before deduction of income taxes) from the production and sale of the
Proved Reserves attributable to the Company's properties.
ESTIMATED FUTURE NET REVENUES
FROM PROVED RESERVES (a)
As of December 31, 1995
Proved Total
Developed Proved
Reserves Reserves
Estimated Future net revenues (b):
1996 ............................... $23,604,312 $23,534,097
1997 ............................... 21,534,708 21,976,058
1998 ............................... 16,618,831 18,861,208
1999 ............................... 9,404,159 11,538,915
Thereafter ......................... 10,876,163 13,613,627
Total ........................ $82,038,173 $89,523,905
Present value (10%) of estimated future net
revenues................................... $69,792,508 $72,432,426
(a) Calculated in accordance with the rules and regulations of the SEC, based
upon year end prices of $17.75 per barrel of oil and $2.24 per MMBTU of
offshore gas, adjusted for basis differentials, BTU content of gas and
specific gravity of oil. The Company prepares a reserve report as of the
end of each calendar year.
(b) Estimated future net revenues represent estimated future gross revenues
from the production and sale of Proved Reserves, net of estimated
operating costs, future development costs estimated to be required to
achieve estimated future production and estimated future costs of plugging
offshore wells and removing offshore structures.
12
<PAGE>
<TABLE>
Production, Price, and Cost Data. The following table sets forth certain
production, price, and cost data with respect to the Company's properties, for
the three years ended December 31, 1995, 1994 and 1993.
<CAPTION>
PRODUCTION, PRICE, AND COST DATA
For the Years Ended December 31,
1995 1994 1993
Oil:
<S> <C> <C> <C>
Net Production (Bbls)(a)............. 170,000 137,000 180,000
Revenue.............................. $ 2,853,000 $ 2,103,000 $ 3,003,000
Average net Bbls per day (a)......... 466 375 493
Average sales price per Bbl.......... $ 16.78 $ 15.35 $ 16.69
Gas:
Net production (Mcf)(a).............. 9,850,000 8,139,000 5,586,000
Revenue.............................. $15,594,000 $15,264,000 $12,635,000
Average net Mcf per day (a).......... 27,000 22,300 15,300
Average sales price per Mcf......... $ 1.58 $ 1.88 $ 2.24
Total revenues............................ $18,447,000 $17,367,000 $15,638,000
Production costs:
Production cost....................... $ 8,055,000 $ 5,231,000 $ 5,297,000
Equivalent Mcf(b)..................... 10,870,000 8,961,500 6,666,000
Production costs per Equivalent Mcf... $ .74 $ .58 $ .79
(a) Production information is net of all royalty interests, overriding royalty
interest and the net profits interest in the West Delta properties owned by
the Company's lenders under the EnCap Credit Facility.
(b) Oil production is converted to Equivalent Mcf at the rate of 6 Mcf per Bbl,
representing the estimated relative energy content of natural gas to oil.
</TABLE>
Productive Wells. The following table sets forth the number of productive
oil and gas wells, as of December 31, 1995, attributable to the Company's
properties.
PRODUCTIVE WELLS(a)
As of December 31, 1995
Company
Gross productive onshore wells(b): Operated
Oil................................. 245................... 83
Gas................................. 246................... 110
Total...................... ..... 491................... 193
Net productive onshore wells(c):
Oil................................. 111................... 56
Gas................................. 91................... 83
Total............................ 202................... 139
Gross productive offshore wells(b):
Oil................................. 8................... 8
Gas................................. 75................... 49
Total............................ 83................... 57
Net productive offshore wells(c):
Oil................................. 8................... 8
Gas................................. 50................... 45
Total............................ 58................... 53
(a) Productive wells consist of producing wells and wells capable of
production, including shut-in wells and water disposal and injection
wells. One or more completions in the same bore hole are counted as one
well.
(b) A "gross well" is a well in which a working interest is owned. The number
of gross wells represents the sum of the wells in which a working
interest is owned.
(c) A "net well" is deemed to exist when the sum of the fractional working
interests in gross wells equals one. The number of net wells is the sum
of the fractional working interests in gross wells.
13
<PAGE>
Acreage. The following table sets forth the developed, undeveloped, and
royalty acreage, as of December 31, 1995, attributable to the Company's
properties.
LEASEHOLD ACREAGE
As of December 31, 1995
Developed onshore acreage(a):
Gross acres(b)........................................... 74,849
Net acres(c)............................................. 14,656
Undeveloped onshore acreage(d):
Gross acres(b)........................................... 10,180
Net acres(c)............................................ 1,685
Onshore royalty acreage(e).................................... 28,548
Developed offshore acreage:
Gross acres(b)........................................... 44,699
Net acres(c)............................................. 29,637
(a) Developed acreage is acreage spaced for or assignable to productive
wells.
(b) A "gross acre" is an acre in which a working interest is owned. The
number of gross acres represents the sum of the acres in which a working
interest is owned.
(c) A "net acre" is deemed to exist when the sum of the fractional working
interests in gross acres equals one. The number of net acres is the sum of the
fractional working interests in gross acres.
(d) Undeveloped acreage is oil and gas acreage on which wells have not been
drilled or to which no Proved Reserves other than Proved Undeveloped Reserves
have been attributed by independent petroleum engineers on the date of
acquisition
(e) Royalty acreage is acreage in which the Company has a royalty interest
but no direct working interests.
14
<PAGE>
Drilling Activities. The following table sets forth the number of gross
productive and dry wells in which the Company had an interest, that were drilled
and completed during the five years ended December 31, 1995. Such information
should not be considered indicative of future performance, nor should it be
assumed that there is necessarily any correlation between the number of
productive wells drilled and the oil and gas reserves generated thereby or the
costs to the Company of productive wells compared to the costs to the Company of
dry wells.
DRILLING ACTIVITIES
For the five years Ended December 31, 1995
Developmental Wells Exploratory Wells
Completed Dry Completed Dry
Oil Gas Oil Gas Oil Gas Oil Gas
1991 4 1 0 0 0 0 0 0
1992 0 0 1 0 0 0 0 0
1993 3 0 0 0 0 0 0 0
1994 5 4 0 0 0 1 0 0
1995 0 0 0 0 0 0 0 3
TOTAL 12 5 1 0 0 1 0 3
Item 3. Legal Proceedings.
The Company is presently a party to two legal proceedings, which it
considers to be routine and in the ordinary course of its business. Management
has no knowledge of any pending or threatened claims that could give rise to
litigation.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Description of Capital Stock.
The authorized capital stock of the Company consists of 20,000,000 shares
of Company Common Stock, par value $.01 per share, and 1,000,000 shares of
preferred stock, par value $.01 per share. The following description of the
capital stock of the Company does not purport to be complete or to give full
effect to the provisions of statutory or common law and is subject in all
respects to the applicable provisions of the Company's Certificate of
Incorporation and the information herein is qualified in its entirety by this
reference.
Company Common Stock
The Company is authorized by its Certificate of Incorporation to issue
20,000,000 shares of Common Stock, of which 12,345,361 shares were issued and
outstanding as of May 1, 1996 and are held by approximately 5,400 shareholders.
15
<PAGE>
The holders of shares of Common Stock are entitled to one vote for each
share held on all matters submitted to a vote of common stockholders. The Common
Stock does not have cumulative voting rights, which means that the holders of a
majority of the shares of Common Stock outstanding can elect all the directors
if they choose to do so. In that event, the holders of the remaining shares will
not be able to elect any directors.
Each share of Common Stock is entitled to participate equally in
dividends, as and when declared by the Board of Directors, and in the
distribution of assets in the event of liquidation, subject in all cases to any
prior rights of outstanding shares of preferred stock. The shares of Common
Stock have no preemptive or conversion rights, redemption rights, or sinking
fund provisions. The outstanding shares of Common Stock are duly authorized,
validly issued, fully paid, and nonassessable.
Warrants
The Company has outstanding warrants to acquire 289,365 Common Shares at
prices ranging from $2.00 to $2.375, of which 250,000 expire thirty days after
the date of the Company's Form S-1/A Post Effective Amendment No. 8 and 39,365
expire December 31, 1997. These warrants 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 registration of Common
Shares.
In addition the Company's lenders, pursuant to the Senior Second Mortgage
Term Loan, acquired 816,526 Common Shares upon the exercise of warrants which
are restricted securities within the meaning of the Securities Act of 1933 and
can only be sold pursuant to an exemption from registration or an offering which
is the subject of an effective registration statement. The holders of these
shares have demand registration rights and "piggy back" rights in the event the
Company registers an offering of its Common Shares. See "Funding of Business
Activities - Borrowing and Obligations," herein.
Preferred Stock
Pursuant to the Company's Certificate of Incorporation, the Company is
authorized to issue 1,000,000 shares of preferred stock, and the Company's Board
of Directors, by resolution, may establish one or more classes or series of
preferred stock 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 stockholder approval.
A number of shares of Preferred Stock equal to one share for every one
hundred Common Shares outstanding has been reserved for issuance pursuant to the
Company's Shareholder Rights Plan, and designated as Series A Preferred Stock.
No shares of this series A Preferred Stock have been issued or are outstanding.
Other than the designation as Series A the Series A Preferred Stock has not had
designations, preferences and rights established by the Board of Directors. See
"Shareholder Rights Plan," below. The designations, preferences and rights will
be established if and when any of this Series A Preferred stock is to be issued.
Transfer Agent
The transfer agent, registrar and dividend disbursing agent for the Common
Stock is American Stock Transfer and Trust Company, 6201 15th Avenue, Brooklyn,
New York 11204.
16
<PAGE>
Market Prices
The Company Common Stock is quoted on the National Association of
Securities Dealers, Inc. Automated Quotation System ("NASDAQ") under the symbol
"PANA". The following table sets forth, for the periods indicated, the high and
low bid for the Common Stock.
1994
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
High 3 5/8 4 3/8 4 5/8 4 1/4
Low 2 9/16 2 15/16 3 1/2 3 5/8
1995
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
High 4 5/16 4 7/8 5 5/16 5
Low 3 5/8 4 4 1/8 4
1996
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter
High 5
Low 3 7/16
Dividends
Dividend History. The Company has not paid any cash dividends on the
Company Common Stock.
Dividend Restrictions. The Delaware General Corporation Law, to which the
Company is subject, permits the Company to pay dividends only out of its capital
surplus (the excess of net assets over the aggregate par value of all
outstanding shares of capital stock) or out of net profits for the fiscal year
in which the dividend is declared or the preceding fiscal year. The two credit
facilities require the consent of the lenders to any dividends or distributions
by the Company and to any purchases by the Company of shares of Common Stock.
Dividend Policy. Subject to the restrictions in the preceding paragraph,
the Company will pay dividends on the Company Common Stock if, as, and when
declared by the Board of Directors. The Company retains its earnings and cash
flow to finance the expansion and development of its business and currently does
not intend to pay dividends on the Company Common Stock. The Company hopes,
however, that the retention and reinvestment of funds that would otherwise be
distributed will have the effect of increasing the financial strength of the
Company and, therefore, increasing the market value of the Common stock. Any
payments of dividends will depend on, among other factors, the earnings, cash
flow, financial condition, and capital requirements of the Company.
17
<PAGE>
Shareholder Rights Plan
On August 2, 1995, the Board of Directors declared a dividend distribution
of one Right for each outstanding share of Common Stock of the Company to the
stockholders of record on August 3, 1995, (the "Record Date"). Each Right
entitles the registered holder to purchase from the Company one one-hundredth of
a share of Series A Preferred Stock (the "Preferred Stock"), or in some
circumstances, Common Stock, other securities, cash or other assets as
summarized below, at a price of $30.00 per share (the "Purchase Price"), subject
to adjustment. The description and terms of the Rights are set forth in a Rights
Agreement (the "Rights Agreement") between the Company and American Stock
Transfer and Trust Company, as Rights Agent.
The Shareholder Rights Plan was designed to reduce the likelihood of
inadequate bids, partial bids, market accumulations and front-end loaded offers
to acquire the Company's Common Shares, which are not in the best interest of
all the Company's shareholders. The adoption of the Plan communicates the
Company's intention to resist such actions as are not in the best interest of
all shareholders, provides time for the Board of Directors to consider any offer
and seek alternative transactions to maximize shareholder value. The Plan was
adopted upon the advice of the Company's investment bankers in 1995 when there
were numerous statements in the media that the Company might be the target of a
takeover attempt, which never materialized.
Until the earlier to occur of (i) the date of a public announcement that a
person or group of affiliated or associated persons (an "Acquiring Person")
acquired, or obtained the right to acquire, beneficial ownership of 20% or more
of the outstanding shares of the Common Stock or (ii) ten days following the
commencement or announcement of an intention to make a tender offer or exchange
offer that would result in a Person or group beneficially owning 20% or more of
such outstanding shares of Common Stock (the earlier of such dates being called
the "Distribution Date"), the Rights will be evidenced, with respect to any of
the Company's Common Stock certificates outstanding as of the Record Date, by
such Common Stock certificate. The Rights Agreement provides that, until the
Distribution Date, the Rights will be transferred with and only with the
Company's Common Stock. Until the Distribution Date (or earlier redemption or
expiration of the Rights), new Common Stock certificates issued after the Record
Date upon transfer or new issuance of the Company's Common Stock will contain a
notation incorporating the Rights Agreement by Reference. Until the Distribution
Date (or earlier redemption or expiration of the Rights), the surrender for
transfer of any of the Company's Common Stock certificates outstanding as of the
Record, will also constitute the transfer of the Rights associated with the
Common Stock represented by such certificate. As soon as practicable following
the Distribution Date, separate certificates evidencing the Rights ("Rights
Certificates") will be mailed to holders of record of the Company's Common Stock
as of the close of business on the Distribution Date and such separate Rights
Certificates alone will evidence the Rights.
The Rights are not exercisable until the Distribution Date. The Rights
will expire on August 4, 2005, unless earlier redeemed by the Company as
described below.
