SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
COMMISSION FILE NUMBER 001-14039
CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)
DELAWARE 64-0844345
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
200 NORTH CANAL STREET
NATCHEZ, MISSISSIPPI 39120 (601) 442-1601
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(Address of Principal Executive (Registrant's telephone number
Offices)(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
------------------------------------------- ------------------------------------
Convertible Exchangeable Preferred Stock, New York Stock Exchange
Series A, Par Value $.01 Per Share
Common Stock, Par Value $.01 Per Share New York Stock Exchange
Preferred Stock Purchase Rights New York Stock Exchange
11% Senior Subordinated Notes due 2005 New York Stock Exchange
10.25% Senior Subordinated Notes due 2004 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
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 Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was approximately $98,778,082 as of March 18, 2002 (based on the last
reported sale price of such stock on the New York Stock Exchange).
As of March 18, 2002, there were 13,424,216 shares of the Registrant's Common
Stock, par value $.01 per share, outstanding.
Document incorporated by reference: Portions of the definitive Proxy Statement
of Callon Petroleum Company (to be filed no later than 120 days after December
31, 2001) relating to the Annual Meeting of Stockholders to be held on May 8,
2002, which is incorporated into Part III of this Form 10-K.
PART I.
ITEM 1. BUSINESS
OVERVIEW
Callon Petroleum Company has been engaged in the exploration, development,
acquisition and production of oil and gas properties since 1950. Our properties
are geographically concentrated primarily offshore in the Gulf of Mexico and
onshore in Louisiana and Alabama. The public Company was formed under the laws
of the state of Delaware in 1994 through the consolidation of a publicly traded
limited partnership, a joint venture with a consortium of European institutional
investors and an independent energy company owned by certain members of current
management (the "Consolidation"). As used herein, the "Company," "Callon," "we,"
"us," and "our" refer to Callon Petroleum Company and its predecessors and
subsidiaries unless the context requires otherwise.
In 1989, we began increasing our reserves through the acquisition of producing
properties that were geologically complex, had (or were analogous to fields
with) an established production history from stacked pay zones and were
candidates for exploitation. We focused on reducing operating costs and
implementing production enhancements through the application of technologically
advanced production and recompletion techniques.
Over the past several years, we have also placed emphasis on the acquisition of
acreage with exploration and development drilling opportunities in the Gulf of
Mexico Shelf area. We acquired an infrastructure of production platforms,
gathering systems and pipelines to minimize development expenditures of these
drilling opportunities. We also joined with other industry partners, primarily
Murphy Exploration and Production, Inc., ("Murphy") to explore federal offshore
blocks acquired in the Gulf of Mexico. Over the last several years we have
expanded our areas of exploration to include the Gulf of Mexico Deepwater area
(generally 900 to 5,500 feet of water).
We ended the year 2001 with estimated net proved reserves of 303 billion cubic
feet of natural gas equivalent ("Bcfe"). This represents a decrease of 9% from
2000 year-end estimated net proved reserves of 334 Bcfe.
The major focus of our future operations is expected to continue to be the
exploration for and development of oil and gas properties, primarily in the Gulf
of Mexico.
BUSINESS STRATEGY
Our goal is to increase shareholder value by increasing our reserves,
production, cash flow and earnings. We seek to achieve these goals through the
following strategies:
o Focus on Gulf of Mexico exploration with a balance between shelf and
deepwater areas using the latest available technology.
o Aggressively explore our existing prospect inventory.
o Replenish our prospect inventory with increasing emphasis on prospect
generation.
o Achieve moderate increases in current production levels through continued
shelf exploration.
o Achieve significant increases in longer-term production levels through
development of deepwater discoveries and ongoing deepwater exploration.
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EXPLORATION AND DEVELOPMENT ACTIVITIES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $112.6 million in 2001. We incurred
approximately $63.7 million in the Gulf of Mexico Shelf area.
The Gulf of Mexico Deepwater area expenditures ($31.9 million) accounted for the
remainder of the total capital expended, along with $4.2 million incurred in
leasehold and seismic acquisition costs and $12.8 million of interest and
general and administrative costs allocable directly to exploration and
development projects. The Gulf of Mexico Deepwater area expenditures included
one unsuccessful exploration project totaling $2.2 million and the balance was
incurred for additional delineation drilling and production facility fabrication
at our Medusa discovery and the delineation drilling at Habanero.
As a result of recent successes in the Gulf of Mexico Deepwater area, we are
faced with increased costs to develop these significant proved undeveloped
reserves. A large portion of these future development costs will be incurred in
2002 and beyond. We are currently evaluating various financing alternatives to
address these issues. While management believes there are a number of financing
sources available to us, no assurances can be made that we will be able to fund
these development costs.
RISK FACTORS
DECREASE IN OIL AND GAS PRICES MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS
AND FINANCIAL CONDITION. Our success is highly dependent on prices for oil and
gas, which are extremely volatile. Any substantial or extended decline in the
price of oil or gas would have a material adverse effect on us. Oil and gas
markets are both seasonal and cyclical. The prices of oil and gas depend on
factors we cannot control such as weather, economic conditions, levels of
production, actions by OPEC and other countries and government actions. Prices
of oil and gas will affect the following aspects of our business:
o our revenues, cash flows and earnings;
o the amount of oil and gas that we are economically able to produce;
o our ability to attract capital to finance our operations and the cost of
the capital;
o the amount we are allowed to borrow under our senior credit facility;
o the value of our oil and gas properties; and
o the profit or loss we incur in exploring for and developing our reserves.
UNLESS WE ARE ABLE TO REPLACE RESERVES, WHICH WE HAVE PRODUCED, OUR CASH FLOWS
AND PRODUCTION WILL DECREASE OVER TIME. Our future success depends upon our
ability to find, develop and acquire oil and gas reserves that are economically
recoverable. As is generally the case for Gulf Coast properties, our producing
properties usually have high initial production rates, followed by a steep
decline in production. As a result, we must continually locate and develop or
acquire new oil and gas reserves to replace those being depleted by production.
We must do this even during periods of low oil and gas prices when it is
difficult to raise the capital necessary to finance these activities and during
periods of high operating costs when it is expensive to contract for drilling
rigs and other equipment and personnel necessary to explore for oil and gas.
Without successful exploration or acquisition activities, our reserves,
production and revenues will decline rapidly. We cannot assure you that we will
be able to find and develop or acquire additional reserves at an acceptable
cost.
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A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
IN A SMALL NUMBER OF OFFSHORE PROPERTIES, AND ANY PRODUCTION PROBLEMS OR
INACCURACIES IN RESERVE ESTIMATES RELATED TO THOSE PROPERTIES WOULD ADVERSELY
IMPACT OUR BUSINESS. During 2001, 44% of our daily production came from two of
our properties in the Gulf of Mexico. Moreover, one property accounted for 25%
of our production during this period. If mechanical problems, storms or other
events curtailed a substantial portion of this production, our results of
operations would be adversely affected. In addition, at December 31, 2001 most
of our proved reserves were located in five fields in the Gulf of Mexico, with
approximately 93% of our total net proved reserves attributable to these
properties. If the actual reserves associated with any one of these five
discoveries are less than our estimated reserves, our results of operations and
financial condition could be adversely affected.
OUR FOCUS ON EXPLORATION PROJECTS INCREASES THE RISKS INHERENT IN OUR OIL AND
GAS ACTIVITIES. Our business strategy focuses on replacing reserves through
exploration, where the risks are greater than in acquisitions and development
drilling. Although we have been successful in exploration in the past, we cannot
assure you that we will continue to increase reserves through exploration or at
an acceptable cost. Additionally, we are often uncertain as to the future costs
and timing of drilling, completing and producing wells. Our drilling operations
may be curtailed, delayed or canceled as a result of a variety of factors,
including:
o unexpected drilling conditions;
o pressure or inequalities in formations;
o equipment failures or accidents;
o adverse weather conditions;
o compliance with governmental requirements; and
o shortages or delays in the availability of drilling rigs and the
delivery of equipment.
BECAUSE WE DO NOT CONTROL ALL OF OUR PROPERTIES, ESPECIALLY OUR DEEPWATER
PROPERTIES, WE HAVE LIMITED INFLUENCE OVER THEIR DEVELOPMENT. We do not operate
all of our properties and have limited influence over the operations of some of
these properties, particularly our deepwater projects. Our lack of control could
result in the following:
o the operator may initiate exploration or development on a faster or
slower pace than we prefer;
o the operator may propose to drill more wells or build more facilities on
a project than we have funds for or that we deem appropriate, which may
mean that we are unable to participate in the project or share in the
revenues generated by the project even though we paid our share of
exploration costs; and
o if an operator refuses to initiate a project, we may be unable to pursue
the project.
Any of these events could materially reduce the value of our properties.
OUR DEEPWATER OPERATIONS HAVE SPECIAL OPERATIONAL RISKS THAT MAY NEGATIVELY
AFFECT THE VALUE OF THOSE ASSETS. Drilling operations in the deepwater area are
by their nature more difficult and costly than drilling operations in shallow
water. They require the application of more advanced drilling technologies,
involving a higher risk of technological failure and usually resulting in
significantly higher drilling costs. Deepwater wells are completed using subsea
completion techniques that require substantial time and the use of advanced
remote installation equipment. These operations involve a high risk of
mechanical difficulties and equipment failures that could result in significant
cost overruns.
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In deepwater, the time required to commence production following a discovery is
much longer than in shallow water and on-shore. Our deepwater discoveries and
prospects will require the construction of expensive production facilities and
pipelines prior to the beginning of production. We cannot estimate the costs and
timing of the construction of these facilities with certainty, and the accuracy
of our estimates will be affected by a number of factors beyond our control,
including the following:
o decisions made by the operators of our deepwater wells;
o the availability of materials necessary to construct the facilities;
o the proximity of our discoveries to pipelines; and
o the price of oil and natural gas.
Delays and cost overruns in the commencement of production will affect the value
of our deepwater prospects and the discounted present value of reserves
attributable to those prospects.
COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT
OPERATIONS. We operate in the highly competitive areas of oil and gas
exploration, development and production. We compete for the purchase of leases
in the Gulf of Mexico from the U. S. government and from other oil and gas
companies. These leases include exploration prospects as well as properties with
proved reserves. Factors that affect our ability to compete in the marketplace
include:
o our access to the capital necessary to drill wells and acquire
properties;
o our ability to acquire and analyze seismic, geological and other
information relating to a property;
o our ability to retain the personnel necessary to properly evaluate
seismic and other information relating to a property;
o the location of, and our ability to access, platforms, pipelines and
other facilities used to produce and transport oil and gas production;
o the standards we establish for the minimum projected return on an
investment of our capital; and
o the availability of alternate fuel sources.
Our competitors include major integrated oil companies, substantial independent
energy companies, affiliates of major interstate and intrastate pipelines and
national and local gas gatherers, many of which possess greater financial,
technological and other resources than we do.
OUR COMPETITORS MAY USE SUPERIOR TECHNOLOGY, WHICH WE MAY BE UNABLE TO AFFORD OR
WHICH WOULD REQUIRE COSTLY INVESTMENT BY US IN ORDER TO COMPETE. Our industry is
subject to rapid and significant advancements in technology, including the
introduction of new products and services using new technologies. As our
competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new
technologies at a substantial cost. In addition, our competitors may have
greater financial, technical and personnel resources that allow them to enjoy
technological advantages and may in the future allow them to implement new
technologies before we can. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to us.
One or more of the technologies that we currently use or that we may implement
in the future may become obsolete, and we may be adversely affected. For
example, marine seismic acquisition technology has been characterized by rapid
technological advancements in recent years, and further significant
technological developments could substantially impair our 3-D seismic data's
value.
WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE
UNABLE TO RAISE CAPITAL. We will be required to make substantial capital
expenditures to develop our existing reserves, and to discover new oil and gas
reserves.
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Historically, we have financed these expenditures primarily with cash from
operations, proceeds from bank borrowings and proceeds from the sale of debt and
equity securities. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources" for a
discussion of our capital budget. We cannot assure you that we will be able to
raise capital in the future. We also make offers to acquire oil and gas
properties in the ordinary course of our business. If these offers are accepted,
our capital needs may increase substantially.
We expect to continue using our senior credit facility to borrow funds to
supplement our available cash. The amount we may borrow under our senior credit
facility may not exceed a borrowing base determined by the lenders based on
their projections of our future production, future production costs, taxes,
commodity prices and any other factors deemed relevant by our lenders. We cannot
control the assumptions the lenders use to calculate our borrowing base. The
lenders may, without our consent, adjust the borrowing base semiannually or in
situations where we purchase or sell assets or issue debt securities. If our
borrowings under the senior credit facility exceed the borrowing base, the
lenders may require that we repay the excess. If this were to occur, we might
have to sell assets or seek financing from other sources. Sales of assets could
further reduce the amount of our borrowing base. We cannot assure you that we
would be successful in selling assets or arranging substitute financing. If we
were not able to repay borrowings under our senior credit facility to reduce the
outstanding amount to less than the borrowing base, we would be in default under
our senior credit facility. For a description of our senior credit facility and
its principal terms and conditions, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
OUR RESERVE INFORMATION REPRESENTS ESTIMATES THAT MAY TURN OUT TO BE INCORRECT
IF THE ASSUMPTIONS UPON WHICH THESE ESTIMATES ARE BASED ARE INACCURATE. ANY
MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS WILL
MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES. The process
of estimating oil and gas reserves is complex. It requires interpretations of
available technical data and various assumptions, including assumptions relating
to economic factors. Any significant inaccuracies in these interpretations or
assumptions could materially affect the estimated quantities and present value
of reserves shown in this prospectus.
In order to prepare these estimates, we must project production rates and the
timing of development expenditures. The assumptions regarding the timing and
costs to commence production from our deepwater wells used in preparing our
reserves are often subject to revisions over time as described under "our
deepwater operations have special operational risks that may negatively affect
the value of those assets." We must also analyze available geological,
geophysical, production and engineering data, the extent, quality and
reliability of which can vary. The process also requires economic assumptions,
such as oil and gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. Therefore, estimates of oil and
gas reserves are inherently imprecise. Actual future production, oil and gas
prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable oil and gas reserves most likely will vary from our
estimates. Any significant variance could materially affect the estimated
quantities and present value of reserves shown in this prospectus. In addition,
we may adjust estimates of proved reserves to reflect production history,
results of exploration and development, prevailing oil and gas prices and other
factors, many of which are beyond our control.
You should not assume that the present value of future net cash flows from our
proved reserves referred to in this prospectus is the current market value of
our estimated oil and gas reserves. In accordance with SEC requirements, we
generally base the estimated discounted future net cash flows from our proved
reserves on
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prices and costs on the date of the estimate. Actual future prices and costs may
differ materially from those used in the present value estimate.
Information about reserves constitutes forward-looking information. See
"Forward-Looking Statements" for information regarding forward-looking
information. The discounted present value of our oil and gas reserves is
prepared in accordance with guidelines established by the SEC. A purchaser of
reserves would use numerous other factors to value our reserves. The discounted
present value of reserves, therefore, does not represent the fair market value
of those reserves.
On December 31, 2001, approximately 77.3% of the discounted present value of our
estimated net proved reserves were proved undeveloped. Substantially all of
these proved undeveloped reserves were attributable to our deepwater properties.
Development of these properties is subject to additional risks as described
above.
WEATHER, UNEXPECTED SUBSURFACE CONDITIONS, AND OTHER UNFORESEEN OPERATING
HAZARDS MAY ADVERSELY IMPACT OUR ABILITY TO CONDUCT BUSINESS. There are many
operating hazards in exploring for and producing oil and gas, including:
o our drilling operations may encounter unexpected formations or pressures,
which could cause damage to equipment or personal injury;
o we may experience equipment failures which curtail or stop production;
and
o we could experience blowouts or other damages to the productive
formations that may require a well to be re-drilled or other corrective
action to be taken.
In addition, any of the foregoing may result in environmental damages for which
we will be liable. Moreover, a substantial portion of our operations are
offshore and are subject to a variety of risks peculiar to the marine
environment such as capsizings, collisions, hurricanes and other adverse weather
conditions. These conditions can cause substantial damage to facilities and
interrupt production. Offshore operations are also subject to more extensive
governmental regulation.
We cannot assure you that we will be able to maintain adequate insurance at
rates we consider reasonable to cover our possible losses from operating
hazards. The occurrence of a significant event not fully insured or indemnified
against could materially and adversely affect our financial condition and
results of operations.
WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT FROM
PRICE INCREASES. Part of our business strategy is to reduce our exposure to the
volatility of oil and gas prices by hedging a portion of our production. In a
typical hedge transaction, we will have the right to receive from the other
parties to the hedge the excess of the fixed price specified in the hedge over a
floating price based on a market index, multiplied by the quantity hedged. If
the floating price exceeds the fixed price, we are required to pay the other
parties this difference multiplied by the quantity hedged. We are required to
pay the difference between the floating price and the fixed price when the
floating price exceeds the fixed price regardless of whether we have sufficient
production to cover the quantities specified in the hedge. Significant
reductions in production at times when the floating price exceeds the fixed
price could require us to make payments under the hedge agreements even though
such payments are not offset by sales of production. Hedging will also prevent
us from receiving the full advantage of increases in oil or gas prices above the
fixed amount specified in the hedge. See "Quantitative and Qualitative
Disclosures About Market Risks" for a discussion of our hedging practices.
