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, 2000
COMMISSION FILE NUMBER 0-25192
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
10.25% Senior Subordinated Notes due 2004 New York Stock Exchange
11.00% Senior Subordinated Notes due 2005 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 $125,850,000 as of March 16, 2001 (based on the
last reported sale price of such stock on the New York Stock Exchange).
As of March 16, 2001, there were 13,353,223 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, 2000) relating to the Annual Meeting of Stockholders to be held on May 4,
2001, which is incorporated into Part III of this Form 10-K.
PART I.
ITEM 1. BUSINESS
OVERVIEW
Callon Petroleum Company (the "Company") has been engaged in the exploration,
development, acquisition and production of oil and gas properties since 1950.
The Company's properties are geographically concentrated primarily offshore in
the Gulf of Mexico and onshore in Louisiana and Alabama. The 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" refers to Callon Petroleum Company and its predecessors and
subsidiaries unless the context requires otherwise.
In 1989, the Company began increasing its 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. The Company focused on reducing operating costs and
implementing production enhancements through the application of technologically
advanced production and recompletion techniques.
Over the past five years, the Company has also placed emphasis on the
acquisition of acreage with exploration and development drilling opportunities
in the Gulf of Mexico Shelf area. The Company acquired an infrastructure of
production platforms, gathering systems and pipelines to minimize development
expenditures of these drilling opportunities. The Company 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). During this past
five-year period, Callon has drilled 26 productive wells and 16 dry holes for a
total of 42 wells and a success rate of 62%. These 26 productive wells include 3
onshore, 17 in the Gulf of Mexico Shelf area and 6 in the deepwater region of
the Gulf.
The Company ended the year 2000 with estimated net proved reserves of 334
billion cubic feet of natural gas equivalent ("Bcfe") and a reserve replacement
rate of 584%. This represents an increase of 28% over 1999 year-end estimated
net proved reserves of 259 Bcfe.
The major focus of the Company's 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 area using the latest available technology.
o Aggressively explore our existing prospect inventory.
o Replenish our prospect inventory with increasing emphasis on prospect
generation.
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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.
EXPLORATION AND DEVELOPMENT ACTIVITIES
Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $82 million in 2000. The Company incurred
approximately $32.6 million in the Gulf of Mexico Shelf area primarily in the
development of the 1999 discoveries at South Marsh Island 261 and East Cameron
Block 275. Included in these expenditures as exploration costs, is approximately
$7.5 million related to three unsuccessful Gulf of Mexico Shelf prospects
evaluated during 2000. The Gulf of Mexico Deepwater area expenditures accounted
for the remainder of the total capital expended, along with $5.8 million
incurred in leasehold and seismic acquisition costs and $11.9 million of
interest and general and administrative costs allocable directly to exploration
and development projects. The Gulf of Mexico Deepwater area expenditures
included three unsuccessful exploration projects totaling $9.3 million and the
balance was incurred for additional delineation drilling at the Company's Medusa
discovery and the drilling of a test well and delineation drilling at the
Entrada discovery in 2000. The Entrada discovery is located on Garden Banks
Block 782, and reached total depth in April 2000.
As a result of recent successes in the Gulf of Mexico Deepwater area, the
Company is faced with increased costs to develop these significant proved
undeveloped reserves. Substantially all of the future development costs will be
incurred in 2001 and beyond. The Company is currently evaluating various
financing alternatives to address these issues. While management believes there
are a number of financing sources available to the Company, no assurances can be
made that the Company 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
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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.
Also, because of the short life of our reserves, our return on the investment we
make in our oil and gas wells and the value of our oil and gas wells will depend
significantly on prices prevailing during relatively short production periods.
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 2000, about 57% of our daily production came from
three of our properties in the Gulf of Mexico. Moreover, one property accounted
for 35% 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, 2000 most
of our proved reserves were located in 11 fields in the Gulf of Mexico, with
approximately 90% of our total net proved reserves attributable to five of 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 DEEP WATER
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 deep water 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.
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OUR DEEP WATER OPERATIONS HAVE SPECIAL OPERATIONAL RISKS THAT MAY NEGATIVELY
AFFECT THE VALUE OF THOSE ASSETS. Drilling operations in the deep water 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. Deep water 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.
In deep water, the time required to commence production following a discovery is
much longer than in shallow water and on-shore. Our deep water 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 deep water wells;
o the availability of materials necessary to construct the facilities;
o 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 deep water prospects and the discounted present value of reserves
attributable to those prospects.
COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT
OPERATIONS. Exploration in the Gulf of Mexico has recently received renewed
interest, especially among major integrated oil companies and large independent
oil companies. The acquisition of exploration prospects, producing properties
and production facilities in the Gulf of Mexico is highly competitive. Factors
which affect our ability to successfully compete are:
o our access to the capital necessary to drill wells and acquire
properties;
o our access to seismic, geological and other information, and our
ability to retain the personnel necessary to properly evaluate such
information;
o the location of, and our ability to access, platforms, pipelines and
other facilities used to produce and transport oil and gas production;
and
o the standards we establish for the minimum projected return on an
investment of our capital.