The Purchase Price payable, and the number of shares of Preferred Stock
(or Common Stock, other securities, cash or other assets, as may be necessary)
issuable upon exercise of the Rights are subject to adjustment from time to time
to prevent dilution (i) in the event of a stock dividend on, or a subdivision,
combination or reclassification of the Preferred Stock, (ii) upon the grant to
holders of the Preferred Stock of certain rights or warrants to subscribe for
shares of the Preferred Stock or convertible securities at less than the current
market price of the Preferred Stock or (iii) upon the distribution to holders of
the Preferred Stock of evidences of indebtedness or assets (excluding regular
periodic cash dividends out of earnings or retained earnings or dividends
payable in the Preferred Stock) or of subscription rights or warrants) other
than those referred to above).
18
<PAGE>
In the event that the Company were acquired in a merger or other business
combination transaction of 50% or more of its assets or earning power were sold,
proper provision shall be made so that each holder of a Right, other than of
Rights that are or were beneficially owned by an Acquiring Person (which will
thereafter be void) shall thereafter have the right to receive, upon the
exercise thereof at the then current exercise price of the Right, that number of
shares of Common Stock of the acquiring company which at the time of such
transaction would have a market value of two times the exercise price of the
Right. In the event that an Acquiring Person becomes the beneficial owner of 20%
or more of the outstanding shares of Common Stock, proper provision shall be
made so that each holder of a Right, other than of Rights that are or were
beneficially owned by the Acquiring Person (which will thereafter be void), will
thereafter have the right to receive upon exercise that number of shares of the
Common Stock (or in certain other circumstances, assets or other securities)
having a market value of two times the exercise price of the Right.
With certain exceptions, no adjustment in the Purchase Price will be
required until cumulative adjustments require an adjustment of at least 1% in
such Purchase Price. No fractional shares will be issued (other than fractional
shares which are integral multiples of one one-hundredth of a share of Preferred
Stock) and, in lieu thereof, an adjustment in cash will be made based on the
market price of the Preferred Stock on the last Trading Date prior to the date
of exercise.
At any time prior to 5:00 P.M. Kansas City time on the tenth calendar day
after the first date after the public announcement that a person or group of
affiliated or associated persons has acquired beneficial ownership of 20% or
more of the outstanding shares of the Common Stock of the Company (the "Shares
Acquisition Date"), the Company may redeem the Rights in whole, but not in part,
at a price of $0.005 per Right (the "Redemption Price"). Following the Shares
Acquisition Date, but prior to an event listed in Section 13(a) of the Rights
Agreement, the Company may redeem the Rights in connection with any event
specified in Section 13(a) in which all shareholders are treated alike and which
does not include the Acquiring Person or his Affiliates or Associates.
Thereafter, the Company's right of redemption may be reinstated if an Acquiring
Person reduces his beneficial ownership to 10% or less of the outstanding shares
of Common Stock in a transaction or series of transactions not involving the
Company. Immediately upon the action of the Board of Directors of the Company
electing to redeem the Rights, the Company shall make announcement thereof, and
upon such election, the right to exercise the Rights will terminate and the only
right of the holders of Rights will be to receive the Redemption Price.
Until a Right is exercised, the holder thereof, as such, will have no
rights as a shareholder of the Company, including, without limitation, the right
to vote or to receive dividends.
The provisions of the Rights Agreement may be amended by the Board of
Directors in order to cure any ambiguity or correct any defect or inconsistency,
extend the Redemption Period and, prior to the Distribution Date, to make
changes deemed to be in the best interests of the holders of the Rights or,
after the Distribution Date, to make such other changes which do not adversely
affect the interests of the holders of the Rights (excluding the interests of
any Acquiring Person and its Affiliates and Associates).
A copy of the Rights Agreement has been filed with the Securities and
Exchange Commission as an Exhibit to a Registration Statement on Form 8-A dated
August 21, 1995. A copy of the Rights Agreement is available free of charge from
the Company. This summary description of the Rights does not purport to be
complete and is qualified in its entirety by reference to the Rights Agreement,
which is hereby incorporated herein by reference.
19
<PAGE>
Certain Anti-takeover Provisions
The provisions of the Company's Certificate of Incorporation and By-laws
summarized in the following paragraphs may be deemed to have an anti-takeover
effect and may delay, defer, or prevent a tender offer or takeover attempt that
a stockholder might consider to be in that stockholder's best interests,
including attempts that might result in a premium over the market price for the
shares held by stockholders. In addition, certain provisions of Delaware law and
the Company's Long-term Incentive Plan may be deemed to have a similar effect.
Certificate of Incorporation and By-laws. The Board of Directors of the
Company is divided into three classes. The term of office of one class of
directors expires at each annual meeting of stockholders, when their successors
are elected and qualified. Directors are elected for three-year terms.
Stockholders may remove a director only for cause. In general, the Board of
Directors, not the Company's stockholders, has the right to appoint persons to
fill vacancies on the Board of Directors.
Pursuant to the Company's Certificate of Incorporation, the Company's
Board of Directors, by resolution, may establish one or more classes or series
of preferred stock 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 stockholder approval.
Any rights, preferences, privileges, and limitations that are established could
have the effect of impeding or discouraging the acquisition of control of the
Company.
The Company's Certificate of Incorporation contains a "fair price"
provision that requires the affirmative vote of the holders of at least 80% of
the voting stock of the Company and the affirmative vote of at least two-thirds
of the voting stock of the Company not owned, directly or indirectly, by the
Related Person (hereafter defined) to approve any merger, consolidation, sale or
lease of all or substantially all of the assets of the Company, or certain other
transactions involving any Related Person. For purposes of the fair price
provision, a "Related Person" is any person beneficially owning 10% or more of
the voting stock of the Company who is a party to the Transaction at issue, a
director who is also an officer of the Company and is a party to the Transaction
at issue, an affiliate of either such person, and certain transferees of those
persons. The voting requirement is not applicable to certain transactions,
including those that are approved by the Company's Continuing Directors (as
defined in the Certificate of Incorporation) or that meet certain "fair price"
criteria contained in the Certificate of Incorporation.
The Company's Certificate of Incorporation further provides that
stockholders may act only at annual or special meeting of stockholders and not
by written consent, that special meetings of stockholders may be called only by
the Board of Directors, and that only business proposed by the Board of
Directors may be considered at special meetings of stockholders.
The Company's Certificate of Incorporation also provides that the only
business (including election of directors) that may be considered at an annual
meeting of stockholders, in addition to business proposed (or persons nominated
to be directors) by the directors of the Company, is business proposed (or
persons nominated to be directors) by stockholders who comply with the notice
and disclosure requirements of the Certificate of Incorporation. In general, the
Certificate of Incorporation requires that a stockholder give the Company notice
of proposed business or nominations no later than 60 days before the annual
meeting of stockholders (meaning the date on which the meeting is first
scheduled and not postponements or adjournments thereof) or (if later) 10 days
after the first public notice of the annual meeting is sent to common
stockholders. In general, the notice must also contain information about the
stockholder 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.
20
<PAGE>
The stockholder 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
stockholders 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 stock 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 stock of the Company, together with
approval by the holders of at least two-thirds of the outstanding voting stock
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 stock is required to amend the provisions
prohibiting stockholders from acting by written consent.
Delaware Anti-takeover Statute. The Company is a Delaware corporation and
is subject to Section 203 of the Delaware General Corporation Law. In general,
Section 203 prevents an "interested stockholder" (defined generally as a person
owning 15% or more of the Company's outstanding voting stock) from engaging in a
"business combination" (as defined in Section 203) with the Company for three
years following the date that person became an interested stockholder unless (a)
before that person became an interested stockholder, the Board of Directors of
the Company approved the transaction in which the interested stockholder became
an interested stockholder or approved the business combination, (b) upon
consummation of the transaction that resulted in the interested stockholder's
becoming an interested stockholder, the interested stockholder owns at least 85%
of the voting stock of the Company outstanding at the time the transaction
commenced (excluding stock held by directors who are also officers of the
Company and by employee stock plans that do not provide employees with the right
to determine confidentially whether shares held subject to the plan will be
tendered in a tender or exchange offer), or (c) following the transaction in
which that person became an interested stockholder, the business combination is
approved by the Board of Directors of the Company and authorized at a meeting of
stockholders by the affirmative vote of the holders of at least two-thirds of
the outstanding voting stock of the Company not owned by the interested
stockholder.
Under Section 203, these restrictions also do not apply to certain
business combinations proposed by an interested stockholder following the
announcement or notification of one of certain extraordinary transactions
involving the Company and a person who was not an interested stockholder during
the previous three years or who became an interested stockholder with the
approval of a majority of the Company's directors, if that extraordinary
transaction is approved or not opposed by a majority of the directors who were
directors before any person became an interested stockholder in the previous
three years or who were recommended for election or elected to succeed such
directors by a majority of such directors then in office.
Long-term Incentive Plan. Awards granted pursuant to the Company's
Long-term Incentive Plan may provide that, upon a change in control of the
Company, (a) each holder of an option will be granted a corresponding stock
appreciation right, (b) all outstanding stock appreciation rights and stock
options become immediately and fully vested and exercisable in full, and (c) the
restriction period on any restricted stock award shall be accelerated and the
restrictions shall expire.
Debt. Certain provisions in the Primary and Secondary Loans may also
impede a change in control, in that they provide that the loans become due if
there is a change in the management of the Company or a merger with another
company.
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<PAGE>
Item 6. Selected Financial Data.
Selected financial data for the five years 1991 through 1995 is presented
below. Effective December 31, 1995, the Company changed its method of accounting
for oil and gas operations from the full cost method to the successful efforts
method. The information provided below reflects this change and will not agree
with previously reported financial information. This data also reflects a
retroactive restatement for all periods presented to reflect the merging of Pan
Petroleum MLP into the Company effective September 1, 1992. The information also
reflects the acquisition of the West Delta offshore properties as of May 28,
1991, accounted for utilizing the "purchase" method.
<TABLE>
Summary of Operations:
<CAPTION>
For the year ended December 31,
(As Restated)
1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
Oil and Gas revenue $18,447,000 $17,367,000 $15,638,000 $14,436,000 $8,017,000
Futures contracts - (29,000) (3,033,000) (1,101,000) 132,000
Total revenue 18,447,000 17,338,000 12,605,000 13,335,000 8,149,000
Depreciation, depletion
& amortization 8,064,000 6,038,000 4,288,000 4,245,000 3,305,000
Lease operating expense 8,055,000 5,231,000 5,297,000 5,762,000 3,728,000
Exploration expenses 8,112,000 - - - -
Production and
ad valorem taxes 1,078,000 1,006,000 754,000 867,000 635,000
Provision for losses and (gains)
on disposition and write-downs
of assets 751,000 1,202,000 3,824,000 - (91,000)
Net operating income (loss) (8,303,000) 3,274,000 (2,100,000) 1,922,000 128,000
Interest (net) and other
expenses 987,000 1,623,000 1,886,000 2,323,000 1,597,000
Net income (loss) (9,290,000) 1,115,000 (3,986,000) (401,000) (1,469,000)
Net income (loss) per
common share (0.81) 0.11 (0.53) (0.05) (0.23)
Summary Balance Sheet Data:
Total assets $36,169,000 $29,095,000 $24,432,000 $31,085,000 $ 3,827,000
Long-term debt 22,390,000 12,500,000 12,465,000 15,380,000 18,945,000
Stockholders' equity 9,174,000 14,882,000 8,744,000 11,700,000 10,889,000
Cash dividends declared
per common share 0.00 0.00 0.00 0.00 0.03
</TABLE>
22
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
For the years ended December 31, 1991 - December 31, 1995
General
"Oil and Gas Revenue" has varied due to several factors. The prices of oil
and gas have fluctuated widely during the years shown. Oil prices are influenced
by world political events as well as decisions made by OPEC regarding the
production quotas of its members. Prices are further influenced by world
economic conditions which affect industrial output and the need for oil. In 1995
the Company sold 170,000 barrels for an average of $16.78 per barrel accounting
for 15% of oil and gas revenue. The Bayou Sorrel acquisition in December should
substantially increase oil production. In 1994 oil was 12% of such revenue with
137,000 barrels at an average price of $15.35. In 1993 oil was 19% of such
revenue with 180,000 barrel at an average price of $16.69. In 1992 oil was 25%
of such revenue with 174,000 barrels at an average price of $19.41. In 1991 the
Company sold 129,000 barrels of oil for an average price of $19.68 per barrel;
accounting for 29% of its oil and gas revenue.
The acquisition of the Bayou Sorrel Field increased the percentage of the
Company's reserves attributable to oil from 12% to 20% and one could anticipate
that there will be a corresponding increase in the percentage of Oil and Gas
Revenue attributable to oil. The Company plans up to $4 million in capital
expenditures on the field during 1996 which will be funded with cash from
operations.
A large part of the changes affecting most operating accounts in 1992 was
due to West Delta being operated for twelve months compared with only seven
months in 1991.
The average natural gas price received by the Company has fluctuated but
generally followed the trend of national gas prices. By 1995, gas revenue
contributed 85% of revenue compared with 46% in 1990. While 1995 saw a
production increase of 21%, the drop in natural gas prices to $1.58 offset most
of the benefit. Part of the increase was due to the Zapata acquisition. By
drilling four horizontal wells and recompleting eight existing wells, the
Company increased production by 34% in 1994. With the West Delta acquisition gas
production increased in 1992, 1993 and 1994 to 5,811,000, 5,586,000 and
8,139,000 Mcf, which sold for an average price of $1.81, $2.24 and $1.88 per
Mcf. In 1991 the Company sold 3,714,000 Mcf for an average price of $1.46.
"Futures contracts" were swap transactions on the natural gas futures
market on NYMEX. They resulted in significant losses during 1992 and 1993 which
had the effect of lowering the price received by the Company for natural gas.
"Total revenue" increased in 1995 due to the production increase even
though natural gas prices were lower, averaging $1.58. The revenue increase of
38% in 1994 was a result of the increased production, management's change from
futures contracts to floor contracts to protect gas prices and the adverse
affect of the mezzanine financing being prepaid in 1994. The 5% decrease in 1993
was the result of additional losses on futures contracts. The acquisition and
development of the West Delta properties and a $.35 per Mcf increase in the
average natural gas price contributed to the 64% increase in revenues in 1992.
The "depreciation, depletion and amortization" increase in 1995 was
primarily the result of the acquisition of the Zapata properties for $2,748,000,
$1.5 million in capitalized costs on existing properties and the increase in
production bringing about an increase in the rate of depletion. The increase in
1994 is due to the 1994 drilling and rework program increasing capitalized cost
and the 34% increase in production. The expense for 1993 remained relatively
constant over 1992 with only a slight decrease due to lower production.