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COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
AND COULD NEGATIVELY IMPACT PRODUCTION. Our operations are subject to numerous
laws and regulations governing the operation and maintenance of our facilities
and discharge of materials into the environment or otherwise relating to
environmental protection. For a discussion of the material regulations
applicable to us, see "Federal Regulations," "State Regulations," and
"Environmental Regulations." These laws and regulations may:
o require that we acquire permits before commencing drilling;
o restrict the substances that can be released into the environment in
connection with drilling and production activities;
o limit or prohibit drilling activities on protected areas such as wetlands
or wilderness areas; and
o require remedial measures to mitigate pollution from former operations,
such as dismantling abandoned production facilities.
Under these laws and regulations, we could be liable for personal injury and
clean-up costs and other environmental and property damages, as well as
administrative, civil and criminal penalties. We maintain limited insurance
coverage for sudden and accidental environmental damages. We do not believe that
insurance coverage for environmental damages that occur over time is available
at a reasonable cost. Also, we do not believe that insurance coverage for the
full potential liability that could be caused by sudden and accidental
environmental damages is available at a reasonable cost. Accordingly, we may be
subject to liability or we may be required to cease production from properties
in the event of environmental damages.
FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION AND OUR
FINANCIAL RESULTS. The ability to market oil and gas from our wells depends upon
numerous factors beyond our control. These factors include:
o the extent of domestic production and imports of oil and gas;
o the proximity of the gas production to gas pipelines;
o the availability of pipeline capacity;
o the demand for oil and gas by utilities and other end users;
o the availability of alternative fuel sources;
o the effects of inclement weather;
o state and federal regulation of oil and gas marketing; and
o federal regulation of gas sold or transported in interstate commerce.
Because of these factors, we may be unable to market all of the oil or gas we
produce. In addition, we may be unable to obtain favorable prices for the oil
and gas we produce.
IF OIL AND GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE WRITEDOWNS. We may be
required to writedown the carrying value of our oil and gas properties when oil
and gas prices are low or if we have substantial downward adjustments to our
estimated net proved reserves, increases in our estimates of development costs
or deterioration in our exploration results. Under the full-cost method we use
to account for our oil and gas properties, the net capitalized costs of our oil
and gas properties may not exceed the present value, discounted at 10%, of
future net cash flows from estimated net proved reserves, using period end oil
and gas prices or prices as of the date of our auditor's report, plus the lower
of cost or fair market value of our unproved properties. If net capitalized
costs of our oil and gas properties exceed this limit, we must charge the amount
of the excess to earnings. This type of charge will not affect our cash flows,
but will reduce the book value of our stockholders' equity. We review the
carrying value of our properties
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quarterly, based on prices in effect as of the end of each quarter or at the
time of reporting our results. Once incurred, a writedown of oil and gas
properties is not reversible at a later date, even if prices increase.
FORWARD-LOOKING STATEMENTS
In this report, we have made many forward-looking statements. We cannot assure
you that the plans, intentions or expectations upon which our forward-looking
statements are based will occur. Our forward-looking statements are subject to
risks, uncertainties and assumptions, including those discussed elsewhere in
this report. Forward-looking statements include statements regarding:
o our oil and gas reserve quantities, and the discounted present value of
these reserves;
o the amount and nature of our capital expenditures;
o drilling of wells;
o the timing and amount of future production and operating costs;
o business strategies and plans of management; and
o prospect development and property acquisitions.
Some of the risks, which could affect our future results and could cause results
to differ materially from those expressed in our forward-looking statements
include:
o general economic conditions;
o the volatility of oil and natural gas prices;
o the uncertainty of estimates of oil and natural gas reserves;
o the impact of competition;
o the availability and cost of seismic, drilling and other equipment;
o operating hazards inherent in the exploration for and production of oil
and natural gas;
o difficulties encountered during the exploration for and production of oil
and natural gas;
o difficulties encountered in delivering oil and natural gas to commercial
markets;
o changes in customer demand and producers' supply;
o the uncertainty of our ability to attract capital;
o compliance with, or the effect of changes in, the extensive governmental
regulations regarding the oil and natural gas business;
o actions of operators of our oil and gas properties; and
o weather conditions.
The information contained in this report, including the information set forth
under the heading "Risk Factors," identifies additional factors that could
affect our operating results and performance. We urge you to carefully consider
these factors and the other cautionary statements in this report. Our
forward-looking statements speak only as of the date made, and we have no
obligation to update these forward-looking statements.
CORPORATE OFFICES
Our headquarters are located in Natchez, Mississippi, in approximately 51,500
square feet of owned space. In late 2000, we opened a field office in Houston,
Texas, staffed with recently hired technical professionals, to enhance
exploration and development efforts. We also maintain owned or leased field
offices in the area of the major fields in which we operate properties or have a
significant interest. Replacement of any of our leased offices would not result
in material expenditures by us as alternative locations to our leased space are
anticipated to be readily available.
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EMPLOYEES
We had 103 employees as of December 31, 2001, none of whom are currently
represented by a union. We believe that we have good relations with our
employees. We employ nine petroleum engineers and eight petroleum geoscientists.
FEDERAL REGULATIONS
SALES OF NATURAL GAS. Effective January 1, 1993, the Natural Gas Wellhead
Decontrol Act deregulated prices for all "first sales" of natural gas. Thus, all
sales of gas by the Company may be made at market prices, subject to applicable
contract provisions.
TRANSPORTATION OF NATURAL GAS. The rates, terms and conditions applicable to the
interstate transportation of natural gas by pipelines are regulated by the
Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA"),
as well as under section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985,
the FERC has implemented regulations intended to make natural gas transportation
more accessible to gas buyers and sellers on an open-access, non-discriminatory
basis.
The FERC has announced several important transportation-related policy
statements and rule changes, including a statement of policy and final rule
issued February 25, 2000 concerning alternatives to its traditional
cost-of-service rate-making methodology to establish the rates interstate
pipelines may charge for their services. The final rule revises FERC's pricing
policy and current regulatory framework to improve the efficiency of the market
and further enhance competition in natural gas markets.
With respect to the transportation of natural gas on or across the Outer
Continental Shelf ("OCS"), the FERC requires, as part of its regulation under
the Outer Continental Shelf Lands Act, that all pipelines provide open and
non-discriminatory access to both owner and non-owner shippers. Although to date
the FERC has imposed light-handed regulation on off-shore facilities that meet
its traditional test of gathering status, it has the authority to exercise
jurisdiction under the Outer Continental Shelf Lands Act ("OCSLA") over
gathering facilities, if necessary, to permit non-discriminatory access to
service. For those facilities transporting natural gas across the OCS that are
not considered to be gathering facilities, the rates, terms, and conditions
applicable to this transportation are regulated by FERC under the NGA and NGPA,
as well as the OCSLA.
SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil and condensate can be
made by the Company at market prices not subject at this time to price controls.
The price that the Company receives from the sale of these products will be
affected by the cost of transporting the products to market. The rates, terms,
and conditions applicable to the interstate transportation of oil and related
products by pipelines are regulated by the FERC under the Interstate Commerce
Act. As required by the Energy Policy Act of 1992, the FERC has revised its
regulations governing the rates that may be charged by oil pipelines. The new
rules, which were effective January 1, 1995, provide a simplified, generally
applicable method of regulating such rates by use of an index for setting rate
ceilings. The FERC will also, under defined circumstances, permit alternative
ratemaking methodologies for interstate oil pipelines such as the use of cost of
service rates, settlement rates, and market-based rates. Market-based rates will
be permitted to the extent the pipeline can demonstrate that it lacks
significant market power in the market in which it proposes to charge
market-based rates. The cumulative effect that these rules may have on moving
the Company's production to market cannot yet be determined.
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With respect to the transportation of oil and condensate on or across the OCS,
the FERC requires, as part of its regulation under the OCSLA, that all pipelines
provide open and non-discriminatory access to both owner and non-owner shippers.
Accordingly, the FERC has the authority to exercise jurisdiction under the
OCSLA, if necessary, to permit non-discriminatory access to service.
LEGISLATIVE PROPOSALS. In the past, Congress has been very active in the area of
natural gas regulation. There are legislative proposals pending in Congress and
in various state legislatures which, if enacted, could significantly affect the
petroleum industry. At the present time it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on the Company's
operations.
FEDERAL, STATE OR INDIAN LEASES. In the event the Company conducts operations on
federal, state or Indian oil and gas leases, such operations must comply with
numerous regulatory restrictions, including various nondiscrimination statutes,
royalty and related valuation requirements, and certain of such operations must
be conducted pursuant to certain on-site security regulations and other
appropriate permits issued by the Bureau of Land Management ("BLM") or Minerals
Management Service ("MMS") or other appropriate federal or state agencies.
The Company's OCS leases in federal waters are administered by the MMS and
require compliance with detailed MMS regulations and orders. The MMS has
promulgated regulations implementing restrictions on various production-related
activities, including restricting the flaring or venting of natural gas. Under
certain circumstances, the MMS may require Company operations on federal leases
to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition and
operations. On March 15, 2000, the MMS issued a final rule effective June 1,
2000 which amends its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. Among other matters, this
rule amends the valuation procedure for the sale of federal royalty oil by
eliminating posted prices as a measure of value and relying instead on arm's
length sales prices and spot market prices as market value indicators. Because
the Company sells its production in the spot market and therefore pays royalties
on production from federal leases, it is not anticipated that this final rule
will have any substantial impact on the Company.
The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect
ownership of any interest in federal onshore oil and gas leases by a foreign
citizen of a country that denies "similar or like privileges" to citizens of the
United States. Such restrictions on citizens of a "non-reciprocal" country
include ownership or holding or controlling stock in a corporation that holds a
federal onshore oil and gas lease. If this restriction is violated, the
corporation's lease can be canceled in a proceeding instituted by the United
States Attorney General. Although the regulations of the BLM (which administers
the Mineral Act) provide for agency designations of non-reciprocal countries,
there are presently no such designations in effect. The Company owns interests
in numerous federal onshore oil and gas leases. It is possible that holders of
equity interests in the Company may be citizens of foreign countries, which at
some time in the future might be determined to be non-reciprocal under the
Mineral Act.
STATE REGULATIONS
Most states regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. The rate of production may be regulated and the maximum daily
production allowable from both oil and gas wells may be established on a market
demand or conservation basis or both.
11
The Company may enter into agreements relating to the construction or operation
of a pipeline system for the transportation of natural gas. To the extent that
such gas is produced, transported and consumed wholly within one state, such
operations may, in certain instances, be subject to the jurisdiction of such
state's administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates which the Company could charge
for gas, the transportation of gas, and the costs of construction and operation
of such pipeline would be impacted by the rules and regulations governing such
matters, if any, of such administrative authority. Further, such a pipeline
system would be subject to various state and/or federal pipeline safety
regulations and requirements, including those of, among others, the Department
of Transportation. Such regulations can increase the cost of planning,
designing, installation and operation of such facilities. The impact of such
pipeline safety regulations would not be any more adverse to the Company than it
would be to other similar owners or operators of such pipeline facilities.
ENVIRONMENTAL REGULATIONS
GENERAL. The Company's activities are subject to federal, state and local laws
and regulations governing environmental quality and pollution control. Although
no assurances can be made, the Company believes that, absent the occurrence of
an extraordinary event, compliance with existing federal, state and local laws,
rules and regulations regulating the release of materials in the environment or
otherwise relating to the protection of the environment will not have a material
effect upon the capital expenditures, earnings or the competitive position of
the Company with respect to its existing assets and operations. The Company
cannot predict what effect additional regulation or legislation, enforcement
policies thereunder, and claims for damages to property, employees, other
persons and the environment resulting from the Company's operations could have
on its activities.
Activities of the Company with respect to natural gas facilities, including the
operation and construction of pipelines, plants and other facilities for
transporting, processing, treating or storing natural gas and other products,
are subject to stringent environmental regulation by state and federal
authorities including the United States Environmental Protection Agency ("EPA").
Such regulation can increase the cost of planning, designing, installation and
operation of such facilities. In most instances, the regulatory requirements
relate to water and air pollution control measures. Although the Company
believes that compliance with environmental regulations will not have a material
adverse effect on it, risks of substantial costs and liabilities are inherent in
oil and gas production operations, and there can be no assurance that
significant costs and liabilities will not be incurred. Moreover, it is possible
that other developments, such as stricter environmental laws and regulations,
and claims for damages to property or persons resulting from oil and gas
production, would result in substantial costs and liabilities to the Company.
SOLID AND HAZARDOUS WASTE. The Company owns or leases numerous properties that
have been used for production of oil and gas for many years. Although the
Company has utilized operating and disposal practices standard in the industry
at the time, hydrocarbons or other solid wastes may have been disposed or
released on or under these properties. In addition, many of these properties
have been operated by third parties. The Company had no control over such
entities' treatment of hydrocarbons or other solid wastes and the manner in
which such substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under these new laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed or released by
prior owners or operators) or property contamination (including groundwater
contamination by prior owners or operators) or to perform remedial plugging
operations to prevent future contamination.
The Company generates wastes, including hazardous wastes, that are subject to
the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA has limited the disposal
12
options for certain hazardous wastes and is considering the adoption of stricter
disposal standards for nonhazardous wastes. Furthermore, it is possible that
certain wastes currently exempt from treatment as "hazardous wastes" generated
by the Company's oil and gas operations may in the future be designated as
"hazardous wastes" under RCRA or other applicable statutes, and therefore may be
subject to more rigorous and costly disposal requirements.
SUPERFUND. The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons with respect to the release of a "hazardous substance" into the
environment. These persons include the owner and operator of a site and persons
that disposed or arranged for the disposal of the hazardous substances found at
a site. CERCLA also authorizes the EPA and, in some cases, third parties to take
actions in response to threats to the public health or the environment and to
seek to recover from the responsible classes of persons the costs of such
action. Neither the Company nor its predecessors has been designated as a
potentially responsible party by the EPA under CERCLA with respect to any such
site.
OIL POLLUTION ACT. The Oil Pollution Act of 1990 (the "OPA") and regulations
thereunder impose a variety of regulations on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from such
spills in United States waters. A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages. While liability limits apply in some circumstances, a party cannot take
advantage of liability limits if the spill was caused by gross negligence or
willful misconduct or resulted from violation of a federal safety, construction
or operating regulation. If the party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. Few defenses exist
to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. Certain amendments to the OPA that were enacted in 1996 require owners
and operators of offshore facilities that have a worst case oil spill potential
of more than 1,000 barrels to demonstrate financial responsibility in amounts
ranging from $10 million in specified state waters and $35 million in federal
OCS waters, with higher amounts, up to $150 million based upon worst case
oil-spill discharge volume calculations. The Company believes that it currently
has established adequate proof of financial responsibility for its offshore
facilities.
AIR EMISSIONS. The operations of the Company are subject to local, state and
federal regulations for the control of emissions from sources of air pollution.
Administrative enforcement actions for failure to comply strictly with air
regulations or permits are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could require the Company to forego construction or operation of certain air
emission sources, although the Company believes that in such case it would have
enough permitted or permittable capacity to continue its operations without a
material adverse effect on any particular producing field.
OSHA. The Company is subject to the requirements of the Federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the Federal Superfund Amendment and Reauthorization Act and similar state
statutes require the Company to organize and/or disclose information about
hazardous materials used or produced in its operations. Certain of this
information must be provided to employees, state and local governmental
authorities and local citizens.
13
Management believes that the Company is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements would not have a material adverse impact on the Company.
ITEM 2. PROPERTIES
We are engaged in the exploration, development, acquisition and production of
oil and gas properties and natural gas transmission and provide oil and gas
property management services for other investors. Our properties are
concentrated offshore in the Gulf of Mexico and onshore, primarily, in Louisiana
and Alabama. We have historically grown our reserves and production by focusing
primarily on low to moderate risk exploration and acquisition opportunities in
the Gulf of Mexico Shelf area. Over the last several years, we have expanded our
area of exploration to include the Gulf of Mexico Deepwater area. As of December
31, 2001, our estimated net proved reserves totaled 30.2 million barrels of oil
("MBbl") and 121.5 billion cubic feet of natural gas ("Bcf"), with a pre-tax
present value, discounted at 10%, of the estimated future net revenues based on
constant prices in effect at year-end ("Discounted Cash Flow") of $272.1
million. Gas constitutes approximately 40% of our total estimated proved
reserves and approximately 17% of our reserves are proved producing reserves.
14
SIGNIFICANT PROPERTIES
The following table shows discounted cash flows and estimated net proved oil and
gas reserves by major field, within focus area, for our nine largest fields and
for all other properties combined at December 31, 2001.