"Lease operating expense" increased significantly during 1995 because of
(1) $1,008,000 related to the acquisition of the Zapata properties in July which
added interests on six offshore platforms and 44 wells, (2)
23
<PAGE>
$1,105,000 related to additional operating expenses on the West Delta properties
to maintain production from some of the more rapidly declining wells, and (3)
$711,000 related to expensing of some items which might otherwise have been
capitalized. Such expenses rose from $.58 per Mcfe in 1994 to $.74 per Mcfe in
1995, after having been $.84, $.84, and $.79 per Mcfe in 1991, 1992, and 1993,
respectively.
The 1995 "exploration expense" consisted of dry hole exploratory costs of
$796,000 on Eugene Island Block 50, $1,378,000 on South Timbalier Block 33 and
$5,938,000 on West Delta Block 54. The Company currently plans no further
exploratory activity in these blocks.
"Production and ad valorem taxes" increased 33% in 1994 due to increased
production from four horizontal wells drilled in state waters in the West Delta
properties in 1994.
"Net operating income (loss)" for 1995 would have been $560,000 were it
not for the $8,112,000 exploratory expenses and $751,000 property write-down.
The increased production in 1994, along with $2.6 million lower asset
write-downs brought about the large increase in 1994. The operating income for
1993 decreased due to lower production, and an asset write-down of $3.8 million.
Net operating income increased from 1991 to 1992 primarily due to the
realization of the benefit of a large number of expenses incurred in 1991 and
again the ownership of the West Delta properties for a full twelve months.
The lower levels of long term debt that prevailed throughout most of 1995
resulted in a decrease in "interest expense." Long term debt increased during
1995 to fund the acquisitions of the Zapata properties in July and more
importantly the acquisition of the Bayou Sorrel Field in late December. The
decreases of 19% in 1993 and 13% in 1994 were due to the significant decrease in
long term debt and the refinancing of such debt on July 1, 1994 at lower
interest rates. Interest expense increased significantly in 1992 because of the
debt incurred to acquire the West Delta properties being in place a full twelve
months.
The net loss in 1995 is primarily due to $8,112,000 in unsuccessful
exploration expenses and the increase in lease operating expenses, partially
offset by a 39% decrease in interest and other expenses. The net income in 1994
is due to the drilling and rework program, the lack of a futures contract losses
and the long term debt being refinanced. The net losses in 1992 and 1993 were
primarily due to futures contract losses of $1,101,000 and $3,033,000,
respectively, which were only partially offset by increases in natural gas
prices. The net loss in 1991 is due to additional interest expense and increased
lease operating expense.
"Net income (loss) per common share" is based upon the weighted average
number of shares outstanding of 11,504,615 for 1995, 10,039,042 for 1994,
7,583,761 for 1993, 7,314,041 for 1992, and 6,399,338 for 1991.
The Company currently does not intend to pay dividends with respect to the
Common Stock but rather intends to retain and reinvest its cash flow. The Board
of Directors of the Company will reexamine the Company's dividend policy from
time to time. The terms of the Primary and Secondary Loans require Lender
consent to the payment of dividends or any purchase of Common Shares by the
Company.
Liquidity and Capital Resources
Cash flow from operations is used to reduce long term debt, drill
developmental wells and rework wells on the Company's properties.
On July 1, 1994 the Company entered into a Credit Agreement with the First
Union National Bank of North Carolina, as the agent for Lenders Signatory
thereto ("Primary Credit Facility"). Initially the only lender
24
<PAGE>
was First Union National Bank of North Carolina. The loan is a reducing revolver
designed to provide the Company up to $30 million depending upon the Company's
borrowing base. The principal amount of the loan is due July 1, 1998. However,
at no time may the Company have outstanding borrowings under the Credit
Agreement in excess of its borrowing base. Should the borrowing base ever be
determined to be less than the outstanding principal owed under the Credit
Agreement the Company must immediately pay that difference to the Lenders.
Interest on the loan is computed at the bank's prime rate or at 1 to 1 3/4%
(depending upon the percentage of the facility being used) over the applicable
Libor rate on Eurodollar loans. Eurodollar loans can be for terms of either one,
two, three or six months and interest on such loans is due at the expiration of
the terms of such loans, but no less frequently than every three months.
Management feels that this new loan arrangement greatly facilitates its ability
to make necessary capital expenditures to maintain and improve production from
its properties and makes available to the Company additional funds for future
acquisitions.
During the years 1991 through 1994 the Company's only capital commitment
was for monthly payments of $14,500 on the 1992 purchase of a natural gas
compressor, which was paid in full in December 1994. All other capital
expenditures have been committed for only after assurance that funding was
available. Cash flow from operations has always exceeded principal and interest
payments and provided funding for capital expenditures. During 1995 the cash
flow from operations was $9,300,000.
Pursuant to existing agreements the Company is required to deposit funds
in escrow accounts to assure satisfaction of its eventual responsibility to plug
and abandon wells and remove structures when certain fields no longer produce
oil and gas. Commencing in January 1996 the Company deposits $25,000 per month
into escrow, until such time as $1,500,000 has been deposited, to satisfy such
obligations with respect to Bayou Sorrel Field. Each month $25,000 is deposited,
until another $575,000 has been deposited, to satisfy such obligations with
respect to a portion of its West Delta properties. Pursuant to the Company's
agreement to acquire the offshore properties of Zapata Exploration Company, it
agreed to escrow 80% of the net income from the East Breaks Field until such
time as the Minerals Management Service of the Department of Interior, which has
jurisdiction over oil and gas operations in the Outer Continental Shelf, has
approved the transfer of East Breaks Blocks 109 and 110 to the Company, which
approval is expected during third quarter 1996.
Under a swap agreement the Company has hedged the price of natural gas by
selling the equivalent of 15,000 MMBTU per day for 1996 at fixed prices which
ranged from $2.25 for December to $1.75 for July. If the closing price
(settlement price) on NYMEX for natural gas futures is greater than the swap
price for a given month the Company must pay that difference to the bank which
effected the swap. If the settlement price is less the swap price the bank must
pay that difference to the Company. By entering into the swap in December 1995
the Company locked in the fixed prices on 15,000 MMBTU per day for each month in
1996. Because settlement prices have been above the fixed prices each month the
Company has been required to pay the difference to the bank which effected the
swap. Since the Company sells its natural gas on the spot market it realizes
prices which approximate the settlement prices on NYMEX, less differences for
transportation due to pipeline locations that are varying distances from Henry
Hub, Louisiana which is the delivery point used for natural gas futures on
NYMEX. Generally these differences are anticipatable and not significant.
However, to the extent that these difference become significant the Company may
realize more or less on its spot sales of gas than was anticipated and may be
impacted beneficially or detrimentally by erratic fluctuations in the natural
gas spot market or the futures market on NYMEX. Both such eventualities have
occurred so far this year. These erratic fluctuations which have characterized
the natural gas market in recent months have exposed the Company to market and
credit risks. In those months in which the spot price is below the settlement
price, the net amount realized by the Company on its total gas sales would be
proportionately reduced by the swap agreements. At present natural gas futures
prices on NYMEX for the remaining months of 1996 are all above the fixed prices
under the swap agreement and the Company anticipates that this will result in
its realizing less for its natural gas due to amounts required for payments to
the bank under the swap
25
<PAGE>
agreement. Management entered into the swap agreement to assure the Company of
not receiving less than the fixed prices established under the agreement for at
least 15,000 MMBTU's of gas a day during 1996. This gave the Company assurance
that it would be in a position to timely amortize its long-term debt. Long-term
debt had increased in connection with acquisitions of the Zapata offshore
properties and the Bayou Sorrel Field from Shell. Management has generally used
hedge transactions to protect its cash flows when long-term debt has been higher
and refrained from hedge transactions when long-term debt has been lower. For
accounting purposes, gain or losses on swap transactions are recognized in the
production month to which a swap contract relates. The Fair Value of these swap
transactions at December 31, 1995 was ($2,000,000), due to the high natural gas
futures market prices on that date.
Capital Spending
In 1995 the Company spent $8,112,000 on exploratory drilling which did not
result in a discovery and $1,497,000 on developmental costs. During 1994 it
recompleted eight offshore wells and drilled four offshore horizontal wells.
During that year over $11,749,000 was spent on offshore recompletions and the
drilling of horizontal wells.
All four horizontal wells and all eight recompletions in 1994 were
successful and offshore natural gas production increased significantly. During
the last part of 1993 the Company raised $1,163,000 in equity primarily by
virtue of options and warrants being exercised. During 1994 the Company raised
$5,023,000 in equity primarily as the result of such exercises of options and
warrants. Likewise most of the $3,173,000 of equity proceeds in 1995 was from
the exercise of options and warrants. As explained under "Business Funding of
Business Activities.", the Company procured a Secondary Loan at year-end 1993.
The Company utilized $5,000,000 of these funds, along with equity proceeds and
cash flow from operations described above, to drill the wells and do the
recompletions in 1994 and 1995. Another $5,000,000 is presently available under
the secondary facility. Repayment is due December 31, 1999.
Item 8. Financial Statement and Supplementary Data.
The financial statements are included herein beginning at page F-1. The
table of contents at the front of the financial statements lists the financial
statements and schedules included therein.
Item 9. Changes in and disagreements with Accountants on accounting and
Financial Disclosure.
None.
Part III
Item 10. Directors and Executive Officers of the Registrant.
The Company has a classified Board of Directors. Directors are elected to
serve for three-year terms and until their successors are elected and qualified.
One-third of the directors stand for election each year as their terms expire.
The Board of Directors consists of three employees of the Company and five
independent directors.
Officers are elected by and serve at the discretion of the Board of
Directors.
26
<PAGE>
Set forth below are the names, ages, and positions of the persons who are
executive officers and directors of the Company.
Director
Name Age Since Position
H. James Maxwell ......... 51 1992 Chairman of the Board, President,
Chief Executive Officer, and Director(a)
Bob F. Mallory ............64 1992 Chief Operating Officer, Executive Vice
President and Director(a)
Larry M. Wright ...........51 1992 Executive Vice President and
Director(b)
Robert G. Wonish ..........42 --- Vice President
William J. Doyle ..........44 --- Vice President
Todd R. Bart ..............31 --- Chief Financial Officer, Secretary and
Treasurer
A. Theodore Stautberg, Jr. 49 1993 Director(c)-Compensation Committee
Donald W. Chesser .........56 1992 Director(a)-Audit and Compensation
Committees
Allen H. Sweeney ..........49 1993 Director(c)-Audit Committee
James B. Kreamer ......... 56 1993 Director(c)
N. Lynne Sieverling .......58 1992 Director(b)-Audit and Compensation
Committees
(a) These persons are designated as Class III directors, with their term of
office expiring at the annual meeting of stockholders in 1998.
(b) These persons are designated as Class II directors, with their term of
office expiring at the annual meeting of stockholders in 1997.
(c) These persons are designated as Class I directors, with their term of
office expiring at the annual meeting of stockholders in 1996.
Set forth below are descriptions of the principal occupations, during at
least the past five years, of the directors and executive officers of the
Company.
H. James Maxwell received a B.A. degree in Economics from the University
of Missouri-Kansas City and received his Law Degree from that same University in
1972. Mr. Maxwell practiced securities law from 1972 to 1984, and was a frequent
author and speaker on oil and gas tax and securities law. He served as a General
Partner of Castle Royalty Limited Partnership from 1984 to 1988, Managing
General Partner of PAN from 1987 to 1992 and President, CEO and Chairman of the
Company from 1992 to date. He is a member of the Executive Committee.
Bob F. Mallory received his PhD in Geology from the University of Missouri
in 1968 and a B.A. in Geology from the University of Wichita in 1961. He began
consulting in the oil industry in 1980. He served as a
27
<PAGE>
General Partner of Castle Royalty Limited Partnership from 1984 to 1988, as a
General Partner of PAN from 1987 to 1992 and Executive Vice President and Chief
Operating Officer of the Company from 1992 to date.
He is a member of the Executive Committee.
Larry M. Wright received his B.S. Degree in Engineering from the
University of Oklahoma in 1966. From 1966 to 1976 he was with Union Oil Company
of California. From 1976 to 1980 he was with Texas International Petroleum
Corporation, ultimately as division operations manager. From 1980 to 1981 he was
with what is now Transamerica Natural Gas Company as Vice President-Exploration
and Production. From 1981-1982 he was Senior Vice President of Operations for
Texas International, and from 1983 to 1985 he was Executive Vice President of
Funk Fuels Corp., a subsidiary of Funk Exploration. From 1985 to 1993 Mr. Wright
was an independent consultant. From 1993 to date he has served as Executive Vice
President of the Company.
Robert G. Wonish received his B.S. in Mechanical Engineering in 1975 from
the University of Missouri-Rolla. He was a production engineer with Amoco form
1975 to 1977, Napeco, Inc. from 1977 to 1979; Division Operation Engineer with
Texas International from 1979 to 1980; Production Manager with Cliffs Drilling
Company from 1980 to 1984 and District Superintendent with Ladd Petroleum
Corporation form 1985 to 1991. He then worked as a consultant, starting with the
Company in 1992 and became an employee in 1993.
William J. Doyle received his Masters in Geology in 1975 from Texas A&M
University and his B.S. in Earth Sciences from the University of New Orleans in
1973. From 1975 to 1978 he was a geologist with Mobil Oil focusing on offshore
Gulf of Mexico projects. From 1978 to the present he has worked as an employee
and consultant for various oil and gas exploration companies operating in the
Gulf Coast.
Todd R. Bart received his B.A. in Accounting from Abilene Christian
University in 1987. He worked in the energy industry with Pennzoil Company from
1987 to 1990 and the public accounting firm of Arthur Andersen and Company from
1990 until 1992. From 1992 to 1995 he worked for Yellow Freight System, Inc., a
trucking company, in financial accounting and reporting. He joined the Company
as Controller in 1995 and was elected Chief Financial Officer, Treasurer and
Secretary in 1996. He received his C.P.A. designation in Texas in 1990 and in
Kansas in 1993, and is a member of the A.I.C.P.A.