ESTIMATED NET PROVED RESERVES PRE-TAX
---------------------------------- DISCOUNTED
OIL GAS TOTAL PRESENT VALUE
OPERATOR (MBBLS) (MMCF) (MMCFE) ($000)
-------- ------- -------- --------- -------------
(b) (b) (a)(b)
GULF OF MEXICO SHELF:
Mobile Block 864 Area Callon -- 41,054 41,054 $ 45,496
Main Pass Block 26 SL 15827 Callon 40 915 1,152 693
East Cameron Block 294 Unocal 14 2,860 2,945 3,598
High Island Block A-494
"Snapper" PetroQuest -- 4,614 4,614 7,285
GULF OF MEXICO DEEPWATER:
Garden Banks Blocks 738/782/826/827
"Entrada" BP Amoco 7,823 29,341 76,279 54,218
Mississippi Canyon 538/582
"Medusa" Murphy 9,507 9,374 66,415 68,028
Garden Banks Block 341
"Habanero" Shell 4,736 12,270 40,685 46,737
Ewing Bank Block 994
"Boomslang" Murphy 7,244 13,040 56,505 38,917
ONSHORE AND OTHER:
Big Escambia Creek Exxon 412 1,027 3,500 2,638
Other Various 433 6,958 9,557 4,443
------- -------- -------- --------
TOTAL PROVED RESERVES 30,209 121,453 302,706 $272,053
======= ======== ======== ========
(a) Represents the present value of future net cash flows before deduction of
federal income taxes, discounted at 10%, attributable to estimated net
proved reserves as of December 31, 2001, as set forth in the Company's
reserve reports prepared by its independent petroleum reserve engineers,
Huddleston & Co., Inc. of Houston, Texas.
(b) The estimates include reserve volumes of approximately 1.2 Bcf with a
pre-tax discounted present value of $2.9 million that are dedicated to a
volumetric production payment.
15
GULF OF MEXICO DEEPWATER
Entrada, Garden Banks Blocks 738/782/826/827
The Entrada discovery is located in approximately 4,500 feet of water in the
Gulf of Mexico. Two wells and seven sidetracks have been drilled to date on
Garden Banks 782 on a northwest plunging salt ridge along the southern edge of
the Entrada Basin. Multiple stacked amplitudes trapped against a salt or fault
interface characterize the Entrada Area. We own a 20% working interest in this
discovery with BP Amoco, the operator, holding the remaining working interest.
Information obtained in a data swap with another exploration company that has
announced a similar discovery adjacent to Entrada, is being incorporated into
the Entrada development plans. The owners of the adjacent discovery have
announced their plans to construct production facilities to enable them to be a
regional off-take point in Southeastern Garden banks. These plans include
handling third party tie-ins, which we expect to include Entrada. First
production from their discovery is expected in late 2004.
Medusa, Mississippi Canyon Block 538/582
Medusa was our third deepwater discovery and was announced in September 1999. We
drilled the initial test well in 2,235 feet of water to a total depth of 16,241
feet and encountered over 120 feet of pay in two intervals. We performed
subsequent sidetrack drilling from the well bore to determine the extent of the
discovery. We drilled a second successful well in the first quarter of 2000 to
further delineate the extent of the pay intervals. We own a 15% working
interest, Murphy, the operator, owns a 60% interest and British-Borneo
Petroleum, Inc. owns the remaining 25%.
In 2001 a delineation program began which included four development wells and
one sidetrack. These will provide the take points for initial production. Also
in 2001, the operator submitted an Authorization For Expenditure for a floating
production system at Medusa and awarded the contract to J. Ray McDermott, Inc.
Construction of the facility is in progress. Upon completion, it is estimated
the production facility will have the capacity to handle 40,000 barrels of crude
oil and 110 million cubic feet of natural gas per day. First production is
anticipated in late 2002 or early 2003.
Habanero, Garden Banks Block 341
During February 1999 the initial test well on our Habanero prospect encountered
over 200 feet of net pay. Located in 2,000 feet of water, the well was drilled
to a measured depth of 21,158 feet. This discovery was our second deepwater
success. We own an 11.25% working interest in the well. It is operated by Shell
Deepwater Development Inc., which owns a 55% working interest, with the
remaining working interest being owned by Murphy.
A field delineation program began in midyear 2001, which included sidetracking
the existing well with three sidetracks. Development plans include sub-sea
completion and tie back to an existing production facility in the area. The
operator has submitted to the co-owners a development schedule with estimated
initial production in November 2003.
Boomslang, Ewing Bank Block 994
Located in 900 feet of water, the Boomslang prospect was drilled to a total
depth of 12,955 feet and encountered 185 net feet of oil pay in three separate
zones. In December 1999, we purchased from Santos
16
USA Corporation an additional 20% working interest in the Boomslang deepwater
discovery on Ewing Bank Block 994 for $7.3 million. This brought our total
working interest in the well to 55%.
A complete field study was initiated in 2001, which resulted in a delineation
and development plan that is scheduled to commence by the second half of 2003.
Plans include a sub-sea completion with a tieback to an existing shelf
production facility. Plans could be altered if the Sidewinder prospect, located
immediately to the southeast of Boomslang on Ewing Bank Block 995 and Green
Canyon Blocks 24 and 25, is drilled and results in a discovery. This could
result in the need for a stand-alone production facility to serve both Boomslang
and Sidewinder. We own a 15% working interest in the Ewing Bank Block 995 and
Green Canyon Blocks 24 and 25 leases.
GULF OF MEXICO SHELF
Mobile Block 864 Area
The Mobile Block 864 Area is located offshore Alabama in the federal waters of
the Outer Continental Shelf area. We consummated five acquisitions in this area
for a total of $63.8 million. In total, we acquired an average 81.6% working
interest in seven blocks, a 66.4% working interest in the Mobile Block 864 Area
unit and the unit production facilities, and a 100% working interest in three
producing wells. We have been appointed operator of the Mobile Block 864 unit
and three other wells. Net average daily production during 2001 was 18 MMcf per
day.
During the first quarter of 2001, we drilled the Mobile Block 908 #4, an
exploratory well, and the Mobile Block 864 A-3, a development well, in our
Mobile Block 864 area, both of which were successful. During the fourth quarter
of 2000, the Company performed acid stimulation on three wells. The 908 #4 well
commenced production during February 2001 and the A-3 well commenced production
during March 2001. These projects increased production in this area during 2001.
In the fourth quarter of 2001, we initiated a production acceleration program
for Mobile Blocks 952, 953 and 955, which currently produce through the Mobile
Block 864 unit facilities. Plans include at least one acceleration well, which
was successfully drilled in the fourth quarter of 2001, stand-alone production
facilities and the rerouting of production flow lines. The project is scheduled
to be completed late in the first quarter or early second quarter 2002.
East Cameron Block 294
In the first quarter of 2001, this prospect was drilled at a water depth of 186
feet and encountered approximately 80 feet of pay in two intervals at
approximately 3,500 and 4,200 feet. First production commenced in the first
quarter of 2002 at a net average daily rate of 6 MMcf. We own a 50% working
interest in this well and Unocal, the operator, owns the remaining interest.
Main Pass 26 / SL 15827 #1
We negotiated a farm-in agreement in 1998 for a 97% working interest after
identifying a prospect on Main Pass Block 26 based upon a seismic survey we
completed in 1996. In August 1998, we drilled the SL 15827 well to a depth of
10,450 feet. This well produced during 2001 at a net average daily rate of 2
MMcf of gas and 85 Bbls of oil. We operate this property.
17
Snapper, High Island Block A-494
In January 1999, we announced a discovery on our Snapper prospect, which was
drilled to a total depth of 8,800 feet. In the second half of 2001, the well was
sidetracked and a second well was drilled to test the same zone in an adjacent
fault block. The second well had over 100 feet of pay which is fault separated
from the initial well with no apparent water. We own a 50% working interest in
these wells, which are operated by PetroQuest Energy. The wells began production
in the third quarter of 2001, and averaged 7 net MMcf per day for December 2001.
ONSHORE
We own various small royalty and working interests in several onshore areas,
which as of December 31, 2001 had total net proved reserves of 9.4 Bcfe with a
discounted present value of $5.0 million. Over 50% of these reserves and their
related discounted present value were attributable to our interest in the Big
Escambia Creek gas field located in south Alabama and operated by Exxon/Mobil.
OIL AND GAS RESERVES
The following table sets forth certain information about our estimated proved
reserves as of the dates set forth below.
YEARS ENDED DECEMBER 31,
----------------------------------------------
2001(a) 2000(a) 1999(a)
---------- ---------- ----------
(IN THOUSANDS)
Proved developed:
Oil (Bbls) 885 2,192 1,376
Gas (Mcf) 52,375 67,463 82,109
Proved undeveloped:
Oil (Bbls) 29,324 31,190 22,458
Gas (Mcf) 69,078 65,940 34,326
Total proved:
Oil (Bbls) 30,209 33,382 23,834
Gas (Mcf) 121,453 133,403 116,435
Estimated pre-tax future net cash flows $ 473,896 $1,610,320 $ 528,659
========== ========== ==========
Pre-tax discounted present value $ 272,053 $ 939,325 $ 296,513
========== ========== ==========
Standardized measure of discounted future
net cash flows $ 254,857 $ 671,197 $ 256,322
========== ========== ==========
(a) The estimates include reserve volumes of approximately 5.8 Bcf, $12.1
million of pre-tax future net cash flows and $10.7 million of pre-tax
discounted present value in 1999, 3.5 Bcf, $31.8 million of pre-tax future
net cash flows and $29.5 million of pre-tax discounted present value in
2000, and 1.2 Bcf, $2.9 million of pre-tax discounted present value in 2001,
attributable to a volumetric production payment. Standardized measure of
discounted future net cash flows does not include any volumes or cash flows
associated with the volumetric production payment.
18
Our independent reserve engineers, Huddleston & Co., Inc. prepared the estimates
of the proved reserves and the future net cash flows and present value thereof
attributable to such proved reserves. Reserves were estimated using oil and gas
prices and production and development costs in effect on December 31 of each
such year, without escalation, and were otherwise prepared in accordance with
Securities and Exchange Commission regulations regarding disclosure of oil and
gas reserve information.
There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond our control or the control of the
reserve engineers. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner, and the accuracy of any reserve or cash flow estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Estimates by different engineers often vary, sometimes
significantly. In addition, physical factors, such as the results of drilling,
testing and production subsequent to the date of an estimate, as well as
economic factors, such as an increase or decrease in product prices that renders
production of such reserves more or less economic, may justify revision of such
estimates. Accordingly, reserve estimates are different from the quantities of
oil and gas that are ultimately recovered.
We have not filed any reports with other federal agencies which contain an
estimate of total proved net oil and gas reserves.
PRODUCTIVE WELLS
The following table sets forth the wells we have drilled and completed during
the periods indicated. All such wells were drilled in the continental United
States including federal and state waters in the Gulf of Mexico.
YEARS ENDED DECEMBER 31,
------------------------
2001 2000 1999
---- ---- ----
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Development:
Oil 6 .45 2 .35 -- --
Gas 4 3.17 -- -- -- --
Non-productive -- -- -- -- -- --
----- ----- ----- ----- ----- -----
Total 10 3.62 2 .35 -- --
===== ===== ===== ===== ===== =====
Exploration:
Oil -- -- 1 .20 2 0.26
Gas 3 2.00 2 2.00 5 3.79
Non-productive 12 5.77 6 2.29 2 1.20
----- ----- ----- ----- ----- -----
Total 15 7.77 9 4.49 9 5.25
===== ===== ===== ===== ===== =====
We owned working and royalty interests in approximately 246 gross (6.7 net)
producing oil and 288 gross (29.9 net) producing gas wells as of December 31,
2001. A well is categorized as an oil well or a natural gas well based upon the
ratio of oil to gas reserves on a Mcfe basis. However, some of our wells produce
both oil and gas. At December 31, 2001, we had 3 gross (.53 net) wells with
multiple completions. At December 31, 2001, we had 1 gross (.15 net) development
oil well and 1 gross (1 net) exploratory gas well in progress.
19
LEASEHOLD ACREAGE
The following table shows our approximate developed and undeveloped (gross and
net) leasehold acreage as of December 31, 2001.
LEASEHOLD ACREAGE
-----------------
DEVELOPED UNDEVELOPED
--------------------- ---------------------
LOCATION GROSS NET GROSS NET
-------- -------- -------- -------- --------
Alabama 19,451 16,635 80 2
Louisiana 8,178 5,221 3,795 1,212
Other States 860 388 934 744
Federal Waters 127,966 85,196 341,995 117,748
-------- -------- -------- --------
Total 156,455 107,440 346,804 119,706
======== ======== ======== ========
As of December 31, 2001, we owned various royalty and overriding royalty
interests in 1,336 net developed and 6,862 undeveloped acres. In addition, we
owned 5,184 developed and 120,816 undeveloped mineral acres.
MAJOR CUSTOMERS
Our production is sold on month-to-month contracts at prevailing prices. The
following table identifies customers to whom we sold a significant percentage of
our total oil and gas production during each of the twelve-month periods ended:
DECEMBER 31,
------------
2001 2000 1999
---- ---- ----
Adams Resources Marketing, Ltd. -- 14% 16%
Columbia Energy Services -- -- 29%
Dynegy 8% -- 12%
Prior Energy Corporation 20% -- --
Reliant Energy Services 49% 37% --
Unocal Exploration Corporation -- 8% --
Because alternative purchasers of oil and gas are readily available, we believe
that the loss of any of these purchasers would not result in a material adverse
effect on our ability to market future oil and gas production.
TITLE TO PROPERTIES
We believe that the title to our oil and gas properties is good and defensible
in accordance with standards generally accepted in the oil and gas industry,
subject to such exceptions which, in our opinion are not so material as to
detract substantially from the use or value of such properties. Our properties
are typically subject, in one degree or another, to one or more of the
following: royalties and other burdens and obligations, express or implied,
under oil and gas leases; overriding royalties and other burdens created by us
or our predecessors in title; a variety of contractual obligations (including,
in some cases, development obligations) arising under operating agreements,
farmout agreements, production sales contracts and other agreements that
20
may affect the properties or their titles; back-ins and reversionary interests
existing under purchase agreements and leasehold assignments; liens that arise
in the normal course of operations, such as those for unpaid taxes, statutory
liens securing obligations to unpaid suppliers and contractors and contractual
liens under operating agreements; pooling, unitization and communitization
agreements, declarations and orders; and easements, restrictions, rights-of-way
and other matters that commonly affect property. To the extent that such burdens
and obligations affect our rights to production revenues, they have been taken
into account in calculating our net revenue interests and in estimating the size
and value of our reserves. We believe that the burdens and obligations affecting
our properties are conventional in the industry for properties of the kind owned
by us.
ITEM 3. LEGAL PROCEEDINGS
We are a defendant in various legal proceedings and claims, which arise in the
ordinary course of our business. We do not believe the ultimate resolution of
any such actions will have a material affect on our financial position or
results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth
quarter of 2001.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock trades on the New York Stock Exchange under the symbol "CPE".
The following table sets forth the high and low sale prices per share as
reported for the periods indicated.
QUARTER ENDED HIGH LOW
------------- -------- -------
2000:
First quarter $ 15.625 $ 9.625
Second quarter 16.500 10.625
Third quarter 17.625 12.500
Fourth quarter 17.188 12.938
2001:
First quarter $ 16.688 $10.000
Second quarter 13.220 10.650
Third quarter 11.820 5.900
Fourth quarter 7.200 5.350
As of March 18, 2002, there were approximately 5,036 common stockholders of
record.
We have not paid dividends on our common stock and intend to retain our cash
flow from operations, net of preferred stock dividends, for the future operation
and development of our business. In addition, our primary credit facility and
the terms of our outstanding subordinated debt restrict payments of dividends on
our common stock.
21
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth, as of the dates and for the periods indicated,
selected financial information about us. The financial information for each of
the five years in the period ended December 31, 2001 have been derived from our
audited Consolidated Financial Statements for such periods. The information
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements and notes thereto. The following information is not necessarily
indicative of our future results.
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales $ 60,010 $ 56,310 $ 37,140 $ 35,624 $ 42,130
Interest and other 1,742 1,767 1,853 2,094 1,508
---------- ---------- ---------- ---------- ----------
Total revenues 61,752 58,077 38,993 37,718 43,638
---------- ---------- ---------- ---------- ----------
Costs and expenses:
Lease operating expenses 11,252 9,339 7,536 7,817 8,123
Depreciation, depletion and amortization 21,081 17,153 16,727 19,284 16,488
General and administrative 4,635 4,155 4,575 5,285 4,433
Writedown of Enron derivatives 9,186 -- -- -- --
Interest 12,805 8,420 6,175 1,925 1,957
Accelerated vesting and retirement benefits -- -- -- 5,761 --
Impairment of oil and gas properties -- -- -- 43,500 --
---------- ---------- ---------- ---------- ----------
Total costs and expenses 58,959 39,067 35,013 83,572 31,001
---------- ---------- ---------- ---------- ----------
Income (loss) from operations 2,793 19,010 3,980 (45,854) 12,637
Income tax expense (benefit) 977 6,463 1,353 (15,100) 4,200
---------- ---------- ---------- ---------- ----------
Net income (loss) 1,816 12,547 2,627 (30,754) 8,437
Preferred stock dividends 1,277 2,403 2,497 2,779 2,795
---------- ---------- ---------- ---------- ----------
Net income (loss) available to common shares $ 539 $ 10,144 $ 130 $ (33,533) $ 5,642
========== ========== ========== ========== ==========
Net income (loss) per common share:
Basic $ .04 $ .82 $ .01 $ (4.17) $ .91
Diluted $ .04 $ .80 $ .01 $ (4.17) $ .88
Shares used in computing net income (loss) per common share:
Basic 13,273 12,420 8,976 8,034 6,194
Diluted 13,366 12,745 9,075 8,034 6,422
BALANCE SHEET DATA (END OF PERIOD):
Oil and gas properties, net $ 343,158 $ 258,613 $ 194,365 $ 141,905 $ 150,494
Total assets $ 372,095 $ 301,569 $ 259,877 $ 181,652 $ 190,421
Long-term debt, less current portion $ 161,733 $ 134,000 $ 100,250 $ 78,250 $ 60,250
Stockholders' equity $ 147,224 $ 136,328 $ 124,380 $ 84,484 $ 113,701
We use the full-cost method of accounting. Under this method of accounting, our
net capitalized costs to acquire, explore and develop oil and gas properties may
not exceed the standardized measure of our proved reserves. If these capitalized
costs exceed a ceiling amount, the excess is charged to expense. As a result of
the significant decline in oil and gas prices, we recorded a non-cash impairment
expense related to our oil and gas properties in the amount of $43.5 million
during the fourth quarter of 1998.