A. Theodore Stautberg, Jr. has since 1981 been the President and a director
of Triumph Resources Corporation and its parent company, Triumph Oil and Gas
Corporation of New York. Triumph engages in the oil and gas business, assists
others in financing energy transactions, and serves as general partner of
Triumph Production L.P. Mr. Stautberg is also the president of Triumph
Securities Corporation and BT Energy Corporation. Prior to forming Triumph in
1981, Mr. Stautberg was a Vice President of Butcher & Singer, Inc., an
investment banking firm, from 1977 to 1981. From 1971 to 1977, Mr. Stautberg was
an attorney with the Securities and Exchange Commission. Mr. Stautberg is a
graduate of the University of Texas and the University of Texas School of Law.
Donald W. Chesser received his BBA in Accounting from Texas Tech
University in 1963 and has served with several CPA firms since that time,
including eight years with Elmer Fox and Company. From 1977 to 1981 he was with
IMCO Enterprises, Inc. Since 1981 he has practiced accounting in Wichita, Kansas
under the name Chesser and Company.
Allen H. Sweeney received his Masters in Finance from Oklahoma City
University in 1972 and a Bachelor Degree in Accounting from Oklahoma State
University in 1969. He served as Treasurer and CAO of Phoenix Resources Company
form 1978 to 1980, Vice President-Finance of Plains Resources, Inc. from 1980 to
1981
28
<PAGE>
and Vice President-Finance of Wildcat Mud, Inc. from 1982 to 1984. In 1984
he started an independent consulting service under the name AHS and Associates,
Inc. Since 1992 he has served as Vice President of Columbia Production Company
and Mid-America Waste Management, Inc.
James B. Kreamer received his B.S. Degree in Business from the University
of Kansas in 1963 and has been active in investment banking since that time.
Since 1982 he has managed his personal investments.
N. Lynne Sieverling received his B.S. Degree in Accounting from the
University of Kansas in 1959 and has practiced as a CPA since graduation,
serving 17 years as a partner with the accounting firm of Coopers & Lybrand. Mr.
Sieverling has been actively involved in the oil and gas industry for the past
ten years both as an investor and as an operator of oil and gas leases in
Kansas, Oklahoma and North Dakota. He is a member of the Kansas Division of the
Interstate Oil Compact Commission.
None of the officers or directors serve pursuant to employment agreements.
Long-term Incentive Plan. The Company's Long-term Incentive Plan (the
"Long-term Incentive Plan"), provides for the granting to certain officers and
key employees of the Company and its participating subsidiaries incentive awards
in the form of stock options, stock appreciation rights ("SARs"), stock, and
cash awards. The Long-term Incentive Plan is administered by a committee of
independent members of the Board of Directors with respect to awards to certain
executive officers of the Company but may be administered by the Board of
Directors with respect to any other awards (either, the "Plan Committee").
Except for certain automatic awards, the Plan Committee has discretion to select
the employees to be granted awards, to determine the type, size, and terms of
the awards, to determine when awards will be granted, and to prescribe the form
of the instruments evidencing awards.
Options, which include nonqualified stock options and incentive stock
options, are rights to purchase a specified number of shares of Common Stock at
a price fixed at the time the option is granted. Payment may be made with cash
or other shares of Common Stock owned by the optionee or a combination of both.
Options are exercisable at the time and on the terms that the Plan Committee
determines. The payment of the option price can be made either in cash or by the
person exercising the option turning in to the Company shares presently owned by
him, which would be valued at the then current market price. SARs are rights to
receive a payment, in cash or shares of Common Stock or both, based on the value
of the Common Stock. A stock award is an award of shares of Common Stock or
denominated in shares of Common Stock that may be subject to a restriction
against transfer as well as a repurchase option exercisable by the Company.
During the period of the restriction, the employee may be given the right to
vote and receive dividends on the shares covered by restricted stock awards.
Cash awards are generally based on the extent to which pre-established
performance goals are achieved over a pre-established period but may also
include individual bonuses paid for previous, exemplary performance. It is
currently expected that the Plan Committee will determine performance objectives
and award levels before the beginning of each plan year.
The Long-term Incentive Plan provides for the issuance of a maximum number
of shares of Common Stock equal to 20% of the total number of shares of Common
Stock outstanding from time to time. Unexercised SARs, unexercised options,
restricted stock, and performance units under the Long-term Incentive Plan are
subject to adjustment in the event of a stock dividend, stock split,
recapitalization or combination of the Company, merger, or similar transaction
and are not transferable except by will and by the laws of descent and
distribution. Except when a participant's employment terminates as a result of
death, disability, or retirement under an approved retirement plan or following
a change in control in certain circumstances, an award generally may be
exercised (or the restriction thereon may lapse) only if the participant is an
officer, employee, or director of the Company or a subsidiary at the time of
exercise or lapse
29
<PAGE>
or, in certain circumstance, if the exercise or lapse occurs within 180 days
after employment is terminated.
The Long-term Incentive Plan allows for the satisfaction of a
participant's tax withholding with respect to an award by the withholding of
shares of Common Stock issuable pursuant to the award or the delivery by the
participant of previously owned shares of Common Stock, in either case valued at
the fair market value, subject to limitations the Plan Committee may adopt.
Awards granted pursuant to the Long-term Incentive Plan may provide that,
upon a change of control of the Company, (a) each holder of an option will be
granted a corresponding SAR, (b) all outstanding SARs and stock options become
immediately and fully vested and exercisable in full, and (c) the restriction
period on any restricted stock award shall be accelerated and the restriction
shall expire. Options and SARs will remain exercisable for their original terms
whether or not employment is terminated following a change in control.
The Long-term Incentive Plan may be amended by the Board of Directors,
except that under current law no amendment that materially increases the number
of shares of Common Stock subject to the Long-term Incentive Plan or that makes
certain other material changes may be made without stockholder approval. No
grants or awards may be made under the Long-term Incentive Plan after the tenth
anniversary of the Closing Date. No stockholder approval will be sought for
amendments to the Long-term Incentive Plan except as required by law (including
Rule 16b-3 under the Exchange Act) or the rules of any national securities
exchange on which the Common Stock is then listed.
There were no incentive awards under the Long-term Incentive Plan
outstanding at December 31, 1995.
Under the Company's Long-Term Incentive Plan beginning in 1996, all
employees share a bonus equal to 5% of the Company's pre-tax net income,
computed in accordance with GAAP, exclusive of extraordinary and non-recurring
items. The bonuses will be paid to all full time (1,000 + hours) employees at
December 31. The bonus will be paid upon delivery of the independent audit. The
bonus shall be allocated to the full time employees based upon their salary at
December 31.
Each non-employee director of the Company who becomes a director will, on
the day after the first meeting of the Board of Directors at which that director
is in attendance, automatically be granted a restricted stock award of the
number of shares of Company Common Stock that have a value of $10,000, which
will be calculated based on the average trading price of the Common Stock during
the 60 days immediately preceding the date of grant. These restricted stock
awards will vest at the rate of one-third annually, with one-third vesting six
months following the date of grant, another one-third vesting on the first
anniversary of the date of grant, and the last one-third vesting on the second
anniversary of the date of grant so long as the non-employee director remains a
director of the Company through those vesting dates.
Each non-employee director will be entitled to vote each share subject to
these restricted stock awards from the date of grant until the shares are
forfeited, if ever. The Long-term Incentive Plan requires each non-employee
director to make an election under Section 83(b) of the Code to include the
value of the restricted stock in his income in the year of grant and provides
for cash awards to the non-employee directors in amounts sufficient to pay the
federal income taxes due with respect to the award.
30
<PAGE>
The following table shows information with respect to restricted stock
awards owned by non-employee directors.
Name Date of Grant Shares Price
James B. Kreamer July 12, 1993 4,098 2.44
A. Theodore Stautberg July 12, 1993 4,098 2.44
Allen H. Sweeney July 12, 1993 4,098 2.44
Total 12,294
Employee Stock Ownership Plan. In 1994 the Shareholders approved the
adoption of the Panaco, Inc. Employee Stock Ownership Plan ("ESOP"). The primary
purposes of the ESOP are to enable participants to acquire stock ownership in
the Company and to provide a source of equity capital to the Company. The ESOP
provides for the establishment of a trust to hold ESOP assets which will
primarily consist of common shares of the Company. The ESOP will be administered
by a committee of the Board of Directors. Subject to the discretion of the Board
of Directors, the Company may contribute up to fifteen percent (15%) of the
participant's (including employees and other consultants to the Company) annual
compensation to the ESOP.
The ESOP does not allow contributions by participants in the Plan.
Company contributions to the ESOP may be in the form of common shares or
cash. Cash contributions may be used, at the discretion of the Board of
Directors, to purchase common shares in the open market or from the Company at
prevailing prices.
The allocation of ESOP assets is determined by a formula based on
participant compensation. Participation in the ESOP requires completion of more
than one thousand (1,000) hours of service to the Company within twelve (12)
consecutive months.
The ESOP is intended to satisfy any applicable requirements of the
Internal Revenue Code of 1986 and the Employee Retirement and Income Security
Act of 1974. The Company has been advised that its contributions to the ESOP
will be deductible for Federal Income Tax purposes, and the participants will
not recognize income on their allocated share of ESOP assets until such assets
are distributed.
31
<PAGE>
Item 11. Executive Compensation.
The following table sets forth the annual compensation paid to the
Company's Chief Executive Officer and each executive officer whose compensation
exceeds $100,000 during 1995.
<TABLE>
Summary Compensation Table
<CAPTION>
Long-Term Incentive Plan
Annual Compensation Awards Payouts
Securities
Other Restricted Underlying LTIP All
Name & Principal Salary Bonus Annual Stock Options Payouts Other
Position Year ($)(1) ($) Comp. ($) Award(s) ($) (#) ($) Comp.($)(2)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
H. James Maxwell 1995 153,500 0 0 0 24,615 0 22,500
President and Chief 1994 120,000 0 0 0 22,857 0 18,000
Executive Officer 1993 80,000 0 0 0 115,000 0 0
Larry M. Wright 1995 147,300 0 0 0 0 0 22,100
Executive Vice 1994 134,000 0 0 0 0 0 20,000
President 1993 120,000 0 0 0 0 0 0
Robert G. Wonish 1995 92,100 0 0 0 0 0 13,800
Vice President 1994 78,800 0 0 0 0 0 11,800
1993 77,000 0 0 0 0 0 0
(1) The 1993 salary figures for Messrs. Wright and Wonish include payments
made to them as independent consultants before becoming employees of
the Company in that year.
(2) The other compensation figures for 1995 and 1994 represent
contributions to the accounts of the employees under the Company's
Employee Stock Ownership Plan. The Plan was adopted in 1994.
</TABLE>
The following table provides information relating to the number and
value of Common Shares subject to options exercised during 1995 or held by the
named executive officers as of December 31, 1995.
<TABLE>
Aggregated Option Exercises in Last Fiscal Year
and Fiscal Year End Option Values
Number of
<CAPTION>
securities underlying Value of unexercised
Securities unexercised options in-the-money
acquired Value at fiscal year-end ($) options at year-end($)(2)
Name on Exercise (#) Realized ($)(1) Exercisable/unexercisable Exercisable/Unexercisable
<S> <C> <C> <C> <C> <C> <C>
H. James Maxwell 250,972 410,129 -0-/-0- -0-/-0-
Larry M. Wright 0 0 250,000/-0- 549,375/-0-
Robert G. Wonish 0 0 -0-/-0- -0-/-0-
(1) Value realized is calculated based upon the difference between the options
exercise price and the market price of the Company's Common Stock on the
date of exercise multiplied by the number of shares to which the exercise
price relates.
(2) Value of unexercised in-the-money options is calculated based on the
difference between the option exercise price and the closing price of the
Company's Common Stock at year-end, multiplied by the number of shares
underlying the options. The closing price on December 29, 1995 of the
Company's Common Stock was $4.4375.
</TABLE>
32
<PAGE>
The following table identifies the grants of stock options made to the
named executive officers in 1995.
<TABLE>
Option Grants in Last Fiscal Year
<CAPTION>
Number of Percent of
Securities total options
Underlying granted to Exercise or Market price
Options employees Base price at date Expiration Grant Date
Name Granted in fiscal year ($/Share) of grant($) Date Value($)
<S> <C> <C> <C> <C> <C> <C> <C>
H. James Maxwell 24,615(1) 33% 2.03125 4.0625 12/31/95 50,000
Larry M. Wright -0- -0- N/A N/A N/A N/A
Robert G. Wonish -0- -0- N/A N/A N/A N/A
</TABLE>
(1) Mr. Maxwell's options were exercised in 1995.
Cash Compensation of Directors. Directors receive travel expenses incurred
in attending Board of Directors or committee meetings. Officers of the Company
who serve as directors do not receive special compensation for serving on the
Board of Directors or a committee thereof. However, Messrs. Stautberg, Chesser,
Sweeney, Kreamer and Sieverling, the five non-employee directors, were each
issued 1,039 shares of Common Stock as a $5,000 bonus during 1995. In addition
Mr. Chesser was issued warrants to acquire 25,000 Common Shares at $2.50 per
share, which expired December 31, 1995, for services performed for the Company
in 1991. See "Certain Relationships and Related Transactions," herein.
Newly elected non-employee directors are granted a one time restricted
stock award in Common Shares equal in value to $10,000 upon their being elected
to the Board. See "Management - Long-Term Incentive Plan," herein.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth information with respect to beneficial
ownership of Company Common Stock by (a) each officer and director of the
Company, (b) all officers and directors of the Company as a group, and (c) for
each person who beneficially owns 5% or more of the Common Stock as of May 1,
1996.
<TABLE>
Name and Positions of Beneficial Owners Shares Owned Beneficially
<CAPTION>
Number Percent
<S> <C> <C> <C> <C> <C> <C>
H. James Maxwell, Chief Executive Officer,
President, Chairman of the Board & Director ...............................322,971 2.56
Larry M. Wright, Executive Vice President &
Director ...................................................................654,999 (1)5.18
Bob F. Mallory, Chief Operating Officer,
Executive Vice President & Director ........................................233,030 1.84
Robert G. Wonish, Vice President ............................................... 18,328 0.15
William J. Doyle, Vice President ............................................... 4,405 0.04
Todd R. Bart, Chief Financial Officer, Secretary, Treasurer .................... -0- 0.00
A. Theodore Stautberg, Director ................................................ 6,137 0.05
Donald W. Chesser, Director .................................................... 1,039 0.01
Allen H. Sweeney, Director .....................................................150,137 (2) 1.19
James B. Kreamer, Director ..................................................... 51,055 0.40
N. Lynne Sieverling, Director .................................................. 8,137 0.06
All directors and officers as a group (11 persons) ............................1,450,238 11.48
33
<PAGE>
Carl C. Icahn ................................................................1,040,000 (3)8.23
% Icahn Associates Corp.
114 West 47th Street, 19th Fl
New York, NY 10036
Richard A. Kayne ...............................................................694,047 (4)5.49
% Kayne Anderson Investment Management, Inc.
1800 Avenue of the Stars, #1425
Los Angeles, CA 90067
</TABLE>
(1) Includes 250,000 shares issuable pursuant to currently exercisable
warrants which, pursuant to Board resolution extending the date, expire thirty
days after the date of the Company's Form S-1/A Post Effective Amendment No. 8.
(2) Mr. Sweeney's shares are held by AHS and Associates, Inc., a
corporation of which he is President and a director.
(3) Mr. Icahn is the sole stockholder of Riverdale Investors Corp, Inc.,
the general partner of High River Limited Partnership, the record holder of
these shares.
(4) Mr. Kayne has sole voting power with respect to investments of Kayne,
Anderson Investment Management, Inc., which is the general partner of KAIN
Non-Traditional, L.P., which is the general partner of: Offense Group Associates
Limited; Opportunity Associates, L.P.; ARBCO Associates, L.P.; and Kayne,
Anderson Non-Traditional Investments, L.P.; the record holders of these shares.
Item 13. Certain Relationships and Related Transactions.
During 1995 each of the five directors who are not employees of the Company
were issued a stock bonus of $5,000, paid by the issuance of 1,039 shares of
Common Stock.
During 1995 Donald W. Chesser, a director who is not an employee of the
Company was issued warrants to acquire 25,000 shares of Common Stock at $2.50
per share for past services to the Company. The warrants, which would have
expired December 31, 1995, were all exercised during 1995.
Employees of the Company are eligible to receive stock awards, stock
options, stock appreciation rights, and performance units pursuant to the
Company's Long-term Incentive Plan.
The Company has several procedures, provisions, and plans designed to
reduce the likelihood of a change in the management or voting control of the
Company without the consent of the incumbent Board of Directors. These
provisions may have the effect of strengthening the ability of officers and
directors of the Company to continue as officers and directors of the Company
despite changes in stock ownership of the Company.
Under the terms of the Company's Long Term Incentive Plan, three of the
officers and directors surrendered shares of Common Stock in January 1995 in
exercise of outstanding options during 1995. The following table sets forth the
number of shares surrendered and market value thereof and the number of options
exercised and the aggregate exercise price thereof.
34
<PAGE>
Shares Market Options Aggregate
Surrendered (1) Value ($) Exercised Price ($) (2)
H. James Maxwell 24,615 99,998 43,100 100,245
Bob F. Mallory 24,615 99,998 42,400 100,018
Thomas E. Clark 24,615 99,820 38,900 100,137
(1) Persons surrendering shares in payment of the exercise price of an option
were granted new options for a like number of shares at $2.03125 expiring
December 31, 1995.
(2) Differences between the value of the share surrendered and the exercise
prices were paid in cash by the person exercising the option.
Messrs. Maxwell and Mallory are the partners of 1050 Blue Ridge Building
Partnership that owns a 5,200 square foot office building at 1050 West Blue
Ridge Boulevard, Kansas City, Missouri, which they lease to the Company on a
triple net basis for $4,000 per month for a term of ten years, expiring in 2003.
The lease was approved by the Board of Directors, which determined that the rate
was as good or better than that which could be obtained from a non-affiliated
party.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) See Index to Financial Statement, Page F-1.
(b) Reports on Form 8-K. No reports on Form 8-K have been filed during the
last quarter of the period covered by this report.
(c) Exhibits: None.
(d) Financial Statement Schedules. See Index to Financial Statements, Page
F-1.
35
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13, or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PANACO, Inc.
By: \s\ H. James Maxwell
H. James Maxwell, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
By: \s\ H. James Maxwell
H. James Maxwell, President,
Chief Executive Officer and
Director
By: \s\ Bob F. Mallory
Bob F. Mallory, Executive
Vice President, Chief Operating
Officer and Director
By: \s\ Todd R. Bart
Todd R. Bart, Chief Financial
Officer, Treasurer and Secretary
By: \s\ N. Lynn Sieverling
N. Lynn Sieverling, Director
By: \s\ Larry M. Wright
Larry M. Wright, Executive
Vice President and Director
By: \s\ A. Theodore Stautberg
A. Theodore Stautberg, Director
36
<PAGE>
PANACO, INC.
INDEX TO FINANCIAL STATEMENTS
<TABLE>
AUDITED FINANCIAL STATEMENTS - PANACO, INC. Page
<CAPTION>
<S> <C>
Independent Auditors' Report F-2
Balance Sheets, December 31, 1995 and 1994 F-3, F-4
Statements of Income (Operations) for the Years Ended
December 31, 1995, 1994 and 1993 F-5
Statements of Changes in Stockholders' Equity and Retained Earnings (Deficit)
for the Years Ended December 31, 1995, 1994 and 1993 F-6
Statements of Cash Flows for the Years Ended
December 31, 1995, 1994 and 1993 F-7, F-8
Notes to Financial Statements for the Years Ended
December 31, 1995, 1994 and 1993 F-9 - F22
SCHEDULES OMITTED:
Schedules other than those listed above are omitted because they are not
required, are not applicable or the required information is shown in the
financial statements or in the related notes.
AUDITED SCHEDULES OF REVENUES, SELECTED DIRECT OPERATING EXPENSES
AND PRODUCTION TAXES - ZAPATA PROPERTIES AND BAYOU SORREL FIELD F-23-F27
Independent Auditors' Report F-23
Schedules of Revenues, Selected Direct Operating Expenses and Production Taxes
for the Years Ended December 31, 1994 and 1993 F-24
Notes to the Schedules of Revenues, Selected Directed Expenses and Production
Taxes for the Years Ended December 31, 1994 and 1993 F-25-F27
</TABLE>
<PAGE>
Independent Auditors' Report
To the Board of Directors
Panaco, Inc.
We have audited the accompanying balance sheets of Panaco, Inc. (a Delaware
corporation) as of December 31, 1995 and 1994, and the related statements of
income (operations), changes in stockholders' equity and cash flows for each of
the three years in the period ended December 31, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial Statements, the Company has given
retroactive effect to the change in accounting for its oil and gas operations.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Panaco, Inc. as of December 31,
1995 and 1994, and the results of its operations, changes in stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1995 in conformity with generally accepted accounting principles.
BARRETT & ASSOCIATES
Overland Park, Kansas
February 26, 1996, except for Note 1, which the date is June 7, 1996.
F-2
<PAGE>
<TABLE>
PANACO, INC.
BALANCE SHEETS
(AS RESTATED)
<CAPTION>
ASSETS
December 31,
1995 1994
CURRENT ASSETS:
<S> <C> <C>
Cash and cash equivalents $ 1,198,000 $ 1,583,000
Accounts receivable
Trade 3,294,000 2,230,000
Other 1,092,000 1,000
Prepaid expenses 465,000 272,000
------- -------
Total current assets 6,049,000 4,086,000
OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
Oil and gas properties 103,105,000 89,010,000
Less accumulated depreciation, depletion, amortization,
and valuation allowances (73,620,000) (65,065,000)
----------- -----------
Net oil and gas properties 29,485,000 23,945,000
PROPERTY, PLANT, AND EQUIPMENT
Equipment 196,000 158,000
Less accumulated depreciation (92,000) (68,000)
------- -------
Net property, plant, and equipment 104,000 90,000
OTHER ASSETS:
Loan costs, net 471,000 714,000
Certificates of deposit - escrow 26,000 47,000
Other 5,000 6,000
Accounts receivable - other 8,000 186,000
Note receivable 21,000 21,000
------ ------
Total other assets 531,000 974,000
TOTAL ASSETS $ 36,169,000 $29,095,000
============ ===========
</TABLE>
The accompanying notes to financial statements are an integral
part of this statement.
F-3
<PAGE>
<TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
(AS RESTATED)
<CAPTION>
December 31,
1995 1994
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable $ 4,444,000 $ 1,528,000
Interest payable 161,000 185,000
Current portion of long-term debt -0- -0-
---------- ---------
Total current liabilities 4,605,000 1,713,000
LONG-TERM DEBT 22,390,000 12,500,000
STOCKHOLDERS' EQUITY
Preferred stock, $.01 par value,
1,000,000 shares authorized; no
shares issued and outstanding -0- -0-
Common stock, $.01 par value,
20,000,000 shares authorized;
11,504,615 and 10,220,138 shares
issued and outstanding, respectively 115,000 102,000
Additional paid in capital 21,155,000 17,586,000
Retained earnings (deficit) (12,096,000) (2,806,000)
----------- ----------
Total stockholders' equity 9,174,000 14,882,000
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 36,169,000 $ 29,095,000
============ ============
</TABLE>
The accompanying notes to financial statements are an integral
part of this statement.
F-4
<PAGE>
<TABLE>
PANACO, INC.
STATEMENTS OF INCOME (OPERATIONS)
(AS RESTATED)
<CAPTION>
Year Ended December 31,
1995 1994 1993
REVENUES
<S> <C> <C> <C>
Oil and gas sales $18,447,000 $17,367,000 $ 15,638,000
Future contracts -0- (29,000) (3,033,000)
----------- ------- ----------
Total 18,447,000 17,338,000 12,605,000
COSTS AND EXPENSES
Lease operating 8,055,000 5,231,000 5,297,000
Depreciation, depletion and amortization 8,064,000 6,038,000 4,288,000
General and administrative 690,000 587,000 542,000
Production and ad valorem taxes 1,078,000 1,006,000 754,000
Exploration expenses 8,112,000 -0- -0-
Provision for losses and (gains) on disposition
and write-down of assets 751,000 1,202,000 3,824,000
----------- --------- ---------
Total 26,750,000 14,064,000 14,705,000
NET OPERATING INCOME (LOSS) (8,303,000) 3,274,000 (2,100,000)
OTHER INCOME (EXPENSE)
Interest income 5,000 46,000 27,000
Interest expense (992,000) (1,669,000) (1,913,000)
Total (987,000) (1,623,000) (1,886,000)
NET INCOME (LOSS) BEFORE INCOME
TAXES AND EXTRAORDINARY ITEM (9,290,000) 1,651,000 (3,986,000)
INCOME TAXES (BENEFIT) -0- -0- -0-
NET INCOME (LOSS) BEFORE
EXTRAORDINARY ITEM (9,290,000) 1,651,000 (3,986,000)
EXTRAORDINARY ITEM - LOSS ON EARLY
RETIREMENT OF DEBT -0- (536,000) -0-
NET INCOME (LOSS) $ (9,290,000) $ 1,115,000 $ (3,986,000)
EARNINGS (LOSS) PER COMMON SHARE
Primary:
Earnings (loss) before extraordinary item $ (.81) $ .16 $ (.53)
Extraordinary loss -0- (.05) -0-
Net earnings (loss) $ (.81) $ .11 $ (.53)
Assuming full dilution:
Earnings (loss) before extraordinary item $ (.81) $ .16 $ (.53)
Extraordinary loss -0- (.05) -0-
Net earnings (loss) $ (.81) $ .11 $ (.53)
Weighted average shares outstanding:
Primary 11,504,615 9,952,870 7,583,761
Assuming full dilution 11,504,615 10,039,042 7,583,761
</TABLE>
The accompanying notes to financial statements are an integral
part of this statement.
F-5
<PAGE>
<TABLE>
PANACO, INC.
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
AND RETAINED EARNINGS (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
(AS RESTATED)
<CAPTION>
Common Additional Retained
Stock Paid-In Earnings
Shares Par Value Capital (Deficit)
<S> <C> <C> <C> <C> <C> <C>
Balances, December 31, 1992 7,534,496 $ 75,000 $ 11,298,000 $ 65,000
Net loss -0- -0- -0- (3,986,000)
Exercises of stock options and warrants 620,759 7,000 1,285,000 -0-
------- ----- --------- -
Balances, December 31, 1993 8,155,255 $ 82,000 $12,583,000 $(3,921,000)
Net income -0- -0- -0- 1,115,000
Exercises of stock options and warrants and
stock issued under Employee Stock
Ownership Plan 2,064,883 20,000 5,003,000 -0-
--------- ------ --------- -
Balances, December 31, 1994 10,220,138 $102,000 $17,586,000 $(2,806,000)
Net Loss -0- -0- -0- (9,290,000)
Exercise of stock options and warrants 1,181,602 12,000 3,137,000 -0-
Issuance of new stock 102,875 1,000 432,000 -0-
------- ----- ------- -
Balances, December 31, 1995 11,504,615 $ 115,000 $21,155,000 $(12,096,000)
=== ==== ========== ========= =========== ============
</TABLE>
The accompanying notes to financial statements are an integral
part of this statement.
F-6
<PAGE>
<TABLE>
PANACO, INC.