22
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in an understanding of our
financial condition and results of operations. Our Financial Statements and
Notes thereto contain detailed information that should be referred to in
conjunction with the following discussion. See Item 8. "Financial Statements and
Supplementary Data."
GENERAL
Callon Petroleum Company has been engaged in the exploration, development,
acquisition and production of oil and gas properties since 1950. Our revenues,
profitability and future growth and the carrying value of our oil and gas
properties are substantially dependent on prevailing prices of oil and gas and
our ability to find, develop and acquire additional oil and gas reserves that
are economically recoverable. Our ability to maintain or increase our borrowing
capacity and to obtain additional capital on attractive terms is also influenced
by oil and gas prices.
Our estimated net proved oil and gas reserves decreased at December 31, 2001 to
303 billion cubic feet of natural gas equivalent (Bcfe). This represents a
decrease of 9% over previous year-end 2000 estimated proved reserves of 334
Bcfe. This decrease in 2001 is primarily due to production and revisions
exceeding exploration additions to the reserve base. These reserve estimates
include 1.2 Bcfe at December 31, 2001 and 3.5 Bcfe at December 31, 2000
dedicated to a volumetric production payment.
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond our control. These
factors include weather conditions in the United States, the condition of the
United States economy, the actions of the Organization of Petroleum Exporting
Countries, governmental regulation, political stability in the Middle East and
elsewhere, the foreign supply of crude oil and natural gas, the price of foreign
imports and the availability of alternate fuel sources. Any substantial and
extended decline in the price of crude oil or natural gas would have an adverse
effect on our carrying value of our proved reserves, borrowing capacity,
revenues, profitability and cash flows from operations. We use derivative
financial instruments (see Note 6 and Item 7A. "Quantitative and Qualitative
Disclosures About Market Risks") for price protection purposes on a limited
amount of our future production and do not use them for trading purposes. On a
Mcfe basis, natural gas represents 92% of the budgeted 2002 production and 40%
of proved reserves at year-end 2001.
Inflation has not had a material impact on us and is not expected to have a
material impact on us in the future.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
RECENT ACCOUNTING PRONOUNCEMENTS. In June 1998, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 133
("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities. The
Statement establishes accounting and reporting standards requiring that every
derivative instrument, including certain derivative instruments embedded in
other contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS 133 requires the Company to report
changes in the fair value of our derivative financial instruments that qualify
as cash flow hedges in other comprehensive income, a component of stockholders'
equity, until realized. We adopted SFAS 133 effective January 1, 2001.
In July 2001, the Financial Accounting Standards Board approved Statement of
Accounting Standards No. 143, Asset Retirement Obligations ("SFAS 143"). SFAS
143 will require that the fair value of abandonment
23
obligations be reflected as a liability, resulting in a corresponding increase
to the historical cost of the related assets and potentially an adjustment for
the cumulative effect of a change in accounting principle. This standard is
required to be adopted by us beginning no later that January 1, 2003. We have
not yet determined timing or the impact of the adoption of SFAS 143.
PROPERTY AND EQUIPMENT. We follow the full-cost method of accounting for oil and
gas properties whereby all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves, including certain overhead
costs, are capitalized. We include in such amounts the cost of drilling and
equipping productive wells, dry hole costs, lease acquisition costs, delay
rentals, interest capitalized on unevaluated leases and other costs related to
exploration and development activities. Our payroll and general and
administrative costs capitalized include salaries and related fringe benefits
paid to employees directly engaged in the acquisition, exploration and/or
development of oil and gas properties as well as other directly identifiable
general and administrative costs associated with such activities. Such
capitalized costs do not include any costs related to our production or our
general corporate overhead. Costs associated with unevaluated properties are
excluded from amortization. Unevaluated property costs are transferred to
evaluated property costs at such time as wells are completed on the properties,
the properties are sold or our management determines these costs have been
impaired and increase our depletion rates as they are transferred to evaluated
property.
Costs of properties, including future development and net future site
restoration, dismantlement and abandonment costs, which have proved reserves and
those which have been determined to be worthless, are depleted using the
unit-of-production method based on proved reserves. Increases in these costs
increase our depletion rates. Additions to reserves decrease our depletion
rates.
Under the full cost accounting rules of the SEC, we reviewed the carrying value
of our proved oil and gas properties each quarter on a country-by-country basis.
Under these rules, capitalized costs of proved oil and gas properties net of
accumulated depreciation, depletion and amortization (DD&A) and deferred income
taxes, may not exceed the present value of our estimated future net cash flows
from proved oil and gas reserves, discounted at 10 percent, plus the lower of
cost or fair value of unproved properties included in the costs being amortized,
net of related tax effects. These rules generally require pricing future oil and
gas production at the unescalated market price for oil and gas at the end of
each fiscal quarter and require a write-down if the "ceiling" is exceeded,
unless prices recover sufficiently before the date of our auditor's report.
Given the volatility of oil and gas prices, it is reasonably possible that our
estimates of discounted future net cash flows from proved oil and gas reserves
could change in the near term. If oil and gas priced decline significantly, even
if only for a short period of time, it is possible that writedowns of oil and
gas properties could occur in the future. Based on prices at December 31, 2001
we would have been required to writedown our assets by $37.5 million. However,
as of the date of our auditor's report, commodity prices increased sufficiently
to eliminate any writedown.
Upon the acquisition or discovery of oil and gas properties, we estimate the
future net costs to be incurred to dismantle, abandon and restore the property
using geological, engineering and regulatory data available. Such cost estimates
are periodically updated for changes in conditions and requirements. Such
estimated amounts are considered as part of the full cost pool subject to
amortization upon acquisition or discovery. Such costs are capitalized as oil
and gas properties as the actual restoration, dismantlement and abandonment
activities take place. These cost estimates, if revised upward for future
changes, could increase our depletion rate.
The estimates used to calculate our oil and gas reserves are imprecise and are
based on assumptions about future production levels, prices and future operating
costs. As a result, the quantity of our proved reserves may be subject to
downward or upward adjustment as additional information or analysis become
available. In addition, estimates of the economically recoverable oil and gas
reserves, classifications of such reserves,
24
and estimates of future net cash flows, prepared by different engineers or by
the same engineers at different times, may vary substantially. In particular,
the assumptions regarding the timing and costs to commence production from our
deepwater wells used in preparing our reserves are subject to revisions over
time. These assumptions could affect quantities used to calculate depletion and
any significant revisions to our reserves could impact our depletion
computations.
DERIVATIVES. We use derivative financial instruments for price protection
purposes on a limited amount of our future production and do not use them for
trading purposes. Such derivatives were accounted for in years prior to 2001 as
hedges and have been recognized as an adjustment to oil and gas sales in the
period in which they are related. Current accounting treatment is under SFAS
133.
LIQUIDITY AND CAPITAL RESOURCES
Our primary sources of capital are cash flows from operations, borrowings from
financial institutions and the sale of debt and equity securities. Net cash and
cash equivalents decreased during 2001 by $5.0 million. Cash provided from
operating activities during 2001 totaled $35.2 million. Dividends paid on
preferred stock were $1.3 million. Average debt outstanding was $164.9 million
during 2001 compared to $118.3 million in 2000. At December 31, 2001, we had
working capital of $.4 million, excluding current maturities of long-term debt
and liabilities to be refinanced.
In May 2001, we initiated a combination of offerings of equity and senior notes
to investors with proceeds to be used to call certain of our subordinated debt,
repay borrowings under our senior secured credit facility and to finance capital
expenditures. Subsequently, we withdrew our offer to sell the senior notes and
the equity sale was terminated. Approximately $358,000 of costs associated with
the withdrawn offering were expensed during the second quarter.
In early July of 2001, we closed a $95 million multiple advance term loan with a
private lender. We drew $45 million on July 3, 2001 and paid down our revolving
Credit Facility. We drew the remaining $50 million in December 2001. Under the
terms of the agreement, we also issued warrants for the purchase, at a nominal
exercise price, of 265,210 shares of our common stock to the lender and conveyed
an overriding royalty interest equal to 2% of our net interest in four of our
deepwater discoveries. The warrants and the overriding royalty interest were
earned by the lender based on the ratio of the amount of the loan proceeds
advanced to the total loan facility amount. This senior debt will mature March
31, 2005 and contains restrictions on certain types of future indebtedness and
dividends on common stock.
Effective October 31, 2000, we entered into a $75 million Credit Facility with
First Union National Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of our producing oil and gas properties and
guaranteed by our subsidiaries. The Credit Facility currently provides for a $50
million borrowing base ("Borrowing Base"), which is adjusted periodically on the
basis of a discounted present value of future net cash flows attributable to our
proved producing oil and gas reserves as determined by the bank. We may borrow,
pay, reborrow and repay under the Credit Facility until July 31, 2002, on which
date, we must repay in full all amounts then outstanding. The maturity date can
be extended to July 31, 2004 if redemption of the 10.125% Senior Subordinated
Notes due September 15, 2002 is completed prior to July 31, 2002. We expect to
redeem or extend the Notes due in September 2002 prior to their maturity and
anticipate extensions of maturity of the Credit Facility to July 2004. At
December 31, 2001, availability under the Credit Facility was $50 million.
25
The Credit Facility and the subordinated debt contain various covenants
including restrictions on additional indebtedness and payment of cash dividends
as well as maintenance of certain financial ratios. We are in compliance with
these covenants at December 31, 2001.
Our plans for 2002 include non-discretionary capital expenditures of $50
million. Approximately $23 million of the investment will be allocated to the
development of two of our deepwater discoveries. Our non-discretionary
expenditure on the shelf includes the completion of a production acceleration
project in the Mobile Block 864 area, well completions for 2001 discoveries and
other commitments to existing properties.
Cash flow and current availability under the Credit Facility, subject to the
maturity of the same as discussed above, is expected to be sufficient to fund
our 2002 non-discretionary capital expenditures. These expenditures include
completion of the Medusa deepwater discovery, currently scheduled to begin
production late in the fourth quarter of 2002 or early 2003. We are currently
evaluating options for redeeming the Senior Subordinated Notes due 2002. These
options include, but are not limited to, (i) negotiated extensions of the
maturity of a portion of these notes, (ii) increased availability under the
Credit Facility and (iii) the issuance of additional Senior Notes.
We anticipate that these options would provide necessary capital to enable us to
continue our operational activities until such time as production from the
Medusa discovery begins. At that time, we anticipate the inclusion of the Medusa
reserves and production will be integrated in our borrowing base from our Credit
Facility and provide available borrowing capacity as well as cash flow from the
new production for future discretionary capital expenditures.
Options currently under consideration to provide longer-term liquidity include
(i) the sale of one of our deepwater discoveries, (ii) lease or similar
financing of our deepwater infrastructure particularly at Medusa and (iii) the
sale of common equity.
The following table describes our outstanding contractual obligations (in
thousands) as of December 31, 2001:
CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE
OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS
----------- ------- --------- --------- --------- ----------
Credit Facility $ 100 $ 100 -- -- --
Senior Notes 95,000 -- -- $ 95,000 --
10.125% Senior
Subordinated Debt 36,000 36,000 -- -- --
10.25% Senior -- -- --
Subordinated Debt 40,000 -- $ 40,000 -- --
11% Senior Subordinated Debt 33,000 -- -- 33,000 --
Capital lease (future minimum payments) 8,413 2,175 3,863 1,138 $ 1,237
26
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect to our
oil and gas operations for each of the three years in the period ended December
31, 2001.
DECEMBER 31,
----------------------------------
2001(a)(b) 2000(a)(b) 1999(a)(b)
---------- ---------- ----------
Production:
Oil (MBbls) 273 232 330
Gas (MMcf) 13,566 13,943 14,606
Total production (MMcfe) 15,206 15,334 16,589
Average daily production (MMcfe) 41.7 41.9 45.5
Average sales price:
Oil (per Bbl) $ 22.95 $ 27.88 $ 12.16
Gas (per Mcf) $ 3.96 $ 3.57 $ 2.27
Total production (per Mcfe) $ 3.95 $ 3.67 $ 2.24
Average costs (per Mcfe):
Lease operating expenses $ .73 $ .61 $ .46
Depletion $ 1.37 $ 1.10 $ .99
General and administrative (net of management fees) $ .30 $ .27 $ .28
(a) Includes hedging gains and losses.
(b) Includes volumes of 2,300 MMcf for each of the years 2001 and 2000 and
volumes of 1,300 MMcf in 1999, at an average price of $2.08 per Mcf
associated with a volumetric production payment.
27
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001 AND
2000
OIL AND GAS REVENUES
Oil and gas revenues for 2001 were $60.0 million, a 7% increase from the 2000
amount of $56.3 million. However, 2001 oil and gas production of 15,206 MMcfe
decreased slightly from the 2000 amount of 15,334 MMcfe.
Oil production increased from 232,000 barrels in 2000 to 273,000 barrels in 2001
but the average sales price decreased from $27.88 in 2000 to $22.95 in 2001. As
a result, oil revenues dropped from $6.5 million in 2000 to $6.3 million in
2001. The production increase was primarily from increased oil production at
South Marsh Island 261 offset by older properties' normal and expected decline
in production. The slight decrease in oil revenue was due to the decline in
average oil prices received in 2001.
Gas revenues for 2001 were $53.7 million based on sales of 13.6 Bcf at an
average sales price of $3.96 per Mcf. For 2000, gas revenues were $49.8 million
based on production of 13.9 Bcf sold at an average sales price of $3.57 per Mcf.
Our gas production in 2001 decreased when compared to last year as a result of
production declines at East Cameron 275 and South Marsh Island 261, offset by
increases in production at Mobile Block 864 and Chandeleur Block 40. The
production declines at East Cameron 275 and South Marsh Island 261 were normal
and expected as the 2000 rates were indicative of higher initial production. The
Mobile Block 864 Area increased production due to a well stimulation program as
well additions to production through exploratory and developmental drilling on
the property. Gas revenue increased due to higher prices received for production
in 2001.
LEASE OPERATING EXPENSES
Lease operating expenses increased from $9.3 million ($.61 per Mcfe) in 2000 to
$11.3 million ($.73 per Mcfe) in 2001. The increase was attributable to higher
operating costs at South Marsh Island 261 and at Mobile Block 864. Also,
production declines related to older properties that have relatively fixed
operating costs contributed to the higher per Mcf costs with lower production
levels for those properties in 2001.
WRITEDOWN OF ENRON DERIVATIVES
In April of 2001, we entered into derivative contracts for 2002 production with
Enron North America Corp. Enron North America Corp. filed for protection under
the bankruptcy laws in late 2001. As a result of the credit risk associated with
the derivatives with Enron North America Corp., hedge accounting was not
available due to ineffectiveness as of September 30, 2001 and the contracts at
December 31, 2001 have been marked to the market. In the fourth quarter of 2001,
we charged to expense (non-cash) $9.2 million related to these Enron North
America Corp. derivatives. We have no other contracts with Enron or their
related subsidiaries.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased by 23% due to a combination
of an increase in the amortization base due to higher drilling costs with
reserve additions being less than expected from exploration efforts in 2001 and
downward reserve revisions as a result of a field delineation program at
Habanero.
28
Total charges increased from $17.2 million, or $1.12 per Mcfe in 2000 to $21.1
million, or $1.39 per Mcfe in 2001.
GENERAL AND ADMINISTRATIVE
General and administrative expenses for 2001 were $4.6 million, or $.30 per
Mcfe, compared to $4.2 million, or $.27 per Mcfe, in 2000. This increase was due
primarily to expenses incurred in the second quarter of 2001 related to our
withdrawn debt offering.
INTEREST EXPENSE
Interest expense for 2001 was $12.8 million increasing from $8.4 million in
2000. This is a result of an increase in our long-term debt as well as higher
interest rates associated with additional debt incurred in 2001.
INCOME TAXES
Our 2001 results include a deferred income tax expense of $977,000. We evaluated
the deferred income tax asset in light of its reserve quantity estimates, its
long-term outlook for oil and gas prices and its expected level of future
revenues and expenses. We believe it is more likely than not, based upon this
evaluation, that it will realize the recorded deferred income tax asset.
However, there is no assurance that such asset will ultimately be realized.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2000 AND
1999
OIL AND GAS REVENUES
Oil and gas revenues for 2000 were $56.3 million, a 52% increase from the 1999
amount of $37.1 million. However, 2000 oil and gas production of 15,334 MMcfe
decreased by 8% from the 1999 amount of 16,589 MMcfe.