STATEMENTS OF CASH FLOWS
(AS RESTATED)
<CAPTION>
Year Ended December 31,
1995 1994 1993
CASH FLOWS FROM OPERATING ACTIVITIES:
<S> <C> <C> <C>
Net income (loss) before extraordinary item $(9,290,000) $1,651,000 $ (3,986,000)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion, and amortization 8,065,000 6,038,000 4,288,000
Amortization of loan discount -0- 340,000 512,000
Exploration expenses 8,112,000 -0- -0-
Provision for losses and (gains) on disposition
and write-down of assets 751,000 1,202,000 3,824,000
Changes in operating assets and liabilities:
Accounts receivable (2,155,000) (1,202,000) 1,261,000
Prepaid expenses (193,000) (113,000) (20,000)
Other assets 200,000 (388,000) (11,000)
Accounts payable 2,916,000 (79,000) (896,000)
Interest payable (24,000) 26,000 (40,000)
Extraordinary loss -0- (536,000) -0-
---------- -------- -
Net cash provided by operating activities 8,382,000 6,939,000 4,932,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Sale of oil and gas properties 11,000 300,000 41,000
Capital expenditures and acquisitions (21,803,000) (12,101,000) (790,000)
Purchase of other property and equipment (38,000) (37,000) (52,000)
Sale of other property and equipment -0- 10,000 -0-
Purchase of certificate of deposit -0- -0- (26,000)
------------ - -------
Net cash used by investing activities (21,830,000) (11,828,000) (827,000)
CASH FLOW FROM FINANCING ACTIVITIES:
Long-term debt proceeds 16,890,000 5,564,000 -0-
Repayment of long-term debt (7,000,000) (7,326,000) (3,535,000)
Issuance of common stock - exercise of
warrants & options 3,173,000 5,023,000 1,163,000
--------- --------- ---------
Net cash provided (used) by financing activities 13,063,000 3,261,000 (2,372,000)
NET INCREASE (DECREASE) IN CASH (385,000) (1,628,000) 1,733,000
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 1,583,000 3,211,000 1,478,000
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 1,198,000 $ 1,583,000 $ 3,211,000
</TABLE>
The accompanying notes to financial statements are an integral
part of this statement.
F-7
<PAGE>
Supplemental schedule of non-cash investing and financing activities:
FOR THE YEAR ENDED DECEMBER 31, 1995:
The Company issued 97,680 shares of common stock totaling $409,000 in exchange
for oil and gas properties.
FOR THE YEAR ENDED DECEMBER 31, 1994:
The Company farmed out an oil & gas property and retained a 12.5% overriding
royalty interest. The Company contributed 30,850 shares to the ESOP.
FOR THE YEAR ENDED DECEMBER 31, 1993:
The Company issued 36,363 shares in payment of a finders fee on new financing.
The Company received oil and gas properties in exchange for $8,000 in accounts
receivable and 1,200 shares of stock.
The Company awarded 12,294 shares to three new directors.
Supplemental disclosures of cash flow information:
Cash paid during the year ended December 31:
1995 1994 1993
Interest $ 1,016,000 $ 1,409,000 $ 1,441,000
Income taxes $ - $ - $ -
The accompanying notes to financial statements are an integral
part of this statement.
F-8
<PAGE>
PANACO, INC.
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994, AND 1993
(As Restated)
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This summary of significant accounting policies of Panaco, Inc. (the Company) is
presented to assist in understanding the Company's financial statements. The
financial statements and notes are representations of the Company's management,
who are responsible for the integrity and objectivity of the financial
statements. These accounting policies conform to generally accepted accounting
principles and have been consistently applied in the preparation of the
financial statements.
Revenue Recognition
The Company recognizes its ownership interest in oil and gas sales as revenue.
It records revenues on an accrual basis, estimating volumes and prices for any
months for which actual information is not available. If actual production sold
differs from its allocable share of production in a given period, such
differences would be recognized as deferred or accounts receivable.
Hedging Transactions
The Company engages in natural gas futures contracts within the normal course of
its business. The Company uses futures and floor contracts to reduce the effects
of fluctuations in natural gas prices. Changes in the market value of these
contracts are deferred and subsequent gains and losses are recognized monthly in
the same period as the hedged item based on the difference between the First
Nearby Contract for Natural Gas - NYMEX and the contract price. The Company
entered into a hedge agreement beginning in January, 1996, for the delivery of
15,000 MMBTU of gas for each day in 1996 with contract prices ranging from
$1.7511/MMBTU to $2.253/MMBTU. Prior to this agreement, the Company had entered
into a floor contract that expired December, 1994, and a hedge contract which
expired September, 1993.
Income Taxes
In 1993, the Company adopted Statement of Financial Accounting Standards (FAS)
No. 109 - "Accounting for Income Taxes", which requires recognition of deferred
tax assets and liabilities for the expected future tax consequences of events
that have been included in the financial statements or tax returns. Under this
method, deferred tax assets and liabilities are determined based on the
differences between the financial statement and tax bases of assets and
liabilities using enacted tax rates in effect for the year in which the
differences are expected to reverse. Generally, FAS 109 allows for at least the
partial recognition of deferred tax assets in the current period for the future
benefit of net operating loss carryforwards.
Income (Loss) per share
The computation of earnings or loss per share in each year is based on the
weighted average number of common shares outstanding. When dilutive, stock
options and warrants are included as share equivalents using the treasury stock
method. Stock options and warrants were not included in the calculation for 1993
and 1995, as the effects were not dilutive. Shares to be contributed to the ESOP
plan are treated as common stock equivalents.
Property, Plant & Equipment
Other property and equipment is recorded at cost. Depreciation is provided using
the straight-line method based on estimated useful lives which range from 5 to 7
years.
F-9
<PAGE>
Oil and Gas Producing Activities and Depreciation, Depletion and Amortization
Effective December 31, 1995, Panaco changed its method of accounting for oil and
gas operations from the full cost method to the successful efforts method.
Management concluded that the successful efforts method will more appropriately
reflect Panaco's oil and gas operations and will enable investors and others to
better compare Panaco to similar oil and gas companies, the majority of which
follow the successful efforts method. All prior period financial statements have
been restated to reflect the change.
Under the successful efforts method, lease acquisition costs are capitalized.
Exploratory drilling costs are also capitalized pending determination of proved
reserves. If proved reserves are not discovered, the exploratory costs are
expensed. All development costs are capitalized. Provision for depreciation and
depletion is determined on a field-by-field basis using the unit-of-production
method. The carrying amounts of proven and unproven properties are reviewed
periodically on a property-by-property basis, based on future net cash flows
determined by an independent engineering firm, and an impairment reserve is
provided as conditions warrant. The provision for write down of assets was
$751,000 for 1995, $1,202,000 for 1994, and $3,824,000 for 1993.
The change in the Company's accounting method increased 1995 net income by
$2,054,000 or $0.18 per share from previously reported results under the full
cost method. The change decreased 1994 and 1993 net income by $1,298,000, or
$0.13 per share and $3,800,000, or $0.51 per share, respectively, from
previously reported results under the full cost method. As of December 31, 1995,
retained earnings was decreased by $2,797,000 as a result of the accounting
change and additional paid in capital was reduced by $1,264,000.
Amortization of Note Discount
The note discount was being amortized utilizing the interest method, which
applies a constant rate of interest to the book value of the note. Additional
interest expense of $0, $234,000, and $512,000, was recorded in 1995, 1994 and
1993, respectively, from the amortization of the discount. Effective July 1,
1994 the debt related to the note discount was extinguished, and the balance of
the note discount totaling $106,000 was recorded as an extraordinary item.
Statement of Cash Flows
For purposes of reporting cash flows, the Company considers all cash investments
with maturities of three months or less to be cash equivalents.
Use of Estimates
Management relies on the use of estimates for oil and gas reserve information
and the valuation allowance for deferred income taxes in preparing financial
statements in accordance with generally accepted accounting principles.
Estimates related to oil and gas reserve information and the standardized
measure are based on estimates provided by third parties. Changes in prices
could significantly affect these estimates from year to year.
Reclassification
Certain financial statement items have been reclassified to conform to the
current year's presentation.
F-10
<PAGE>
Note 2 - LOAN COSTS
Loan costs in the amount of $602,000 and $255,000 are being amortized over the
lives of the loans, three years and six years, respectively. Additional loan
costs of $402,000 were incurred during 1994.
Note 3 - MAJOR CUSTOMERS
One purchaser accounted for 69% and 83% of revenues in 1995 and 1994,
respectively, and two purchasers accounted for 65% and 17% of revenues in 1993.
Note 4 - CERTIFICATE OF DEPOSITS - ESCROW
The Company has CD's to satisfy plugging obligations with certain government
entities.
Note 5- LONG-TERM DEBT
1995 1994
Note payable (a) $ 5,000,000 $ 5,000,000
Note payable (b) 17,390,000 7,500,000
22,390,000 12,500,000
Less current portion - -
Long-term debt $ 22,390,000 $ 12,500,000
(a) Note payable dated December 31, 1993 due to a group of six lenders in
the amount of $5,000,000 bearing interest at 12%. The lenders at their
discretion can loan an additional $5,000,000 to the Company. Payments for
interest only are required quarterly. The Company may deliver up to $1,000,000
in PIK (payment in kind) notes, bearing interest at 12%, in satisfaction of all
or part of any interest payment. The loan agreement limited the use of the first
$5,000,000 to capital expenditures and the next $5,000,000 (assuming the lenders
approve additional borrowings) to acquisitions. The loan agreement contains
certain financial covenants including future indebtedness and payment of
dividends. The note matures on December 31, 1999 and is collateralized by a
second mortgage on a substantial portion of offshore oil and gas properties,
production proceeds and receivables. The lenders were issued 816,526 warrants,
at an exercise price of $2.25, expiring December 31, 1998 in connection with the
financing (see Note 8).
(b) Reducing Revolving Line of Credit dated July 1, 1994 with a maximum
debt incurred equal to the lesser of thirty million dollars or the Borrowing
Base ($21,000,000 at December 31, 1995). The Borrowing Base reduces on a monthly
basis at a rate of $500,000 and is reviewed on a semi-annual basis as of June 30
and December 31. The note is due July 1, 1998 and bears interest at either prime
or Libor plus 1.0% to 1.75% depending on the percentage of the borrowing base
used (8% and 7.625% at December 31, 1995, respectively). At December 31, 1995,
the Company had $3,025,000 borrowed at 7.625%, $10,500,000 borrowed at 7.5625%,
and $3,865,000 borrowed at 7.6875%. Interest is due on the last day of the month
for prime notes and is due on the last day of the interest period or every three
months on Libor notes. A commitment fee of .375% to .5% of the average unused
portion of the Borrowing Base is due on a quarterly basis. The revolving line of
credit is collateralized by a substantial portion of the oil and gas properties,
receivables, inventory and general intangibles. The loan agreement contains
certain covenants including maintaining a positive indebtedness to cash flow
ratio, a positive working capital ratio, a certain tangible net worth,
limitations on future debt, guarantees, liens, dividends, mergers, material
change in ownership by management, and sale of assets. In addition, the Lender
has issued the Company a letter of credit for $3,000,000 to collateralize a
plugging bond which reduces the available Borrowing Base.
Maturities of long-term debt are as follows:
December 31, 1997 $17,390,000
F-11
<PAGE>
December 31, 1999 $ 5,000,000
$22,390,000
Note 6 - STOCKHOLDERS' EQUITY
During 1995, 1,181,602 shares were issued related to the exercise of warrants
and options, 97,680 shares were issued related to property acquisition costs and
5,195 shares were issued for board of directors fees.
During 1994, 2,034,033 shares were issued related to the exercise of warrants
and options, and 30,850 shares were issued related to the Company's ESOP.
During 1993, 12,294 shares were awarded to three new directors, 1,200 shares
were issued in exchange for oil and gas properties, 36,363 shares were issued
for payment of a finders fee on new financing (see Note 5) and 575,000 shares
were issued related to the exercise of warrants and options.
During 1993, 4,098 shares were relinquished to the Company under the terms of
the long-term incentive plan by a director upon his resignation. These shares
were reissued in the above transactions during 1993.
Shares outstanding are as follows:
Year Ending December 31,
Common Preferred
Stock Stock
1993 8,155,255 -
1994 10,220,138 -
1995 11,504,615 -
Note 7- WARRANTS
Warrants outstanding at December 31, 1995, to acquire common stock are as
follows:
Number of Price per
Shares Share Expiration Date
160,000 $2.375 June 1, 1996
90,000 $2.00 June 1, 1996
39,365 $2.00 December 31, 1997
289,365
During 1995, warrants with exercise prices ranging from $2.00 to $4.00 per share
were exercised for a total of 495,735 shares.
Note 8 - LENDER WARRANTS
In connection with the note payable dated December 31, 1993 (See Note 4)
warrants were issued to a group of six lenders. These warrants differ from those
described in Note 5; they have stronger antidilution provisions, effective
January 1, 1996 the holders can demand registering the warrant shares either
issuable upon exercise or held by the holder, and the holder may also, if the
Company files a registration statement, have an opportunity to include the
warrant shares in such registration statement. Warrants to acquire common stock
were as follows:
Number of Price per
Shares Share Expiration Date
- ------------- ----------- ----------------------
816,526 $2.25 December 31, 1998
Early in 1996, the warrants were exercised.
Note 9 - STOCK OPTIONS AND LONG-TERM INCENTIVE PLAN
On August 26, 1992, the stockholders approved a long-term incentive plan
allowing the Company to grant incentive and nonstatutory 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.
At December 31, 1995, there were no stock options outstanding.
During 1995, options with exercise prices ranging from $2.00 to $3.975 per share
were exercised for a total of 759,712 shares.
Under the terms of the long-term incentive plan, three directors surrendered
73,845 shares of stock to exercise 124,400 options. New options were issued
equal to the number of shares surrendered at a price of $2.0313 per share.
F-12
<PAGE>
Note 10 - RELATED PARTY TRANSACTIONS
During 1995, 25,000 warrants at a price of $2.50 per share were issued to and
exercised by a director.
During 1994, 650,000 warrants at a price of $2.75 per share were issued to the
Board of Directors. All warrants were exercised during 1994.
The Company entered into a triple net lease agreement with a partnership owned
by two directors for the lease of an office building. The lease, which expires
November, 2003, has monthly rental payments of $4,000. During 1995 and 1994,
$48,000 per year in rent was paid under the lease agreement. During 1993, no
rent was due under the lease agreement. A deposit of $4,000 was due and included
in accounts payable at December 31, 1993.
Stock options (see Note 7) originally issued to three directors to acquire
250,000 shares each, were exercisable through December 31, 1995 at $2.00 per
share. During 1995, 1994 and 1993, 150,000, 275,000 and 300,000 options were
exercised at $2.00 per share. In 1994 and 1993, an additional 275,000 and
300,000 options respectively were issued at prices ranging from $2.32 per share
to $3.9375 per share, and all options were exercised in 1995.
Under the terms of the long-term incentive plan, three directors were issued
73,845 options at $2.0313 per share and 68,567 options at $2.1875 per share in
1995 and 1994, respectively. These options were exercised in 1995.