Oil production decreased from 330,000 barrels in 1999 to 232,000 barrels in 2000
but the average sales price increased from $12.16 in 1999 to $27.88 in 2000. As
a result, oil revenues went from $4.0 million in 1999 to $6.5 million in 2000.
The decrease in oil production was primarily from older properties' normal and
expected decline in production and the depletion of Main Pass 31. The
significant increase in oil revenue was due to the price of oil received for
2000 oil production more than doubling over 1999 average prices.
Gas revenues for 2000 were $49.8 million based on sales of 13.9 Bcf at an
average sales price of $3.57 per Mcf. For 1999, gas revenues were $33.1 million
based on production of 14.6 Bcf sold at an average sales price of $2.27 per Mcf.
When compared to 1999, production decreased due to a combination of older
properties' normal and expected decline in production and the depletion of Main
Pass 31. This decrease was offset by production gains at East Cameron Block 275
and South Marsh Island 261 as they began production in early 2000. East Cameron
Block 275 experienced a significant drop in the fourth quarter of 2000 due to
work on the host platform, which caused the well to be shut in for the entire
quarter. This property was back online in January 2001 and currently is
producing at or near levels prior to the shut-in. Gas revenue increased due to
higher prices received for production in 2000, especially in the fourth quarter,
compared to 1999 offset by the 5% decline in gas production.
29
LEASE OPERATING EXPENSES AND SEVERANCE TAXES
Lease operating expenses, including severance taxes, increased from $7.5 million
($.46 per Mcfe) in 1999 to $9.3 million ($.61 per Mcfe) in 2000. The increase
per Mcfe is primarily attributable to production declines in 2000 related to
older properties that have relatively fixed operating costs, which contributed
to the higher per Mcf costs.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased by almost 3% due to an
increase in the amortization base by 56%, primarily as a result of increased
future development costs over 1999 offset by a 28% increase in reserves and by a
decrease in production.
Total charges increased from $16.7 million, or $1.01 per Mcfe in 1999 to $17.2
million, or $1.12 per Mcfe in 2000.
GENERAL AND ADMINISTRATIVE
General and administrative expenses for 2000 were $4.2 million, or $.27 per
Mcfe, compared to $4.6 million, or $.28 per Mcfe, in 1999. This 9% decrease is
primarily due to an increase in direct overhead allocable to employees engaged
in the acquisition, exploration and development of oil and gas properties in
2000.
INTEREST EXPENSE
Interest expense for 2000 and 1999 was $8.4 million and $6.2 million,
respectively. This increase is a result of the increase in interest rates and in
average debt outstanding in 2000 versus 1999. This average debt outstanding
increase is directly related to the Senior Subordinated Notes issued in October
2000 and borrowings under the Credit Facility during the year.
INCOME TAXES
Our 2000 results include a deferred income tax expense of $6.5 million. We have
evaluated the deferred income tax asset in light of our reserve quantity
estimates, our long-term outlook for oil and gas prices and our expected level
of future revenues and expenses. We believe it is more likely than not, based
upon this evaluation, that we will realize the recorded deferred income tax
asset. However, there is no assurance that such asset will ultimately be
realized.
30
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Our revenues are derived from the sale of our crude oil and natural gas
production. From time to time, we have entered into hedging transactions that
lock in for specified periods the prices we will receive for the production
volumes to which the hedge relates. The hedges reduce exposure on the hedged
volumes to decreases in commodities prices and limit the benefit might otherwise
have received from any increases in commodities prices on the hedged volumes.
We have put options in effect for 2002, other than those certain Enron North
America Corp. derivatives discussed previously under Management Discussion and
Analysis of Financial Condition and Results of Operation-Comparison of Results
of Operations for the Years Ended December 31, 2001 and 2000 and in Note 6 of
the financial statements. In March 2002, we purchased put options, which
established an average floor price of $2.65 per Mcf on 6.1 Bcf of production
from April 2002 through September 2002.
Based on projected annual sales volumes for 2002 (excluding forecast production
increases over 2001), a 10% decline in the prices we receive for our crude oil
and natural gas production would have an approximate $4.0 million impact on our
revenues.
31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
----
Report of Independent Public Accountants 33
Consolidated Balance Sheets as of December 31, 2001 34
and 2000
Consolidated Statements of Operations for Each of the Three Years
in the Period Ended December 31, 2001 35
Consolidated Statements of Stockholders' Equity
for Each of the Three Years in the Period Ended December 31, 2001 36
Consolidated Statements of Cash Flows for Each of the Three Years
in the Period Ended December 31, 2001 37
Notes to Consolidated Financial Statements 38
32
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Callon Petroleum Company:
We have audited the accompanying consolidated balance sheets of Callon
Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. 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 auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Callon Petroleum Company and
subsidiaries, as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 2 to the consolidated financial statements effective
January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities."
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
March 29, 2002
33
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
--------------------------
2001 2000
---------- ----------
ASSETS
Current assets:
Cash and cash equivalents $ 6,887 $ 11,876
Accounts receivable 5,908 9,244
Advance to operators -- 1,131
Other current assets 209 207
---------- ----------
Total current assets 13,004 22,458
---------- ----------
Oil and gas properties, full-cost accounting method:
Evaluated properties 704,937 589,549
Less accumulated depreciation, depletion and amortization (399,339) (378,589)
---------- ----------
305,598 210,960
Unevaluated properties excluded from amortization 37,560 47,653
---------- ----------
Total oil and gas properties 343,158 258,613
---------- ----------
Pipeline and other facilities, net 5,364 5,537
Other property and equipment, net 2,455 1,790
Deferred tax asset 4,399 8,573
Long-term gas balancing receivable 473 643
Other assets, net 3,242 3,955
---------- ----------
Total assets $ 372,095 $ 301,569
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 9,985 $ 17,842
Undistributed oil and gas revenues 1,131 1,411
Accrued net profits interest payable 1,501 2,146
Accounts payable and accrued liabilities to be refinanced 9,558 --
Current maturities of long-term debt 37,345 --
---------- ----------
Total current liabilities 59,520 21,399
---------- ----------
Long-term debt-excluding current maturities 161,733 134,000
Deferred revenue on sale of production payment 2,406 7,236
Accrued retirement benefits 137 1,886
Long-term gas balancing payable 1,075 720
---------- ----------
Total liabilities 224,871 165,241
---------- ----------
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares
authorized; 600,861 shares of Convertible
Exchangeable Preferred Stock, Series A issued
and outstanding at December 31, 2001
with a liquidation preference of $15,021,525 6 6
Common Stock, $.01 par value; 20,000,000 shares
authorized; 13,397,706 and 13,327,675 shares
outstanding at December 31, 2001 and 2000, respectively 134 133
Treasury stock (99,078 shares at cost) (1,183) (1,183)
Capital in excess of par value 155,608 151,223
Accumulated other comprehensive income 5,971 --
Retained earnings (deficit) (13,312) (13,851)
---------- ----------
Total stockholders' equity 147,224 136,328
---------- ----------
Total liabilities and stockholders' equity $ 372,095 $ 301,569
========== ==========
The accompanying notes are an integral part of these financial statements.
34
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2001 2000 1999
-------- -------- --------
Revenues:
Oil and gas sales $ 60,010 $ 56,310 $ 37,140
Interest and other 1,742 1,767 1,853
-------- -------- --------
Total revenues 61,752 58,077 38,993
-------- -------- --------
Costs and expenses:
Lease operating expenses 11,252 9,339 7,536
Depreciation, depletion and amortization 21,081 17,153 16,727
General and administrative 4,635 4,155 4,575
Writedown of Enron derivatives 9,186 -- --
Interest 12,805 8,420 6,175
-------- -------- --------
Total costs and expenses 58,959 39,067 35,013
-------- -------- --------
Income from operations 2,793 19,010 3,980
Income tax expense 977 6,463 1,353
-------- -------- --------
Net income 1,816 12,547 2,627
Preferred stock dividends 1,277 2,403 2,497
-------- -------- --------
Net income available to common shares $ 539 $ 10,144 $ 130
======== ======== ========
Net income per common share:
Basic $ .04 $ .82 $ .01
======== ======== ========
Diluted $ .04 $ .80 $ .01
======== ======== ========
Shares used in computing net income per common share:
Basic 13,273 12,420 8,976
======== ======== ========
Diluted 13,366 12,745 9,075
======== ======== ========
The accompanying notes are an integral part of these financial statements.
35
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
ACCUMULATED TOTAL
CAPITAL IN OTHER RETAINED STOCK-
PREFERRED COMMON TREASURY EXCESS OF COMPREHENSIVE EARNINGS HOLDER'S
STOCK STOCK STOCK PAR VALUE INCOME (DEFICIT) EQUITY
--------- ------ -------- ---------- ------------- --------- --------
Balances, December 31, 1998 $ 13 $ 82 $ (915) $ 109,429 $ -- $ (24,125) $ 84,484
--------- ------ -------- ---------- ------- --------- --------
Net income -- -- -- -- -- 2,627 2,627
Sale of common stock -- 37 -- 40,994 -- -- 41,031
Preferred stock dividends -- -- -- -- -- (2,222) (2,222)
Shares issued pursuant to employee
benefit and option plan -- -- -- 274 -- -- 274
Employee stock purchase plan -- -- -- 67 -- -- 67
Restricted stock plan -- (2) -- (1,613) -- -- (1,615)
Conversion of preferred shares
to common stock (2) 5 -- 274 -- (275) 2
Stock buyback plan -- -- (268) -- -- -- (268)
--------- ------ -------- ---------- ------- --------- --------
Balances, December 31, 1999 11 122 (1,183) 149,425 -- (23,995) 124,380
--------- ------ -------- ---------- ------- --------- --------
Net income -- -- -- -- -- 12,547 12,547
Preferred stock dividends -- -- -- -- -- (1,978) (1,978)
Shares issued pursuant to employee
benefit and option plan -- -- -- 1,069 -- -- 1,069
Employee stock purchase plan -- -- -- 269 -- -- 269
Tax benefits related to stock
compensation plans -- -- -- 41 -- -- 41
Conversion of preferred shares to
common (5) 11 -- 419 -- (425) --
--------- ------ -------- ---------- ------- --------- --------
Balances, December 31, 2000 6 133 (1,183) 151,223 -- (13,851) 136,328
--------- ------ -------- ---------- ------- --------- --------
Comprehensive income:
Net income -- -- -- -- -- 1,816
Other comprehensive income -- -- -- -- 5,971 --
--------
Total comprehensive income 7,787
Preferred stock dividends -- -- -- -- -- (1,277) (1,277)
Shares issued pursuant to employee
benefit and option plan -- 1 -- 942 -- -- 943
Employee stock purchase plan -- -- -- 357 -- -- 357
Tax benefits related to stock
compensation plans -- -- -- 18 -- -- 18
Warrants -- -- -- 3,068 -- -- 3,068
--------- ------ -------- ---------- ------- --------- --------
Balances, December 31, 2001 $ 6 $ 134 $ (1,183) $ 155,608 $ 5,971 $ (13,312) $147,224
========= ====== ======== ========== ======= ========= ========
The accompanying notes are an integral part of these financial statements.
36
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(IN THOUSANDS)
2001 2000 1999
---------- ---------- ----------
Cash flows from operating activities:
Net income $ 1,816 $ 12,547 $ 2,627
Adjustments to reconcile net income (loss) to
cash provided by operating activities:
Depreciation, depletion and amortization 21,709 17,598 17,232
Amortization of deferred costs 2,485 1,034 707
Amortization of deferred production payment revenue (4,830) (4,844) (2,710)
Writedown of Enron derivatives 9,186 -- --
Deferred income tax expense 977 6,463 1,353
Noncash charge related to compensation plans 942 1,069 275
Changes in current assets and liabilities:
Accounts receivable 3,336 (3,882) 662
Advance to operators 1,131 (1,131) 1,271
Other current assets (2) (18) (11)
Current liabilities (8,782) 1,077 1,981
Increase in accounts payable and accrued liabilities to be refinanced 9,558 -- --
Change in gas balancing receivable 170 (400) (44)
Change in gas balancing payable 355 204 27
Change in other long-term liabilities (1,749) (221) (216)
Change in other assets, net (1,071) (751) (134)
---------- ---------- ----------
Cash provided (used) by operating activities 35,231 28,745 23,020
---------- ---------- ----------
Cash flows from investing activities:
Capital expenditures (113,833) (81,849) (51,709)
Cash proceeds from sale of mineral interests 1,195 -- --
---------- ---------- ----------
Cash provided (used) by investing activities (112,638) (81,849) (51,709)
---------- ---------- ----------
Cash flows from financing activities:
Equity issued related to employee stock plans 357 269 68
Purchase of treasury shares -- -- (268)
Payment on debt (84,900) (29,250) (42,500)
Increase in debt 155,000 63,000 64,500
Deferred financing costs (2,374) (1,496) (1,823)
Restricted stock plan -- -- (1,615)
Sale of common stock -- -- 41,031
Capital lease 5,612 -- --
Cash dividends on preferred stock (1,277) (2,214) (2,333)
---------- ---------- ----------
Cash provided (used) by financing activities 72,418 30,309 57,060
---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents (4,989) (22,795) 28,371
Cash and cash equivalents:
Balance, beginning of period 11,876 34,671 6,300
---------- ---------- ----------
Balance, end of period $ 6,887 $ 11,876 $ 34,671
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
37
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
GENERAL
Callon Petroleum Company (the "Company") was organized under the laws of the
state of Delaware in March 1994 to serve as the surviving entity in the
consolidation and combination of several related entities (referred to herein
collectively as the "Constituent Entities"). The combination of the businesses
and properties of the Constituent Entities with the Company was completed on
September 16, 1994 (the "Consolidation").
As a result of the Consolidation, all of the businesses and properties of the
Constituent Entities are owned (directly or indirectly) by the Company. Certain
registration rights were granted to the stockholders of certain of the
Constituent Entities. See Note 7.
The Company and its predecessors have been engaged in the acquisition,
development and exploration of crude oil and natural gas since 1950. The
Company's properties are geographically concentrated in Louisiana, Alabama,
Texas and offshore Gulf of Mexico.
LIQUIDITY AND CAPITAL RESOURCES
As discussed in Note 5, the $36.0 million of the 10.125% Senior Subordinated
Notes will mature on September 15, 2002. When these notes are extended or
redeemed, maturity of the Credit Facility, currently scheduled for July 31,
2002, can be extended until July 31, 2004. We are currently evaluating options
for redeeming the Senior Subordinated Notes due 2002. These options include, but
are not limited to, (i) negotiated extensions of the maturity of a portion of
these notes, (ii) increased availability under the Credit Facility and (iii) the
issuance of additional Senior Notes.
Capital commitments in 2002 include non-discretionary capital expenditures and
the redemption or extension of the $36.0 million of the 10.125% Senior
Subordinated Notes that will mature on September 15, 2002. Capital expenditures
include completion of the Medusa deepwater discovery, currently scheduled to
begin production late in the fourth quarter of 2002. The Company expects that,
in addition to cash flow generated during 2002 and current availability under
the Credit Facility, approximately $27 million of additional funding will be
required to finance our capital commitments. We expect these requirements to be
met through the options discussed above. As of March 27, 2002, the company has
obtained a commitment from holders of approximately $10 million of the Notes to
extend the maturity of the Notes until 2004.
We anticipate that these funding sources will provide necessary capital to
enable us to continue our operational activities until such time as production
from the Medusa discovery begins. At that time, we anticipate the inclusion of
the Medusa reserves and production will be integrated in our borrowing base from
our Credit Facility and provide available borrowing capacity as well as
significant additional cash flow from the new production for future
discretionary capital expenditures.
38
Longer-term liquidity options currently under consideration include (i) the sale
of one of our deepwater discoveries, (ii) lease or similar financing of our
deepwater infrastructure, particularly at Medusa and (iii) the sale of common
equity.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION AND REPORTING
The Consolidated Financial Statements include the accounts of the Company, and
its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has
subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing,
Inc. All intercompany accounts and transactions have been eliminated. Certain
prior year amounts have been reclassified to conform to presentation in the
current year.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative
Instruments and Hedging Activities. The Statement establishes accounting and
reporting standards requiring that every derivative instrument, including
certain derivative instruments embedded in other contracts, be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Company adopted SFAS 133 effective January 1, 2001.
SFAS 133 requires the Company to report changes in the fair value of our
derivative financial instruments that qualify as cash flow hedges in other
comprehensive income, a component of stockholders' equity, until realized. See
Note 6 for a discussion of our derivative financial instruments.
As discussed in Note 1, the Company adopted SFAS 133 effective January 1, 2001.
The cumulative effect of the accounting change, net of tax, recorded as other
comprehensive loss was $3.8 million. In 2001, this amount was offset by an
increase in the fair value of derivatives recorded as other comprehensive income
and the settlement of the derivatives that contractually matured in 2001.
In July 2001, the Financial Accounting Standards Board approved Statement of
Accounting Standards No. 143, Asset Retirement Obligations ("SFAS 143"). SFAS
143 will require that the fair value of abandonment obligations be reflected as
a liability, resulting in a corresponding increase to the historical cost of the
related assets and potentially an adjustment for the cumulative effect of a
change in accounting principle. This standard is required to be adopted by the
Company beginning no later that January 1, 2003. The Company has not yet
determined timing or the impact of the adoption of SFAS 143.
39
PROPERTY AND EQUIPMENT
The Company follows the full-cost method of accounting for oil and gas
properties whereby all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves, including certain overhead
costs, are capitalized. Such amounts include the cost of drilling and equipping
productive wells, dry hole costs, lease acquisition costs, delay rentals,
interest capitalized on unevaluated leases and other costs related to
exploration and development activities. Payroll and general and administrative
costs capitalized include salaries and related fringe benefits paid to employees
directly engaged in the acquisition, exploration and/or development of oil and
gas properties as well as other directly identifiable general and administrative
costs associated with such activities. Such capitalized costs do not include any
costs related to production or general corporate overhead. Costs associated with
unevaluated properties are excluded from amortization. Unevaluated property
costs are transferred to evaluated property costs at such time as wells are
completed on the properties, the properties are sold or management determines
these costs have been impaired.
Costs of properties, including future development and net future site
restoration, dismantlement and abandonment costs, which have proved reserves and
those which have been determined to be worthless, are depleted using the
unit-of-production method based on proved reserves. If the total capitalized
costs of oil and gas properties, net of amortization, exceed the sum of (1) the
estimated future net revenues from proved reserves at current prices and
discounted at 10% and (2) the lower of cost or market of unevaluated properties
(the full-cost ceiling amount), net of tax effects, then such excess is charged
to expense during the period in which the excess occurs. See Note 8.
Upon the acquisition or discovery of oil and gas properties, management
estimates the future net costs to be incurred to dismantle, abandon and restore
the property using geological, engineering and regulatory data available. Such
cost estimates are periodically updated for changes in conditions and
requirements. Such estimated amounts are considered as part of the full cost
pool subject to amortization upon acquisition or discovery. Such costs are
capitalized as oil and gas properties as the actual restoration, dismantlement
and abandonment activities take place.
Depreciation of other property and equipment is provided using the straight-line
method over estimated lives of three to 20 years. Depreciation of pipeline and
other facilities is provided using the straight-line method over estimated lives
of 15 to 27 years.
SALE OF PRODUCTION PAYMENT INTEREST
In June 1999, the Company acquired a working interest in the Mobile Block 864
Area where the Company already owned an interest. Concurrent with this
acquisition, the seller received a volumetric production payment, valued at
approximately $14.8 million, from production attributable to a portion of the
Company's interest in the area over a 39-month period. The Company recorded a
liability associated with the sale of this production payment interest because a
substantial obligation for future performance exists. Under the terms of the
sale, the Company is obligated to deliver the production volumes free and clear
of royalties, lease operating expenses, production taxes and all capital costs.
The production payment was recorded at the present value of the volumetric
production committed to the seller at market value and, beginning in June 1999,
is amortized to oil and gas sales on the units-of-production method as
associated hydrocarbons are delivered and will expire in July 2002.
40
NATURAL GAS IMBALANCES
The Company follows an entitlement method of accounting for its proportionate
share of gas production on a well-by-well basis, recording a receivable to the
extent that a well is in an "undertake" position and conversely recording a
liability to the extent that a well is in an "overtake" position. Imbalance
positions are not significant at December 31, 2001.
DERIVATIVES
The Company uses derivative financial instruments for price protection purposes
on a limited amount of its future production and does not use them for trading
purposes. Such derivatives were accounted for, prior to adoption of SFAS 133, as
hedges and have been recognized as an adjustment to oil and gas sales in the
period in which they are related. Current accounting treatment is under SFAS 133
(see Note 6).
ACCOUNTS RECEIVABLE
Accounts receivable consists primarily of accrued oil and gas production
receivables. The balance in the reserve for doubtful accounts included in
accounts receivable was $68,000 and $78,000 at December 31, 2001 and 2000,
respectively. Net charge offs were $10,000 in 2001 and net recoveries were
$40,000 in 2000. There were no provisions to expense in the three-year period
ended December 31, 2001.
MAJOR CUSTOMERS
Our production is sold primarily on month-to-month contracts at prevailing
prices. The following table identifies customers to whom we sold a significant
percentage of our total oil and gas production during each of the twelve-month
periods ended:
DECEMBER 31,
------------
2001 2000 1999
---- ---- ----
Adams Resources Marketing, Ltd. -- 14% 16%
Columbia Energy Services -- -- 29%
Dynegy 8% -- 12%
Prior Energy Corporation 20% -- --
Reliant Energy Services 49% 37% --
Unocal Exploration Corporation -- 8% --
Because alternative purchasers of oil and gas are readily available, we believe
that the loss of any of these purchasers would not result in a material adverse
effect on our ability to market future oil and gas production.
STATEMENTS OF CASH FLOWS
For purposes of the Consolidated Financial Statements, the Company considers all
highly liquid investments purchased with an original maturity of three months or
less to be cash equivalents.
41
The Company paid no federal income taxes for the three years ended December 31,
2001. During the years ended December 31, 2001, 2000 and 1999, the Company made
cash payments of $16,441,000, $11,449,000 and $9,013,000 respectively, for
interest.
PER SHARE AMOUNTS
Basic income or loss per common share were computed by dividing net income or
loss by the weighted average number of shares of common stock outstanding during
the year. Diluted income or loss per common share was determined on a weighted
average basis using common shares issued and outstanding adjusted for the effect
of stock options considered common stock equivalents computed using the treasury
stock method. The conversion of the preferred stock was not included in any
annual calculation due to its antidilutive effect on diluted income or loss per
common share.
A reconciliation of the basic and diluted per share computation is as follows
(in thousands, except per share amounts):
2001 2000 1999
-------- -------- --------
(a) Net income available for common stock $ 539 $ 10,144 $ 130
Preferred dividends assuming conversion of
preferred stock (if dilutive) -- -- --
(b) Income available for common stock assuming
conversion of preferred stock (if dilutive) $ 539 $ 10,144 $ 130
(c) Weighted average shares outstanding 13,273 12,420 8,976
Dilutive impact of stock options 27 325 99
Dilutive impact of warrants 66 -- --
Convertible preferred stock (if dilutive) -- -- --
(d) Total diluted shares 13,366 12,745 9,075
Stock options and warrants excluded due to
antidilutive impact 1,438 150 590
Basic income per share (a/c) $ .04 $ .82 $ .01
Diluted income per share (b/d) $ .04 $ .80 $ .01
FAIR VALUE OF FINANCIAL INSTRUMENTS
Fair value of cash, cash equivalents, accounts receivable, accounts payable, the
capital lease and the Credit Facility approximates book value at December 31,
2001 and 2000. Fair value of long-term debt (specifically, the 10.125%, the
10.25%, the 11% Senior Subordinated Notes and the 12% Senior Notes) have an
estimated fair value of between 95% and 97% of face value at December 31, 2001.
3. INCOME TAXES
The Company follows the asset and liability method of accounting for deferred
income taxes prescribed by Statement of Financial Accounting Standards No. 109
("SFAS 109") "Accounting for Income Taxes". The statement provides for the
recognition of a deferred tax asset for deductible temporary timing differences,
capital and operating loss carryforwards, statutory depletion carryforward and
tax credit carryforwards, net of
42
a "valuation allowance". The valuation allowance is provided for that portion of
the asset, for which it is deemed more likely than not, that it will not be
realized. The Company's management determined that no valuation allowance was
required in 2001 or 2000. Accordingly, the Company has recorded a deferred tax
asset at December 31, 2001 and 2000 as follows:
DECEMBER 31,
------------
2001 2000
---------- ----------
(IN THOUSANDS)
Federal net operating loss carryforwards $ 29,723 $ 14,352
Statutory depletion carryforward 4,184 4,152
Temporary differences:
Oil and gas properties (28,685) (8,937)
Pipeline and other facilities (1,822) (1,938)
Non-oil and gas property (62) (81)
Other 1,061 1,025
---------- ----------
Total tax asset 4,399 8,573
Valuation allowance -- --
---------- ----------
Net tax asset $ 4,399 $ 8,573
========== ==========
At December 31, 2001, the Company had, for federal tax reporting purposes, net
operating loss carryforwards of $84.9 million, which expire in 2002 through
2016. Net operating loss carryforwards includes approximately $1.5 million of
the total that will expire within the next five years. Additionally, the Company
had available for tax reporting purposes $11.9 million in statutory depletion
deductions, which can be carried forward for an indefinite period.
The Company has significant state net operating loss carryforwards that are not
included in the deferred tax asset above, as the Company does not anticipate
generating taxable state income in the states in which these loss carryforwards
apply. The Company has very limited state taxable income as primarily all of its
revenue is generated in federal waters not subject to state income taxes.
The provision for income taxes at the Company's effective tax rate approximated
the provision for income taxes at the statutory rate.
4. OTHER COMPREHENSIVE INCOME
The Company did not have any items of other comprehensive income prior to 2001.
A recap of the Company's 2001 comprehensive income (net of tax) is shown below
(in thousands):
YEAR ENDED
DECEMBER 31, 2001
-----------------
Other comprehensive income (loss):
Cumulative effect of change in
accounting principle $(3,764)
Change in unrealized derivatives'
fair value 9,735
-------
Total other comprehensive income $ 5,971
=======
43
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
DECEMBER 31,
------------
2001 2000
---------- ----------
(IN THOUSANDS)
Credit Facility $ 100 $ 25,000
Senior Notes, net of discount 84,366 --
10.125% Senior Subordinated Notes (due 2002) 36,000 36,000
10.25% Senior Subordinated Notes (due 2004) 40,000 40,000
11% Senior Subordinated Notes (due 2005) 33,000 33,000
Capital lease 5,612 --
---------- ----------
199,078 134,000
Less: current portion 37,345 --
---------- ----------
$ 161,733 $ 134,000
========== ==========
The Company negotiated a new Credit Facility effective October 31, 2000 with
First Union National Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. Currently, the Credit Facility is for $75 million with an initial
$50 million borrowing base ("Borrowing Base"), which is adjusted periodically on
the basis of a discounted present value of future net cash flows attributable to
the Company's proved producing oil and gas reserves. Pursuant to the Credit
Facility, the interest rate is equal to the lender's prime rate plus 0.25%. The
Company, at its option, may fix the interest rate on all or a portion of the
outstanding principal balance at 1.5% to 2.0% above a defined "Eurodollar" rate
for periods up to six months depending on borrowing base utilization. The
weighted average interest rate for the Credit Facility debt outstanding at
December 31, 2001 and 2000 was 4.75% and 8.53%, respectively. Under the Credit
Facility, a commitment fee of 0.25% or 0.375% per annum, depending on the amount
of the unused portion of the borrowing base, is payable quarterly. The Company
may borrow, pay, reborrow and repay under the Credit Facility until July 31,
2002 up to the borrowing base amount, on which date, the Company must repay in
full all amounts then outstanding. The maturity date will extend to July 31,
2004 upon redemption of the 10.125% Senior Subordinated Notes due September 15,
2002.
On July 31, 1997, the Company issued $36 million of its 10.125% Series A Senior
Subordinated Notes due September 15, 2002. Interest on the 10.125% Notes is
payable quarterly, on March 15, June 15, September 15, and December 15 of each
year. The 10.125% Notes are redeemable at the option of the Company in whole or
in part, at any time on or after September 15, 2000. The 10.125% Notes are
general unsecured obligations of the Company, subordinated in right of payment
to all existing and future indebtedness of the Company. The 10.125% Senior
Subordinated Notes due September 15, 2002 have been classified as a current
liability.
44
On July 15, 1999, the Company completed the sale of $40 million of Senior
Subordinated Notes due 2004 at 10.25%. The net proceeds of approximately $38.2
million were used to pay down the Credit Facility at that time. These notes are
not entitled to any mandatory sinking fund payments and are subject to
redemption at the Company's option at par plus unpaid interest at any time after
March 15, 2001. The notes are listed on the New York Stock Exchange under the
symbol "CPE 04" and are subject to a change of control clause that obligates the
Company to repurchase the notes for 101% of par should a change of control
occur. Interest is paid quarterly.
The Company completed the sale of $33 million of 11% Senior Subordinated Notes
due 2005, on October 26, 2000. The Company netted $31.5 million from the
offering after deducting the underwriters' discount and offering expenses.
Approximately $20.8 million of the net proceeds from the offering were used to
purchase a portion of the Company's outstanding 10% Senior Subordinated Notes
due 2001 in conjunction with a tender offer. The Company redeemed the remaining
$3.4 million of its 10% Senior Subordinated Notes due 2001 not tendered in the
offer.
In May 2001, the Company initiated a combination of offerings of equity and
senior notes to investors with proceeds to be used to call certain of the
Company's subordinated debt, repay borrowings under its senior secured credit
facility and to finance capital expenditures. Subsequently, the Company withdrew
its offer to sell the senior notes and the equity sale was terminated.
Approximately $358,000 of costs associated with the withdrawn offering were
expensed during the quarter.
In July 2001, the Company entered into a $95 million multiple advance term loan
with a private lender. The Company issued $45 million of 12% Senior Notes upon
closing of the loan and issued the remaining $50 million of Senior Notes in
December 2001. Under the terms of the agreement Callon also issued warrants to
purchase, at a nominal exercise price, 265,210 shares of its common stock (fair
value of $3.1 million) and conveyed an overriding royalty interest equal to 2%
of the Company's net interest in four existing deepwater discoveries (fair value
of $5.9 million). The warrants and the overriding royalty interest were earned
by the lender based on the ratio of the amount of the loan proceeds advanced to
the total loan facility amount. The Senior Notes will mature March 31, 2005,
have an effective interest rate of approximately 16% and contain restrictions on
certain types of future indebtedness.
In December 2001, the Company entered into a ten-year gas processing agreement
associated with a production facility on Callon's Mobile 952 field with Hanover
Compression Limited Partnership, which is being accounted for as a capital
lease. Total minimum obligations are $8.4 million with interest representing
approximately $2.8 million and the present value minimum obligation were $5.6
million ($1.2 million current).
Future minimum lease payments and debt maturities (in thousands) are as follows:
CAPITAL LEASE
YEAR PAYMENTS DEBT
---- ------------- --------
2002 $ 2,175 $ 36,100
2003 1,982 --
2004 1,881 40,000
2005 752 128,000
2006 413 --
Thereafter 1,236 --
45
The Credit Facility, the subordinated debt and the $95 million Senior Notes
contain various covenants including restrictions on additional indebtedness and
payment of cash dividends as well as maintenance of certain financial ratios.
The Company is in compliance with these covenants at December 31, 2001.
6. HEDGING CONTRACTS
The Company periodically uses derivative financial instruments to manage oil and
gas price risk. Settlements of gains and losses on commodity price contracts are
generally based upon the difference between the contract price or prices
specified in the derivative instrument and a NYMEX price or other cash or
futures index price. Approximately $3,290,000 and $1,559,000 were recognized as
a reduction of oil and gas revenue in 2000 and 1999 respectively, and $1,371,000
was recognized as additional oil and gas revenue in 2001 as a result of such
agreements.
In March 2002, the Company purchased put options, which established an average
floor price of $2.65 per Mcf on 6.1 Bcf of production from April 2002 through
September 2002.
In April of 2001, the Company entered into derivative contracts for 2002
production with Enron North America Corp. These agreements are for average gas
volumes of approximately 600,000 Mcf per month in 2002 with a weighted average
ceiling price of $6.09 and floor price of $4.11. Enron North America Corp. filed
for protection under the bankruptcy laws in late 2001. As a result of the credit
risk associated with the derivatives with Enron North America Corp., hedge
accounting was not available due to ineffectiveness as of September 30, 2001 and
the contracts at December 31, 2001 have been marked to the market. In the fourth
quarter of 2001, the Company charged to expense (non-cash) $9.2 million related
to these Enron North America Corp. derivatives. The Company has no other
contracts with Enron or its subsidiaries.
The $5,971,000 (net of tax) recorded in other comprehensive income at December
31, 2001 is related to the fair value as of September 30, 2001 of the natural
gas collar contracts with Enron North America Corp., which matures in 2002. As
the contracts mature in 2002, the Company will record non-cash revenue each
month, offsetting the amounts in other comprehensive income related to the
derivatives.
The Company has no other derivative contracts.
7. COMMITMENTS AND CONTINGENCIES
As described in Note 9, abandonment trusts (the "Trusts") have been established
for future abandonment obligations of those oil and gas properties of the
Company burdened by a net profits interest. The management of the Company
believes the Trusts will be sufficient to offset those future abandonment
liabilities; however, the Company is responsible for any abandonment expenses in
excess of the Trusts' balances. As of December 31, 2001 total estimated site
restoration, dismantlement and abandonment costs were approximately $6,567,000,
net of expected salvage value. Substantially all such costs are expected to be
funded through the Trusts' funds, all of which will be accessible to the Company
when abandonment work begins. In addition, as a working interest owner and/or
operator of oil and gas properties, the Company is responsible for the cost of
abandonment of such properties. See Note 2.
From time to time, the Company, as part of the Consolidation and other capital
transactions, entered into Registration Rights Agreements whereby certain
parties to the transactions are entitled to require the
46
Company to register Common Stock of the Company owned by them with the
Securities and Exchange Commission for sale to the public in firm commitment
public offerings and generally to include shares owned by them, at no cost, in
registration statements filed by the Company. Costs of the offering will not
include broker's discounts and commissions, which will be paid by the respective
sellers of the Common Stock.