Warrants were issued to a director in 1991 to acquire 250,000 shares. Of these,
160,000 shares were exercised in 1993 at $2.00 per share and 90,000 warrants are
exercisable through June 1, 1996 at $2.00 per share. In addition, 160,000
warrants at $2.375 issued December 10, 1993, are exercisable through June 1,
1996.
Consulting fees of $80,000 were paid in 1993 to an entity in which a director is
a 100% owner. At December 31, 1993, no such fees were payable to this entity.
In 1993, three new directors were awarded 4,098 shares each (valued at a total
of $30,000) pursuant to the Company's Long-term Incentive Plan. These shares
become vested over a thirty month period.
F-13
<PAGE>
During 1993, a director relinquished 4,098 shares upon his resignation.
Note 11 - LEASES
The following is a schedule of future rental payments required under an office
building lease described in Note 10 as of December 31, 1995.
Year ending December 31,
1996 $ 48,000
1997 48,000
1998 48,000
1999 48,000
2000 48,000
2001-2003 140,000
--------- -------
$ 380,000
===========
Rental expense incurred on a former office lease for the year ended December 31,
1993, was $26,180.
Note 12 - INCOME TAXES
At December 31, 1995, the Company had net operating loss carryforwards for
federal income tax purposes of $15,765,000 which are available to offset future
federal taxable income through 2010.
Significant components of the Company's deferred tax liabilities and assets as
of December 31 are as follows:
1995 1994
Deferred tax assets
Fixed asset basis differences 1,408,000 557,000
Net operating loss carry forwards 6,306,000 3,504,000
Total deferred tax assets 7,714,000 4,061,000
Valuation allowance for deferred
tax assets (7,714,000) (4,061,000)
Total deferred tax assets $ - $ -
A valuation allowance is provided to reduce the deferred tax assets to a level
which, more likely than not, will be realized.
The valuation allowance for deferred tax assets as of December 31, 1993 was
$3,704,000. The net change in the total valuation allowance for the years ended
December 31, 1995 and 1994 was an increase of $3,653,000 and $357,000,
respectively.
Note 13 - COMMITMENT AND CONTINGENCIES
A $3,000,000 letter of credit, collateralizing a plugging bond, expires on
December 14, 1996. The contract amount of the letter of credit approximates its
fair value.
The Company has had a suit filed against it related to a gas gathering system in
Oklahoma seeking $700,000. The Company has filed a counter claim against the
plaintiff alleging fraud, asking that the contract, which is the subject of the
suit, be declared void. Management feels the suit is without merit and will be
disposed of for less than the amount claimed, although this amount can not be
reasonably estimated.
F-14
<PAGE>
Note 14 - EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)
In August, 1994, the Company established an Employee Stock Ownership Plan (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 $132,000 and $123,000 in costs for the years ended
December 31, 1995 and 1994, respectively.
Note 15 - IMPAIRMENT OF LONG-LIVED ASSETS
In 1995 the company adopted the Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets
to be Disposed Of", which requires that long-lived assets and identifiable
intangibles be reviewed for impairment when the assets carrying amount may not
be recoverable based on the fair market value of the asset. SFAS 121 requires
assets to be reviewed for impairment at the lowest level for which there are
independent, identifiable cash flows. The adoption of SFAS 121 had no effect on
1995 financial statements and the Company expects no future impact as the
Company evaluates its oil and gas properties for impairment on a field by field
basis as prescribed by FAS No. 121.
Note 16 - FINANCIAL INSTRUMENTS
Effective December 31, 1995, the Company adopted the requirements of Statement
of Financial Accounting Standards No. 107, "Disclosure about Fair Value of
Financial Instruments" requires disclosure of an estimate of the fair value of
certain financial instruments. The carrying amount and fair values of the
Company's financial instruments at December 31, 1995, are as follows:
Assets (Liabilities)
--------------------------------------
Carrying Amount Fair Value
Cash and cash equivalents $ 1,198,000 $ 1,198,000
Receivables 4,415,000 4,415,000
Payables (4,605,000) (4,605,000)
Long-term variable rate debt (17,390,000) (17,390,000)
Long-term fixed rate debt (5,000,000) (3,675,150)
Off balance sheet financial instruments
Letter of credit 0
Hedge contracts (2,000,000)
Cash and cash equivalents, receivables, payables, and long-term variable
rate debt The carrying amount reported on the consolidated balance sheet
approximates its fair value because of the short maturities of these
instruments.
Long-term, fixed rate debt
The Company estimates the fair value of its long-term, fixed rate debt generally
using discounted cash flow analysis based on the Corporation's current borrowing
rates for debt with similar maturities.
Letter of credit
A $3,000,000 letter of credit collateralizes a plugging bond. Fair value
estimated on the basis of fees paid to obtain the obligation is not material at
December 31, 1995.
Hedge contract
The fair values of the Company's futures contracts are estimated based on
current settlement values.
F-15
<PAGE>
Concentrations of Credit Risk
Financial instruments which potentially subject the Company to concentration of
credit risk consist principally of bank account balances in excess of federally
insured limits and trade receivables. The Company's receivables consist of oil
and gas sales to third parties primarily from offshore production in the Gulf of
Mexico and onshore oil production in the central part of the United States. This
concentration may impact the Company's overall credit risk, either positively or
negatively, in that these entities may be similarly affected by changes in
economic or other conditions. Receivables are generally not collateralized.
Historical credit losses incurred by the Company on receivables have not been
significant.
Note 17 - SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
<TABLE>
The following table reflects the costs incurred in oil and gas property
activities for each of the three years ended December 31:
<CAPTION>
1995 1994 1993
------------- ------------- --------------
<S> <C> <C> <C>
Property acquisition costs, proved $12,603,000 $ 352,000 $ -
Property acquisition costs, unproved $ - $ - $ -
Exploration costs $ 8,112,000 $ - $ -
Development costs $ 1,497,000 $ 11,749,000 $ 801,000
Quantities of Oil and Gas Reserves
</TABLE>
The estimates of proved developed and proved undeveloped reserve quantities at
December 31, 1995 are based upon reports of petroleum engineers and do not
purport to reflect realizable values or fair market values of Panaco's reserves.
It should be emphasized that reserve estimates are inherently imprecise and
accordingly, these estimates are expected to change as future information
becomes available. These are estimates only and should not be construed as exact
amounts. All reserves are located in the United States.
Proved reserves are estimated reserves of natural gas and crude oil and
condensate that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those expected
to be recovered through existing wells, equipment, and operating methods.
<TABLE>
Proved developed and undeveloped reserves Oil Gas
<CAPTION>
<S> <C> <C> <C> <C>
Estimated reserves as of December 31, 1992 1,121,000 46,595,000
Production (180,000) (5,586,000)
Sale of minerals in-place (12,000) (155,000)
Revisions of previous estimates (184,000) 2,842,000
Estimated reserves as of December 31, 1993 745,000 43,696,000
Production (137,000) (8,139,000)
Extensions and discoveries 183,000 16,930,000
Sale of minerals in-place (24,000) (45,000)
Revisions of previous estimates 176,000 (10,860,000)
Estimated reserves as of December 31, 1994 943,000 41,582,000
Production (170,000) (9,850,000)
Sale of minerals in-place (1,000) (22,000)
Purchase of minerals in-place 1,140,000 20,094,000
Revisions of previous estimates (12,000) (5,093,000)
Estimated reserves as of December 31, 1995 1 ,900,000 46,711,000
</TABLE>
F-16
<PAGE>
Proved developed reserves:
Oil Gas
(BBLS) (MCF)
----------- --------------
December 31, 1992 1,053,000 36,208,000
December 31, 1993 745,000 24,665,000
December 31, 1994 907,000 36,282,000
December 31, 1995 1,794,000 40,323,000
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows are computed by applying year-end prices of oil and gas
(with consideration of price changes only to the extent provided by contractual
arrangements) to the year-end estimated future production of proved oil and gas
reserves. Estimates of future development and production costs are based on
year-end costs and assume continuation of existing economic conditions. The
estimated future net cash flows are then discounted using a rate of 10 per cent
per year to reflect the estimated timing of the future cash flows. The
standardized measure of discounted cash flows is the future net cash flows less
the computed discount.
F-17
<PAGE>
<TABLE>
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:
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Future cash inflows $ 140,247,000 $88,893,000 $113,419,000
Future development and production costs 50,723,000 32,197,000 38,375,000
Future net cash flows 89,524,000 56,696,000 75,044,000
Future income taxes 11,755,000 6,304,000 13,937,000
Future net cash flows after income taxes 77,769,000 50,392,000 61,107,000
10% annual discount (14,848,000) (8,477,000) (13,728,000)
Standardized measure after income taxes $ 62,921,000 $41,915,000 $ 47,379,000
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
The accompanying table reflects the principal changes in the standardized
measure of discounted future net cash flows attributable to proved oil and gas
reserves for each of the three years ended December 31:
1995 1994 1993
Beginning balance $ 41,915,000 $47,379,000 $ 48,163,000
Sales of oil and gas, net of production costs (9,314,000) (11,047,000) (9,426,000)
Net change in income taxes (4,267,000) 5,562,000 (2,130,000)
Changes in price and production costs 11,498,000 (10,781,000) 2,199,000
Purchase of minerals in-place 34,415,000 - -
Revision of previous estimates, extensions,
discoveries, & sales of minerals in place-net (11,326,000) 10,802,000 8,573,000
Ending balance $ 62,921,000 $41,915,000 $ 47,379,000
Price per MCF $ 2.24 $ 1.75 $ 2.40
Price per BBL $ 17.75 $ 16.00 $ 12.75
</TABLE>
F-18
<PAGE>
Note 18 - ACQUISITIONS
On July 12, 1995, the Company entered into a Purchase and Sale Agreement with
Zapata Exploration Company ("Zapata") to acquire all of Zapata's offshore oil
and gas properties in the Gulf of Mexico. The properties consist of East Breaks
Blocks 109 and 110, East Cameron Block 359, Eugene Island Block 372, South
Timbalier Block 185 and West Cameron Block 538, totaling 31,134 gross acres. The
transaction closed July 26, 1995.
The purchase price for the assets acquired in this transaction was $2,748,000 in
cash and the obligation to pay a production payment to Zapata based upon future
production. The production payment is based upon production from the East Breaks
109 Field after production of 12 Bcfe gross (10 Bcfe net) measured from October
1, 1994. The Company will pay to Zapata $.4167 per Mcfe on the next 27 Bcfe
produced. Payments to Zapata on this production payment are to be made by the
Company when it is paid for the oil or gas. Oil and gas reserves attributable to
this production payment are not included in the reserves for the properties set
forth herein.
As of November 30, 1995, the Company entered into a Purchase and Sale Agreement
with Shell Western E&P Inc. ("Shell") to acquire all of Shell's interest in the
Bayou Sorrel Field in Iberville Parish, Louisiana. The transaction closed
December 27, 1995, and PANACO took over as operator from Shell. Proved reserves
attributable to the field at December 31, 1995, were 898,000 barrels and 3.1 Bcf
of natural gas. In addition to the proved reserves management has identified
significant probable and possible reserves attributable to this field. The
purchase price of the field was $10,455,000 which included a $204,000 brokers'
fee and a related receivable of $600,000.
Both of the acquisitions made in 1995 were accounted for using the purchase
method. The results of the Zapata properties acquisition are included in the
Company's statement of income (operations) from July 27 to December 31, 1995.
The results of the Bayou Sorrel acquisition are included in the Company's
statement of income (operations) from December 28 to December 31, 1995.
The unaudited pro forma statement of income (operations) for the year ended
December 31, 1995 assumes the Zapata and Bayou Sorrel acquisitions had been
consummated January 1, 1995. The unaudited pro forma statement of income
(operations) includes certain adjustments to give effect to the acquisitions of
the oil and gas properties.
The pro forma statement do not purport to be indicative of the results of the
Company had these acquisitions occurred on the date assumed, nor is the pro
forma statement necessarily indicative of the future results of the Company. The
pro forma statement should be read together with the Financial Statements of the
Company, including the notes thereto and included elsewhere in this Statement.
F-19
<PAGE>
<TABLE>
PANACO, INC.
Unaudited Pro Forma Combined Statement of Income (Operations)
For the Year Ended December 31, 1995
<CAPTION>
Zapata Bayou PANACO, Inc.
PANACO, Inc. Properties Sorrel Field Pro Forma Pro Forma
(As Restated) 1/1-7/26/95 1/1-12/26/95 Adjustments Combined
REVENUES
<S> <C> <C> <C> <C>
Oil and gas sales $ 18,447,000 $ 3,623,000 $ 3,326,000 $ -- $ 25,396,000
Future contracts -- -- -- -- --
Total 18,447,000 3,623,000 3,326,000 -- 25,396,000
COSTS AND EXPENSES
Lease operating 8,055,000 1,460,000 867,000 280,000 (a) 10,662,000
Depreciation, depletion and
amortization 8,064,000 -- -- 1,812,000 (b) 9,876,000
Exploration expenses 8,112,000 -- -- -- 8,112,000
Provision for losses and
(gains) on disposition
& write-down of assets 751,000 -- -- -- 751,000
General and administrative 690,000 -- -- -- 987,000
Production and ad valorem
taxes 1,078,000 -- 297,000 -- 1,078,000
--------- ------- ---------
Total 26,750,000 1,460,000 1,164,000 2,092,000 31,466,000
NET OPERATING INCOME
(LOSS) (8,303,000) 2,163,000 2,162,000 (2,092,000) (6,070,000)
OTHER INCOME (EXPENSE)
Interest income 5,000 -- -- -- 5,000
Interest expense (992,000) -- -- (651,000) (c) (1,643,000)
-------- -------- ----------
Total (987,000) -- -- (651,000) (1,638,000)
-------- -------- ----------
NET INCOME (LOSS) BEFORE
INCOME TAXES (9,290,000) 2,163,000 2,162,000 (2,743,000) (7,708,000)
INCOME TAXES (BENEFIT) -- -- -- -- --
NET INCOME (LOSS $(9,290,000) $2,163,000 $2,162,000 $(2,743,000) $(7,708,000)
EARNINGS (LOSS) PER COMMON SHARE
Primary
Net earnings (loss) $ (0.81) $ (0.67)
Assuming full dilution
Net earnings (loss) $ (0.81) $ (0.67)
Weighted average shares outstanding:
Primary 11,504,615 11,504,615
Assuming full dilution 11,504,615 11,504,615
</TABLE>
The accompanying notes to pro forma financial statements are an
integral part of this statement.