The Company is involved in various claims and lawsuits incidental to its
business. In the opinion of management, the ultimate liability thereunder, if
any, will not have a material adverse effect on the financial position or
results of operations of the Company.
The Company's activities are subject to federal, state and local laws and
regulations governing environmental quality and pollution control. Although no
assurances can be made, the Company believes that, absent the occurrence of an
extraordinary event, compliance with existing federal, state and local laws,
rules and regulating the release of materials in the environment or otherwise
relating to the protection of the environment will not have a material effect
upon the capital expenditures, earnings or the competitive position of the
Company with respect to its existing assets and operations. The Company cannot
predict what effect additional regulation or legislation, enforcement polices
thereunder, and claims for damages to property, employees, other persons and the
environment resulting from the Company's operations could have on its
activities.
47
8. OIL AND GAS PROPERTIES
The following table discloses certain financial data relating to the Company's
oil and gas activities, all of which are located in the United States.
YEARS ENDED DECEMBER 31,
------------------------------------------
2001 2000 1999
---------- ---------- ----------
(IN THOUSANDS)
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance $ 589,549 $ 511,689 $ 444,579
Property acquisition costs 1,713 3,211 24,153
Exploration costs 85,782 51,837 37,427
Development costs 34,980 25,242 5,530
Sale of mineral interests (7,087) (2,430) --
---------- ---------- ----------
End of period balance $ 704,937 $ 589,549 $ 511,689
========== ========== ==========
Unevaluated Properties (excluded from
amortization) -
Beginning of period balance $ 47,653 $ 44,434 $ 42,679
Additions 2,350 4,381 4,890
Capitalized interest 4,879 4,548 3,497
General and administrative costs 6,410 5,036 3,623
Transfers to evaluated (23,732) (10,746) (10,255)
---------- ---------- ----------
End of period balance $ 37,560 $ 47,653 $ 44,434
========== ========== ==========
Accumulated depreciation, depletion
and amortization
Beginning of period balance $ 378,589 $ 361,758 $ 345,353
Provision charged to expense 20,750 16,831 16,405
---------- ---------- ----------
End of period balance $ 399,339 $ 378,589 $ 361,758
========== ========== ==========
Unevaluated property costs, primarily lease acquisition costs incurred at
federal lease sales, unevaluated drilling costs, capitalized interest and
general and administrative costs being excluded from the amortizable evaluated
property base consisted of $7.5 million incurred in 2001, $8.3 million incurred
in 2000 and $21.9 million incurred in 1999 and prior. These costs are directly
related to the acquisition and evaluation of unproved properties and major
development projects. The excluded costs and related reserves are included in
the amortization base as the properties are evaluated and proved reserves are
established or impairment is determined. The Company expects that the majority
of these costs will be evaluated over the next three to five year period.
Depletion per unit-of-production (thousand cubic feet of gas equivalent)
amounted to $1.37, $1.10 and $.99 for the years ended December 31, 2001, 2000,
and 1999, respectively.
Under the full cost accounting rules of the SEC, the Company reviews the
carrying value of its proved oil and gas properties each quarter on a
country-by-country basis. Under these rules, capitalized costs of proved oil and
gas properties net of accumulated depreciation, depletion and amortization
(DD&A) and deferred income taxes, may not exceed the present value of estimated
future net cash flows from proved oil and gas reserves, discounted at 10
percent, plus the lower of cost or fair value of unproved properties included in
the costs being amortized, net of related tax effects. These rules generally
require pricing future oil and gas
48
production at the unescalated market price for oil and gas at the end of each
fiscal quarter and require a write-down if the "ceiling" is exceeded, unless
prices recover sufficiently before the date of the auditor's report. Given the
volatility of oil and gas prices, it is reasonably possible that the Company's
estimate of discounted future net cash flows from proved oil and gas reserves
could change in the near term. If oil and gas priced decline significantly, even
if only for a short period of time, it is possible that writedowns of oil and
gas properties could occur in the future. Based on prices at December 31, 2001
the Company would be required to writedown its assets by $37.5 million. However,
as of the date of the auditor's report, commodity prices increased sufficiently
to eliminate any writedown.
9. NET PROFITS INTEREST
From 1989 through 1994, the Constituent Entities entered into separate
agreements to purchase certain oil and gas properties with gross contract
acquisition prices of $170,000,000 ($150,000,000 net as of closing dates) and in
simultaneous transactions, entered into agreements to sell overriding royalty
interests ("ORRI") in the acquired properties. These ORRI are in the form of net
profits interests ("NPI") equal to a significant percentage of the excess of
gross proceeds over production costs, as defined, from the acquired oil and gas
properties. A net deficit incurred in any month can be carried forward to
subsequent months until such deficit is fully recovered. The Company has the
right to abandon the purchased oil and gas properties if it deems the properties
to be uneconomical.
The Company has, pursuant to the purchase agreements, created abandonment trusts
whereby funds are provided out of gross production proceeds from the properties
for the estimated amount of future abandonment obligations related to the
working interests owned by the Company. The Trusts are administered by unrelated
third party trustees for the benefit of the Company's working interest in each
property. The Trust agreements limit their funds to be disbursed for the
satisfaction of abandonment obligations. Any funds remaining in the Trusts after
all restoration, dismantlement and abandonment obligations have been met will be
distributed to the owners of the properties in the same ratio as contributions
to the Trusts. The Trusts' assets are excluded from the Consolidated Balance
Sheets of the Company because the Company does not control the Trusts. Estimated
future revenues and costs associated with the NPI and the Trusts are also
excluded from the oil and gas reserve disclosures at Note 12. As of December 31,
2001 and 2000, the Trusts' assets (all cash and investments) totaled $6,567,000
and $6,227,000 respectively, all of which will be available to the Company to
pay its portion, as working interest owner, of the restoration, dismantlement
and abandonment costs discussed at Note 7.
At the time of acquisition of properties by the Company, the property owners
estimated the future costs to be incurred for site restoration, dismantlement
and abandonment, net of salvage value. A portion of the amounts necessary to pay
such estimated costs was deposited in the Trusts upon acquisition of the
properties, and the remainder is deposited from time to time out of the proceeds
from production. The determination of the amount deposited upon the acquisition
of the properties and the amount to be deposited as proceeds from production was
based on numerous factors, including the estimated reserves of the properties.
The amounts deposited in the Trusts upon acquisition of the properties were
capitalized by the Company as oil and gas properties.
As operator, the Company receives all of the revenues and incurs all of the
production costs for the purchased oil and gas properties but retains only that
portion applicable to its net ownership share. As a result, the payables and
receivables associated with operating the properties included in the Company's
Consolidated Balance Sheets include both the Company's and all other outside
owners' shares. However,
49
revenues and production costs associated with the acquired properties reflected
in the accompanying Consolidated Statements of Operations represent only the
Company's share, after reduction for the NPI.
10. EMPLOYEE BENEFIT PLANS
The Company has adopted a series of incentive compensation plans designed to
align the interest of the executives and employees with those of its
stockholders. The following is a brief description of each plan:
o The Savings and Protection Plan provides employees with the option to
defer receipt of a portion of their compensation and the Company may,
at its discretion, match a portion of the employee's deferral with cash
and Company Common Stock. The Company may also elect, at its
discretion, to contribute a non-matching amount in cash and Company
Common Stock to employees. The amounts held under the Savings and
Protection Plan are invested in various funds maintained by a third
party in accordance with the directions of each employee. An employee
is fully vested, including Company discretionary contributions,
immediately upon participation in the Savings and Protection Plan. The
total amounts contributed by the Company, including the value of the
common stock contributed, were $595,000, $500,000 and $466,000 in the
years 2001, 2000 and 1999, respectively.
o The 1994 Stock Incentive Plan (the "1994 Plan") provides for 600,000
shares of Common Stock to be reserved for issuance pursuant to such
plan. Under the 1994 Plan the Company may grant both stock options
qualifying under Section 422 of the Internal Revenue Code and options
that are not qualified as incentive stock options, as well as
performance shares. These options have an expiration date 10 years from
date of grant.
o On August 23, 1996, the Board of Directors of the Company approved and
adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the
"1996 Plan"). The 1996 Plan provides for the same types of awards as
the 1994 Plan and is limited to a maximum of 1,200,000 shares (as
amended from the original 900,000 shares) of common stock that may be
subject to outstanding awards. Unvested options are subject to
forfeiture upon certain termination of employment events and expire 10
years from date of grant.
o The Company granted 533,000 stock options to employees on March 23,
2000 and 120,000 stock options to directors on July 25, 2000 at $10.50
per share. The March 23, 2000 grant was subject to shareholder approval
of an amendment to the 1996 Stock Incentive Plan. The amendment, which
was approved on May 9, 2000 at the Annual Meeting of Shareholders,
increased the number of shares reserved for issuance under the 1996
plan to 2,200,000 shares. The excess of the market price over the
exercise price on the approval date of the amendment is amortized over
the three-year vesting period of the options. Compensation costs of
$611,000 and $801,000 were recognized in income in 2001 and 2000
respectively related to these options.
The Company accounts for the options issued pursuant to the stock incentive
plans under APB Opinion No. 25, under which no compensation cost has been
recognized unless the exercise price is less than the market price at the
measurement date. Had compensation cost for these plans been determined
consistent with Statement of Financial Accounting Standards No. 123 ("SFAS
123"), "Accounting for Stock-Based
50
Compensation", the Company's net income and earnings per common share would have
been reduced to the following pro forma amounts:
2001 2000 1999
-------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income (loss) available for
common shares: As Reported $ 539 $ 10,144 $ 130
Pro Forma (839) 8,418 (1,212)
Basic earnings (loss) per share: As Reported .04 .82 .01
Pro Forma (.06) .68 (.14)
Diluted earnings (loss) per share: As Reported .04 .80 .01
Pro Forma (.06) .66 (.14)
A summary of the status of the Company's two stock option plans for the three
most recent years and changes during the years then ended is presented in the
table and narrative below:
2001 2000 1999
------------------------ ------------------------ -----------------------
WTD AVG WTD AVG WTD AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
---------- -------- ---------- -------- ---------- --------
Outstanding, beginning of year 2,304,167 $ 10.83 1,536,500 $ 10.60 1,266,000 $ 11.00
Granted (at market) 30,000 11.61 135,000 14.73 270,500 9.27
Granted (below market) -- -- 653,000 10.50 -- --
Exercised (1,500) 9.00 (20,333) 9.00 -- --
Forfeited -- -- -- -- -- --
Expired -- -- -- -- -- --
---------- -------- ---------- -------- ---------- --------
Outstanding, end of year 2,332,667 $ 10.84 2,304,167 $ 10.83 1,536,500 $ 10.60
========== ======== ========== ======== ========== ========
Exercisable, end of year 2,057,977 $ 10.80 1,647,657 $ 10.71 1,247,600 $ 10.47
========== ======== ========== ======== ========== ========
Weighted average fair value of
options granted (at market) $ 5.80 $ 7.68 $ 4.94
========== ========== ==========
Weighted average fair value of
options granted (below market) N/A $ 7.90 N/A
=========
At December 31, 2001, 2,157,667 of the 2,332,667 options outstanding have
exercise prices between $9 and $13.50 with a weighted average exercise price of
$10.53 and a weighted average remaining contractual life of 5.90 years. Of these
options, 1,919,277 are exercisable at a weighted average exercise price of
$10.53. The remaining 175,000 options have exercise prices between $13.50 and
$15.31 with a weighted average exercise price of $14.69 and a weighted average
remaining contractual life of 7.98 years. Of these options, 138,700 are
exercisable at a weighted average exercise price of $14.61.
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for options granted during the years presented are as follows:
2001 2000 1999
------ ------ ------
Risk free interest rate 4.5% 6.3% 6.3%
Expected life (years) 5.0 5.0 7.0
Expected volatility 43.9% 52.1% 46.0%
Expected dividends -- -- --
51
11. EQUITY TRANSACTIONS
In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible
Exchangeable Preferred Stock, Series A (the "Preferred Stock") for net proceeds
of $30.9 million. Annual dividends are $2.125 per share and are cumulative. The
net proceeds of the $.01 par value stock after underwriters discount and expense
was $30,899,000. Each share has a liquidation preference of $25.00, plus accrued
and unpaid dividends. Dividends on the Preferred Stock are cumulative from the
date of issuance and are payable quarterly, commencing January 15, 1996. The
Preferred Stock is convertible at any time, at the option of the holders
thereof, unless previously redeemed, into shares of Common Stock of the Company
at an initial conversion price of $11 per share of Common Stock, subject to
adjustments under certain conditions.
The Preferred Stock is redeemable at any time on or after December 31, 1998, in
whole or in part at the option of the Company at a redemption price of $26.488
per share beginning at December 31, 1998 and at premiums declining to the $25.00
liquidation preference by the year 2005 and thereafter, plus accrued and unpaid
dividends. The Preferred Stock is also exchangeable, in whole, but not in part,
at the option of the Company on or after January 15, 1998 for the Company's 8.5%
Convertible Subordinated Debentures due 2010 (the "Debentures") at a rate of
$25.00 principal amount of Debentures for each share of Preferred Stock. The
Debentures will be convertible into Common Stock of the Company on the same
terms as the Preferred Stock and will pay interest semi-annually.
In a December 1998 private transaction, a preferred stockholder elected to
convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's
Common Stock. In 1999 certain other preferred stockholders, through private
transactions, agreed to convert 210,350 shares of Preferred Stock into 502,637
shares of the Company's Common Stock under similar terms. Likewise in 2000,
444,600 shares of Preferred Stock were converted into 1,036,098 shares of the
Company's Common Stock. Any noncash premium negotiated in excess of the
conversion rate was recorded as additional preferred stock dividends and
excluded from the Consolidated Statements of Cash Flows.
In November of 1999, the Company sold 3,680,000 shares of Common Stock in a
public offering at a price to the public of $11.875 per share. Cash proceeds
received by the Company were $41.1 million net of underwriting discount and
offering costs.
In 2001, under the terms of the $95 million multiple advance loan, the Company
issued warrants to purchase, at a nominal exercise price, 265,210 shares of its
common stock. See Note 5.
The Company adopted a stockholder rights plan on March 30, 2000, designed to
assure that the Company's stockholders receive fair and equal treatment in the
event of any proposed takeover of the Company and to guard against partial
tender offers, squeeze-outs, open market accumulations, and other abusive
tactics to gain control without paying all stockholders a fair price. The rights
plan was not adopted in response to any specific takeover proposal. Under the
rights plan, the Company declared a dividend of one right ("Right") on each
share of the Company's Common Stock. Each Right will entitle the holder to
purchase one one-thousandth of a share of a Series B Preferred Stock, par value
$0.01 per share, at an exercise price of $90 per one one-thousandth of a share.
The Rights are not currently exercisable and will become exercisable only in the
event a person or group acquires, or engages in a tender or exchange offer to
acquire, beneficial ownership of 15 percent or more (one existing stockholder
was granted an exception for up to 21 percent) of the Company's Common Stock.
After the Rights become exercisable, each Right will also entitle its holder to
purchase a number of common shares of the Company having a market value of twice
the exercise price.
52
The dividend distribution was made to stockholders of record at the close of
business on April 10, 2000. The Rights will expire on March 30, 2010.
12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 2001, 2000 and 1999
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions. These estimates have been adjusted (per SEC
guidelines) to exclude the volumetric production payment described in Note 2.
There are numerous uncertainties inherent in establishing quantities of proved
reserves. The following reserve data represent estimates only and should not be
construed as being exact. In addition, the standard measure of discounted future
net cash flows should not be construed as the current market value of the
Company's oil and gas properties or the cost that would be incurred to obtain
equivalent reserves.
53
ESTIMATED RESERVES
Changes in the estimated net quantities of crude oil and natural gas reserves,
all of which are located onshore and offshore in the continental United States,
are as follows:
RESERVE QUANTITIES
YEARS ENDED DECEMBER 31,
------------------------------------
2001 2000 1999
-------- -------- --------
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period 33,382 23,834 6,898
Revisions to previous estimates (2,290) 85 (686)
Purchase of reserves in place -- -- 2,629
Sales of reserves in place (624) -- --
Extensions and discoveries 14 9,695 15,323
Production (273) (232) (330)
-------- -------- --------
End of period 30,209 33,382 23,834
======== ======== ========
Natural Gas (MMcf):
Beginning of period 129,922 110,621 88,030
Revisions to previous estimates (5,874) (4,817) (11,492)
Purchase of reserves in place -- 347 4,733
Sales of reserves in place -- -- --
Extensions and discoveries 7,483 35,387 42,662
Production (11,232) (11,616) (13,312)
-------- -------- --------
End of period 120,299 129,922 110,621
======== ======== ========
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period 2,192 1,376 1,774
======== ======== ========
End of period 885 2,192 1,376
======== ======== ========
Natural Gas (MMcf):
Beginning of period 63,982 76,295 76,895
======== ======== ========
End of period 51,221 63,982 76,295
======== ======== ========
54
STANDARDIZED MEASURE
The following tables present the Company's standardized measure of discounted
future net cash flows and changes therein relating to proved oil and gas
reserves and were computed using reserve valuations based on regulations
prescribed by the SEC. These regulations provide that the oil, condensate and
gas price structure utilized to project future net cash flows reflects current
prices ($2.58 for natural gas and $20.10 for oil for the 2001 disclosures) at
each date presented and have been escalated only when known and determinable
price changes are provided by contract and law. Future production, development
and net abandonment costs are based on current costs without escalation. The
resulting net future cash flows have been discounted to their present values
based on a 10% annual discount factor.
STANDARDIZED MEASURE
YEARS ENDED DECEMBER 31,
------------------------------------------------
2001 2000 1999
------------ ------------ ------------
(IN THOUSANDS)
Future cash inflows $ 883,145 $ 2,080,680 $ 847,930
Future costs -
Production (220,857) (284,667) (207,615)
Development and net abandonment (191,369) (217,507) (123,749)
------------ ------------ ------------
Future net inflows before income taxes 470,919 1,578,506 516,567
Future income taxes (30,315) (472,637) (109,238)
------------ ------------ ------------
Future net cash flows 440,604 1,105,869 407,329
10% discount factor (185,747) (434,672) (151,007)
------------ ------------ ------------
Standardized measure of discounted
future net cash flows $ 254,857 $ 671,197 $ 256,322
============ ============ ============
CHANGES IN STANDARDIZED MEASURE
YEARS ENDED DECEMBER 31,
-------------------------------------------
2001 2000 1999
---------- ---------- ----------
(IN THOUSANDS)
Standardized measure - beginning of period $ 671,197 $ 256,322 $ 99,751
Sales and transfers, net of production costs (45,672) (42,132) (27,076)
Net change in sales and transfer prices,
Net of production costs (604,391) 361,179 57,246
Exchange and sale of in place reserves (5,850) -- --
Purchases, extensions, discoveries, and improved
recovery, net of future production and
development costs 9,358 276,770 181,185
Revisions of quantity estimates (23,314) (12,399) (22,438)
Accretion of discount 90,978 28,581 9,975
Net change in income taxes 224,290 (209,090) (29,492)
Changes in production rates, timing and other (61,739) 11,966 (12,829)
---------- ---------- ----------
Standardized measure - end of period $ 254,857 $ 671,197 $ 256,322
========== ========== ==========
55
13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
2001
Total revenues $20,812 $17,712 $12,715 $10,513
Total costs and expenses 11,314 12,398 12,311 22,936
Income tax expense (benefit) 3,324 1,860 142 (4,349)
Net income 6,174 3,454 262 (8,074)
Net income per share-basic 0.44 0.24 0.00 (.63)
Net income per share-diluted 0.41 0.23 0.00 (.63)
2000
Total revenues $10,118 $14,716 $16,422 $16,821
Total costs and expenses 8,354 9,935 9,958 10,820
Income tax expense 600 1,626 2,197 2,040
Net income 1,164 3,155 4,267 3,961
Net income per share-basic 0.05 0.21 0.30 0.25
Net income per share-diluted 0.05 0.21 0.29 0.24
56
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III.
ITEMS 10, 11, 12 &13
For information concerning Item 10 - Directors and Executive Officers of the
Registrant, Item 11 - Executive Compensation, Item 12 - Security Ownership of
Certain Beneficial Owners and Management and Item 13 - Certain Relationships and
Related Transactions, see the definitive Proxy Statement of Callon Petroleum
Company relating to the Annual Meeting of Stockholders on May 8, 2002 which will
be filed with the Securities and Exchange Commission and is incorporated herein
by reference.
57
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. The following is an index to the financial statements and financial
statement schedules that are filed as part of this Form 10-K on pages 33 through
56.
Report of Independent Public Accountants
Consolidated Balance Sheets as of the Years Ended December 31, 2001 and
2000
Consolidated Statements of Operations for the Three Years in the Period
Ended December 31, 2001
Consolidated Statements of Stockholders' Equity for the Three Years in the
Period Ended December 31, 2001
Consolidated Statements of Cash Flows for the Three Years in the Period
Ended December 31, 2001
Notes to Consolidated Financial Statements
(a) 2. Schedules other than those listed above are omitted because they are not
required, not applicable or the required information is included in the
financial statements or notes thereto.
(a) 3. Exhibits:
2. Plan of acquisition, reorganization, arrangement, liquidation or
succession*
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended
(incorporated by reference from Exhibit 3.1 of the Company's
Registration Statement on Form S-4, filed August 4, 1994, Reg.
No. 33-82408)
3.2 Certificate of Merger of Callon Consolidated Partners, L. P. with
and into the Company dated September 16, 1994 (incorporated by
reference from Exhibit 3.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 1994, File No. 000-25192)
3.3 Bylaws of the Company (incorporated by reference from Exhibit 3.2
of the Company's Registration Statement on Form S-4, filed August
4, 1994, Reg. No. 33-82408)
4. Instruments defining the rights of security holders, including
indentures
4.1 Specimen Common Stock Certificate (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed August 4, 1994, Reg. No. 33-82408)
58
4.2 Specimen Preferred Stock Certificate (incorporated by reference
from Exhibit 4.2 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)
4.3 Designation for Convertible, Exchangeable Preferred Stock, Series
A (incorporated by reference from Exhibit 4.3 of the Company's
Registration Statement on Form S-1, filed November 13, 1995, Reg.
No. 33-96700)
4.4 Indenture for Convertible Debentures (incorporated by reference
from Exhibit 4.4 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)
4.5 Certificate of Correction on Designation of Series A Preferred
Stock (incorporated by reference from Exhibit 4.4 of the
Company's Registration Statement on Form S-1, filed November 22,
1996, Reg. No. 333-15501)
4.6 Indenture for the Company's 10.125% Senior Subordinated Notes due
2002 dated as of July 31, 1997 (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed September 25, 1997, Reg. No. 333-36395)
4.7 Form of Note Indenture for the Company's 10.25% Senior
Subordinated Notes due 2004 (incorporated by reference from
Exhibit 4.10 of the Company's Registration Statement on Form S-2,
filed June 14, 1999, Reg. No. 333-80579)
4.8 Rights Agreement between Callon Petroleum Company and American
Stock Transfer & Trust Company, Rights Agent, dated March 30,
2000 (incorporated by reference from Exhibit 99.1 of the
Company's Registration Statement on Form 8-A, filed April 6,
2000, File No. 001-14039)
4.9 Subordinated Indenture for the Company dated October 26, 2000
(incorporated by reference from Exhibit 4.1 of the Company's
Current Report on Form 8-K dated October 24, 2000, File No.
001-14039)
4.10 Supplemental Indenture for the Company's 11% Senior Subordinated
Notes due 2005 (incorporated by reference from Exhibit 4.2 of the
Company's Current Report on Form 8-K dated October 24, 2000, File
No. 001-14039)
4.11 Warrant dated as of June 29, 2001 entitling Duke Capital
Partners, LLC to purchase common stock from the Company.
(incorporated by reference to Exhibit 4.11 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2001,
File No. 001-14039)
9. Voting trust agreement
None.
59
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between
the Company and NOCO Enterprises, L. P. (incorporated by
reference from Exhibit 10.2 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.2 Counterpart to Registration Rights Agreement by and between the
Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
reference from Exhibit 10.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 2000, File No. 001-14039)
10.3 Registration Rights Agreement dated September 16, 1994 between
the Company and Callon Stockholders (incorporated by reference
from Exhibit 10.3 of the Company's Registration Statement on Form
8-B filed October 3, 1994)
10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated
by reference from Exhibit 10.5 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.5 Consulting Agreement between the Company and John S. Callon dated
June 19, 1996 (incorporated by reference from Exhibit 10.10 of
the Company's Registration Statement on Form S-1, filed November
5, 1996, Reg. No. 333-15501)
10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the Post-Effective
Amendment No. 1 to the Company's Registration Statement on Form
S-8, filed February 5, 1999, Reg No. 333-29537)
10.7 Purchase and Sale Agreement between Callon Petroleum Operating
Company and Murphy Exploration Company, dated May 26, 1999
(incorporated by reference from Exhibit 10.11 on Form S-2, filed
June 14, 1999, Reg. No. 333-80579)
10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended on
May 9, 2000 (incorporated by reference from Appendix I of the
Company's Definitive Proxy Statement of Schedule 14A filed March
28, 2000)
10.9 Credit Agreement dated as of October 30, 2000 between the Company
and First Union National Bank, as administrative agent for the
lenders (incorporated by reference from Exhibit 10.2 of the
Company's Quarterly Report on Form 10-Q for the period ended
September 30, 2000, File No. 001-14039)
10.10 Credit Agreement dated as of June 29, 2001 between the Company
and Duke Capital Partners, LLC, as Administrative Agent
(incorporated by reference to Exhibit 10.01 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2001,
File No. 001-14039)
10.11 Second Amendment to Credit Agreement by and among the Company and
First Union National Bank, as Administrative Agent, effective as
of June 29, 2001 (incorporated by reference to Exhibit 10.01 of
the Company's Quarterly Report on Form 10-Q for the period ended
June 30, 2001, File No. 001-14039)
60
10.12 Conveyance of Overriding Royalty Interest from the Company to
Duke Capital Partners, LLC, dated June 29, 2001 (incorporated by
reference to Exhibit 10.03 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)
10.13 Callon Petroleum Company 2002 Stock Incentive Plan.
10.14 Change of Control Severance Compensation Agreement by and between
Callon Petroleum and John S. Weatherly dated January 1, 2002.
10.15 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Fred L. Callon, dated January 1,
2002.
10.16 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Dennis W. Christian, dated January
1, 2002.
11. Statement re computation of per share earnings*
12. Statements re computation of ratios*
13. Annual Report to security holders, Form 10-Q or quarterly
reports*
16. Letter re change in certifying accountant*
18. Letter re change in accounting principles*
21. Subsidiaries of the Company
21.1 Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Company's Registration Statement on Form 8-B
filed October 3, 1994)
22. Published report regarding matters submitted to vote of security
holders*
23. Consents of experts and counsel
23.1 Consent of Arthur Andersen LLP
24. Power of attorney*
99. Additional Exhibits
99.1 Letter to the Commission re: Arthur Andersen Representations
*Inapplicable to this filing.
(b) Reports on Form 8-K.
None
61
SIGNATURES
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.
CALLON PETROLEUM COMPANY
Date: March 29, 2002 /s/ Fred L. Callon
--------------- ------------------
Fred L. Callon (principal executive officer, director)
Date: March 29, 2002 /s/ John S. Weatherly
--------------- ---------------------
John S. Weatherly (principal financial officer)
Date: March 29, 2002 /s/ James O. Bassi
--------------- ------------------
James O. Bassi (principal accounting officer)
Date: March 29, 2002 /s/ John S. Callon
--------------- ------------------
John S. Callon (director)
Date: March 29, 2002 /s/ Dennis W. Christian
--------------- -----------------------
Dennis W. Christian (director)
Date: March 29, 2002 /s/ B. F. Weatherly
--------------- -------------------
B. F. Weatherly (director)
Date: March 29, 2002 /s/ Robert A. Stanger
--------------- ---------------------
Robert A. Stanger (director)
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.
CALLON PETROLEUM COMPANY
Date: March 29, 2002 By: /s/ John S. Weatherly
--------------- ----------------------
John S. Weatherly, Senior Vice President
and Chief Financial Officer
62
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2. Plan of acquisition, reorganization, arrangement, liquidation or
succession*
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended
(incorporated by reference from Exhibit 3.1 of the Company's
Registration Statement on Form S-4, filed August 4, 1994, Reg.
No. 33-82408)
3.2 Certificate of Merger of Callon Consolidated Partners, L. P. with
and into the Company dated September 16, 1994 (incorporated by
reference from Exhibit 3.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 1994, File No. 000-25192)
3.3 Bylaws of the Company (incorporated by reference from Exhibit 3.2
of the Company's Registration Statement on Form S-4, filed August
4, 1994, Reg. No. 33-82408)
4. Instruments defining the rights of security holders, including
indentures
4.1 Specimen Common Stock Certificate (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed August 4, 1994, Reg. No. 33-82408)
4.2 Specimen Preferred Stock Certificate (incorporated by reference
from Exhibit 4.2 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)
4.3 Designation for Convertible, Exchangeable Preferred Stock, Series
A (incorporated by reference from Exhibit 4.3 of the Company's
Registration Statement on Form S-1, filed November 13, 1995, Reg.
No. 33-96700)
4.4 Indenture for Convertible Debentures (incorporated by reference
from Exhibit 4.4 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)
4.5 Certificate of Correction on Designation of Series A Preferred
Stock (incorporated by reference from Exhibit 4.4 of the
Company's Registration Statement on Form S-1, filed November 22,
1996, Reg. No. 333-15501)
4.6 Indenture for the Company's 10.125% Senior Subordinated Notes due
2002 dated as of July 31, 1997 (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed September 25, 1997, Reg. No. 333-36395)
4.7 Form of Note Indenture for the Company's 10.25% Senior
Subordinated Notes due 2004 (incorporated by reference from
Exhibit 4.10 of the Company's Registration Statement on Form S-2,
filed June 14, 1999, Reg. No. 333-80579)
4.8 Rights Agreement between Callon Petroleum Company and American
Stock Transfer & Trust Company, Rights Agent, dated March 30,
2000 (incorporated by reference from Exhibit 99.1 of the
Company's Registration Statement on Form 8-A, filed Aril 6, 2000,
File No. 001-14039)
4.9 Subordinated Indenture for the Company dated October 26, 2000
(incorporated by reference from Exhibit 4.1 of the Company's
Current Report on Form 8-K dated October 24, 2000, File No.
001-14039)
4.10 Supplemental Indenture for the Company's 11% Senior Subordinated
Notes due 2005 (incorporated by reference from Exhibit 4.2 of the
Company's Current Report on Form 8-K dated October 24, 2000, File
No. 001-14039)
4.11 Warrant dated as of June 29, 2001 entitling Duke Capital
Partners, LLC to purchase common stock from the Company.
(incorporated by reference to Exhibit 4.11 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2001,
File No. 001-14039)
9. Voting trust agreement
None.
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between
the Company and NOCO Enterprises, L. P. (incorporated by
reference from Exhibit 10.2 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.2 Counterpart to Registration Rights Agreement by and between the
Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
reference from Exhibit 10.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 2000, File No. 001-14039)
10.3 Registration Rights Agreement dated September 16, 1994 between
the Company and Callon Stockholders (incorporated by reference
from Exhibit 10.3 of the Company's Registration Statement on Form
8-B filed October 3, 1994)
10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated
by reference from Exhibit 10.5 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.5 Consulting Agreement between the Company and John S. Callon dated
June 19, 1996 (incorporated by reference from Exhibit 10.10 of
the Company's Registration Statement on Form S-1, filed November
5, 1996, Reg. No. 333-15501)
10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the Post-Effective
Amendment No. 1 to the Company's Registration Statement on Form
S-8, filed February 5, 1999, Reg No. 333-29537)
10.7 Purchase and Sale Agreement between Callon Petroleum Operating
Company and Murphy Exploration Company, dated May 26, 1999
(incorporated by reference from Exhibit 10.11 on Form S-2, filed
June 14, 1999, Reg. No. 333-80579)
10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended on
May 9, 2000 (incorporated by reference from Appendix I of the
Company's Definitive Proxy Statement of Schedule 14A filed March
28, 2000)
10.9 Credit Agreement dated as of October 30, 2000 between the Company
and First Union National Bank, as administrative agent for the
lenders (incorporated by reference from Exhibit 10.2 of the
Company's Quarterly Report on Form 10-Q for the period ended
September 30, 2000, File No. 001-14039)
10.10 Credit Agreement dated as of June 29, 2001 between the Company
and Duke Capital Partners, LLC, as Administrative Agent
(incorporated by reference to Exhibit 10.01 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 2001,
File No. 001-14039)
10.11 Second Amendment to Credit Agreement by and among the Company and
First Union National Bank, as Administrative Agent, effective as
of June 29, 2001 (incorporated by reference to Exhibit 10.01 of
the Company's Quarterly Report on Form 10-Q for the period ended
June 30, 2001, File No. 001-14039)
10.12 Conveyance of Overriding Royalty Interest from the Company to
Duke Capital Partners, LLC, dated June 29, 2001 (incorporated by
reference to Exhibit 10.03 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)
10.13 Callon Petroleum Company 2002 Stock Incentive Plan.
10.14 Change of Control Severance Compensation Agreement by and between
Callon Petroleum and John S. Weatherly dated January 1, 2002.
10.15 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Fred L. Callon, dated January 1,
2002.
10.16 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Dennis W. Christian, dated January
1, 2002.
11. Statement re computation of per share earnings*
12. Statements re computation of ratios*
13. Annual Report to security holders, Form 10-Q or quarterly
reports*
16. Letter re change in certifying accountant*
18. Letter re change in accounting principles*
21. Subsidiaries of the Company
21.1 Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Company's Registration Statement on Form 8-B
filed October 3, 1994)
22. Published report regarding matters submitted to vote of security
holders*
23. Consents of experts and counsel
23.1 Consent of Arthur Andersen LLP
24. Power of attorney*
99. Additional Exhibits
99.1 Letter to the Commission re: Arthur Andersen Representations
*Inapplicable to this filing.