F-20
<PAGE>
<TABLE>
PANACO, INC.
Unaudited Pro Forma Combined Statement of Income (Operations)
For the Year Ended December 31, 1994
<CAPTION>
Zapata Bayou PANACO, Inc.
PANACO, Inc. Properties Sorrel Field Pro Forma Pro Forma
(As Restated) 1/1-7/26/94 1/1-12/26/94 Adjustments Combined
REVENUES
<S> <C> <C> <C> <C>
Oil and gas sales $ 17,367,000 $ 7,540,000 $ 2,888,000 $ -- $ 27,795,000
Future contracts (29,000) -- -- -- (29,000)
Total 17,338,000 7,540,000 2,888,000 -- 27,766,000
COSTS AND EXPENSES
Lease operating 5,231,000 3,317,000 1,942,000 480,000 (a) 10,970,000
Depreciation, depletion and amort. 6,038,000 -- -- 1,447,000 (b) 7,485,000
Exploration expenses -- -- -- -- --
Provision for losses and (gains)
on disposition and write-down
of assets 1,202,000 -- -- -- 1,202,000
General and administrative 587,000 -- 310,000 -- 897,000
Production and ad valorem taxes 1,006,000 -- -- -- 1,006,000
--------- ---------
Total 14,064,000 3,317,000 2,252,000 1,927,000 21,560,000
NET OPERATING INCOME (LOSS) 3,274,000 4,223,000 636,000 (1,927,000) 6,206,000
OTHER INCOME (EXPENSE)
Interest income 46,000 -- -- -- 46,000
Interest expense (1,669,000) -- -- (788,000) (c) (2,457,000)
---------- -------- ----------
Total (1,623,000) -- -- (788,000 (2,411,000)
NET INCOME (LOSS) BEFORE
INCOME TAXES AND
EXTRAORDINARY ITEM 1,651,000 4,223,000 636,000 (2,715,000) 3,795,000
INCOME TAXES (BENEFIT) -- -- -- -- --
EXTRAORDINARY ITEM-LOSS
ON EARLY RETIREMENT OF
DEBT $ (536,000) $ -- $ -- $ -- $ (536,000)
------------ ------ ------ ------ ----------
NET INCOME (LOSS) $ 1,115,000 $ 4,223,000 $ 636,000 $(2,715,000) $ 3,259,000
EARNINGS (LOSS) PER COMMON SHARE
Primary
Net (loss) before extraordinary item$ 0.16 $ 0.37
Extraordinary loss (0.05) (0.05)
Net earnings (loss) $ 0.11 $ 0.33
Assuming full dilution
Earnings loss before
extraordinary item $ 0.16 $ 0.38
Extraordinary loss (0.05) (0.05)
Net earnings (loss) $ 0.11 $ 0.33
Weighted average shares outstanding:
Primary 9,952,870 9,952,870
Assuming full dilution 10,039,042 10,039,042
</TABLE>
The accompanying notes to pro forma financial statements are an
integral part of this statement.
F-21
<PAGE>
NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME (OPERATIONS)
1. Basis of Presentation
The Unaudited Pro Forma Statement of Income (Operations) of PANACO, Inc.
presents the combined effects of the acquisition of the Zapata properties and
Bayou Sorrel Field as if the acquisitions had been consummated January 1st of
each year.
2. Pro Forma Entries
(a) To record the estimated additional insurance expense.
(b) To record the additional depletion and depreciation expense for the
increased property costs and production volumes (see Note 4 below).
(c) To record the additional interest expense for increased term of
borrowing (see Note 5 below).
3. Taxes
No additional operating taxes are included for the Zapata properties as the
production from these properties is from federal offshore waters and are not
subject to severance taxes.
4. Depletion, depreciation & amortization
Additional depletion and depreciation expense is included to reflect the
additional property costs and production volumes assuming the transaction was
consummated January 1. The original purchase prices are used for the cost of the
properties. The actual purchase prices of the properties were reduced by the net
income of the properties from the effective dates of the purchases until the
closing dates.
5. Interest
Additional interest expense is included as if the transactions had taken place
January 1. It is assumed that the Zapata acquisition price was paid in cash and
the Bayou Sorrel acquisition price was paid for using the Company's Primary
Credit Facility. Interest is computed on the additional borrowings at the
estimated rates in effect at January 1.
F-22
<PAGE>
Independent Auditors' Report
To the Board of Directors
Panaco, Inc.
We have audited the accompanying schedules of Revenues, Direct Operating
Expenses and Production Taxes of the Zapata properties (which were acquired by
Panaco, Inc., on July 26, 1995) and the Bayou Sorrel Field (which was acquired
by Panaco on December 27, 1995) for each of the two years in the period ended
December 31, 1994. These schedules are the responsibility of Panaco, Inc.'s
management. Our responsibility is to express an opinion on the schedules based
on our audits.
We conducted our audit in accordance with generally accepted auditing standards.
These standards require that we plan and perform the audit to obtain reasonable
assurance about whether the Schedules of Revenues, Direct Operating Expenses and
Production Taxes are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
schedules. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
schedule presentation. We believe that our audits provides a reasonable basis
for our opinion.
The accompanying Schedules of Revenues, Selected Direct Operating Expenses and
Production Taxes were prepared for the purpose of complying with the rules and
regulations of the Securities and Exchange Commission (for inclusion in the
current report on Form 10-K) and is not intended to be a complete presentation
of the Zapata properties and Bayou Sorrel Field's revenues and expenses.
In our opinion, the Schedules of Revenues, Direct Operating Expenses and
Production Taxes referred to above present fairly, in all material respects, the
revenues, selected direct operating expenses and production taxes of the Zapata
properties and the Bayou Sorrel Field for each of the two years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.
BARRETT & ASSOCIATES
Overland Park, Kansas
December 15, 1995
F-23
<PAGE>
<TABLE>
ZAPATA PROPERTIES AND BAYOU SORREL FIELD
SCHEDULES OF REVENUES, SELECTED DIRECT OPERATING EXPENSES
AND PRODUCTION TAXES
<CAPTION>
Year Ended December 31, 1994
<S> <C> <C> <C>
Oil and gas revenues $ 7,540,000 $ 2,888,000 $ 10,428,000
Selected direct operating expenses $ 3,317,000 $ 1,942,000 $ 5,259,000
Production taxes $ 0 $ 310,000 $ 310,000
Year Ended December 31, 1993
Oil and gas revenues $ 11,823,000 $ 2,908,000 $ 14,731,000
Selected direct operating expenses $ 3,696,000 $ 1,806,000 $ 5,502,000
Production taxes $ 0 $ 352,000 $ 352,000
</TABLE>
See accompanying notes to this schedule.
F-24
<PAGE>
ZAPATA PROPERTIES AND BAYOU SORREL FIELD
NOTES TO THE SCHEDULES OF REVENUES,
SELECTED DIRECT OPERATING EXPENSES AND PRODUCTION TAXES
FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1993
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
This summary of significant accounting policies related to the Schedules of
Revenues, Selected Direct Operating Expenses and Production Taxes of the Zapata
properties and the Bayou Sorrel Field is presented to assist in understanding
the schedules. The schedules and notes are representations of Panaco, Inc.'s
management, which is responsible for the integrity and objectivity of the
schedules. These accounting policies conform to generally accepted accounting
principles and have been consistently applied in the preparation of the
statement.
Acquisitions
The Zapata properties were acquired by Panaco, Inc. on July 26, 1995 from
Zapata Exploration Co. The Bayou Sorrel Field was acquired by Panaco, Inc. on
December 27, 1995, from Shell-Western E&P, Inc.
Revenue Recognition
Revenues are recorded on the accrual basis, with volumes and prices being
estimated for properties during periods when actual production information is
not available.
Selected Direct Operating Expenses
Selected direct operating expenses include necessary and ordinary expenses
to maintain production. Insurance expense is not included since sufficient
information is not available from the Seller. Management estimates insurance
costs to be $280,000 per annum.
Depreciation, depletion and amortization
Depreciation, depletion and amortization is not presented as sufficient
information is not available from the Seller.
Operating Taxes
No additional tax expense is included for the Zapata properties, as the
production from federal offshore waters are not subject to state severance
taxes.
General, Administrative, and Overhead Expenses
General, administrative, and overhead expenses are not presented as sufficient
information is not available from the Seller.
F-25
<PAGE>
Note 2 - 1995 REVENUES, SELECTED DIRECT OPERATING EXPENSES AND PRODUCTION
TAXES (UNAUDITED)
<TABLE>
The following is a schedule of revenues, selected direct operating expenses and
production taxes for the periods in 1995 that Panaco, Inc. did not own the
Zapata properties and the Bayou Sorrel Field. The schedule is not intended to be
a complete presentation of the Zapata properties and Bayou Sorrel Field's
revenues and expenses.
<CAPTION>
Oil and Gas Selected Direct Production
Revenues Operating Expenses Taxes
Zapata Properties
<S> <C> <C> <C> <C> <C> <C>
January 1, 1995 to July 25, 1995 $ 3,623,000 $ 1,460,000 $ 0
Bayou Sorrel
January 1, 1995 to December 26, 1995 3,326,000 867,000 297,000
TOTAL $ 6,949,000 $ 2,327,000 $ 297,000
</TABLE>
Note 3 - SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Quantities of Oil and Gas Reserves
The estimates of proved developed and proved undeveloped reserve quantities of
the Zapata properties and the Bayou Sorrel Field at December 31, 1994 are based
upon management's computation from the report of Panaco's independent petroleum
engineers as of December 31, 1995, and do not purport to reflect realizable
values or fair market values of the properties' 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. Reserve quantities for the Zapata
properties and the Bayou Sorrel Field were not available at December 31, 1992,
1993, and 1994, and the balances at those dates were derived from production
activity during 1993 and 1994.
Proved reserves are estimated reserves of natural gas and crude oil that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those expected to be
recovered through existing wells, equipment, and operating methods.
<TABLE>
<CAPTION>
Proved developed and OIL (BBLS) GAS (MCF)
undeveloped reserves Bayou Bayou
Zapata Sorrel Total Zapata Sorrel Total
Estimated reserves as of
<S> <C> <C> <C> <C> <C> <C> <C> <C>
December 31, 1992 391,000 1,323,000 1,714,000 27,647,000 4,039,000 31,686,000
Production (54,000) (143,000) (197,000) (4,924,000) (228,000) (5,152,000)
Estimated reserves as of
December 31, 1993 337,000 1,180,000 1,517,000 22,723,000 3,811,000 26,534,000
Production (67,000) (127,000) (194,000) (3,419,000) (368,000) (3,787,000)
Estimated reserves as of
December 31, 1994 270,000 1,053,000 1,323,000 19,304,000 3,443,000 22,747,000
Proved, developed reserves:
December 31, 1993 337,000 1,180,000 1,517,000 22,723,000 3,811,000 26,534,000
December 31, 1994 270,000 1,053,000 1,323,000 19,304,000 3,443,000 22,747,000
</TABLE>
F-26
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows are computed by applying year-end prices of oil and gas
(with consideration of price changes only to the extent provided by contractual
arrangements) to the year-end estimated future production of proved oil and gas
reserves. Estimates of future development and production costs are based on
year-end costs and assume continuation of existing economic conditions. The
estimated future net cash flows are then discounted using a rate of 10 percent
per year to reflect the estimated timing of the future cash flows. The
standardized measure of discounted cash flows is the future net cash flows less
the computed discount.
The accompanying table reflects the standardized measure of discounted future
cash flows relating to the proved oil and gas reserves of the Zapata properties
as of the two years ended December 31:
<TABLE>
<CAPTION>
1994 1993
Bayou Bayou
Zapata Sorrel Total Zapata Sorrel Total
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows $ 45,181,000 $27,233,000 $72,414,000 $52,721,000 $30,121,000 $ 82,842,000
Future development
and production costs 15,341,000 9,021,000 24,362,000 18,658,000 11,273,000 29,931,000
Future net cash flows 29,840,000 18,212,000 48,052,000 34,063,000 18,848,000 52,911,000
10% annual discount
to reflect timing of
cash flows 1,821,000 5,532,000 7,353,000 1,821,000 5,532,000 7,353,000
Standardized measure
before income taxes $ 28,019,000 $12,680,000 $40,699,000 $ 32,242,000 $13,316,000 $ 45,558,000
</TABLE>
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
The accompanying table reflects the principal changes in the standardized
measure of discounted future net cash flows attributable to proved oil and gas
reserves of the Zapata properties for each of the two years ended December 31:
<TABLE>
<CAPTION>
1994 1993
Bayou Bayou
Zapata Sorrel Total Zapata Sorrel Total
<S> <C> <C> <C> <C> <C> <C>
Beginning balance $ 32,242,000 $13,316,000 $45,558,000 $ 40,369,000 $14,066,000 $ 54,435,000
Sales of oil and gas,
net of production
costs 4,223,000 636,000 4,859,000 8,127,000 750,000 8,877,000
Ending balance $ 28,019,000 $12,680,000 $40,699,000 $ 32,242,000 $13,316,000 $ 45,558,000
</TABLE>
F-27
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 882074
<NAME> PANACO, Inc.
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-1-1995
<PERIOD-END> DEC-31-1995
<CASH> 1,198,000
<SECURITIES> 0
<RECEIVABLES> 3,294,000
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 6,049,000
<PP&E> 103,301,000
<DEPRECIATION> 73,712,000
<TOTAL-ASSETS> 36,169,000
<CURRENT-LIABILITIES> 4,605,000
<BONDS> 0
0
0
<COMMON> 115,000
<OTHER-SE> 21,155,000
<TOTAL-LIABILITY-AND-EQUITY> 36,169,000
<SALES> 18,447,000
<TOTAL-REVENUES> 18,447,000
<CGS> 0
<TOTAL-COSTS> 26,750,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 987,000
<INCOME-PRETAX> (9,290,000)
<INCOME-TAX> (9,290,000)
<INCOME-CONTINUING> (9,290,000)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (9,290,000)
<EPS-PRIMARY> (.81)
<EPS-DILUTED> (.81)
</TABLE>