Our competitors include major integrated oil companies and large independent
energy companies, many of which have greater financial and other resources.
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
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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. Our current capital budget includes drilling 7 gross (1.1 net)
development wells and 21 gross (9.9 net) exploratory wells through fiscal 2001.
The estimated cost, net to us, to drill and complete these wells is
approximately $73 million. The estimated dry hole costs to drill these wells,
which are the costs we would incur if all of the wells were unsuccessful and we
incurred no completion costs, are approximately $38 million. 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
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 will 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."
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OUR RESERVE INFORMATION REPRESENTS ESTIMATES THAT MAY TURN OUT TO BE INCORRECT
IF THE ASSUMPTIONS UPON WHICH THESE ESTIMATES ARE BASED ARE INACCURATE.
Estimating quantities of proved reserves is inherently imprecise and involves
uncertainties and factors beyond our control. The reserve data in this report
represent only estimates. These estimates are based upon assumptions about
future production levels, future oil and gas prices and future operating costs.
As a result, the quantity of 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, 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 deep water wells used in preparing our
reserves are subject to revisions over time as described under " -- Our deep
water operations have special operational risks that may negatively affect the
value of those assets." Information about reserves constitutes 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, 2000, approximately 58.2% 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 deep water
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 hurricanes and other adverse weather conditions. 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
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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.
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 discharge of materials into the environment
or otherwise relating to environmental protection. 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
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present value, discounted at 10%, of future net cash flows from estimated net
proved reserves, using period end oil and gas prices and costs, 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 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 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 volatility of oil and natural gas prices;
o uncertainty of estimates of oil and natural gas reserves;
o impact of competition;
o 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;
o 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 climatic 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.
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CORPORATE OFFICES
The Company's headquarters are located in Natchez, Mississippi, in approximately
51,500 square feet of owned space. In late 2000, the Company opened a field
office in Houston, Texas, staffed with recently hired technical professionals,
to enhance exploration and development efforts. The Company also maintains owned
or leased field offices in the area of the major fields in which it operates
properties or has a significant interest. Replacement of any of the Company's
leased offices would not result in material expenditures by the Company as
alternative locations to its leased space are anticipated to be readily
available.
EMPLOYEES
The Company had 99 employees as of December 31, 2000, none of who are currently
represented by a union. The Company considers itself to have good relations with
its employees. The Company employs eight petroleum engineers and seven 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,
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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.
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.
11
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.
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
12
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 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.
13
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.
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
The Company is engaged in the exploration, development, acquisition and
production of oil and gas properties and natural gas transmission and provides
oil and gas property management services for other investors. The Company's
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, 2000, the Company's estimated net
proved reserves totaled 33.4 million barrels of oil ("MBbl") and 133.4 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 $939.3 million. Gas constitutes
approximately 40% of the Company's total estimated proved reserves and
approximately 20% of the Company's 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 for the Company's twelve largest fields and for all
other properties combined at December 31, 2000.
ESTIMATED NET PROVED RESERVES PRE-TAX
PROVED RESERVES AND PRODUCTION BY 2000 ------------------------------ DISCOUNTED
- ---------------------------------- PRIMARY PRODUCTION OIL GAS TOTAL PRESENT VALUE
FOCUS AREA: OPERATOR (MMcfe) (MBbls) (MMcf) (MMcfe) ($000)
- -------------- -------- ------- ------- ------ ------- -------------
(b) (b) (a)(b)
GULF OF MEXICO SHELF:
Mobile Block 864 Area Callon 5,474 -- 47,582 47,582 $264,436
Main Pass Block 26 SL 15827 Callon 385 116 2,855 3,551 20,248
South Marsh Island 261 Callon 1,960 962 2,995 8,767 18,920
East Cameron Block 275 Callon 1,185 13 2,616 2,694 17,766
High Island Block A-494
"Snapper" Petrosec 668 -- 1,637 1,637 10,852
Main Pass 163 Area Callon 1,317 -- 2,431 2,431 10,404
Chandeleur Block 40 Callon 399 -- 1,470 1,470 9,758
Other Various 2,166 79 2,537 3,011 15,294
-------- -------- -------- -------- --------
TOTAL SHELF AREA 13,554 1,170 64,123 71,143 367,678
-------- -------- -------- -------- --------
GULF OF MEXICO DEEPWATER:
Garden Banks Blocks 738/782/826/827
"Entrada" BP Amoco -- 7,983 29,940 77,838 191,234
Mississippi Canyon 538/582
"Medusa" Murphy -- 9,585 9,288 66,798 130,982
Garden Banks Block 341
"Habanero" Shell -- 6,393 12,547 50,905 112,967
Ewing Bank Block 994
"Boomslang" Murphy -- 7,230 13,015 56,395 102,206
-------- -------- -------- -------- --------
TOTAL DEEPWATER AREA -- 31,191 64,790 251,936 537,389
-------- -------- -------- -------- --------
ONSHORE AND OTHER:
Big Escambia Creek Exxon 421 639 1,523 5,357 12,304
Other Various 1,359 382 2,967 5,259 21,954
-------- -------- -------- -------- --------
TOTAL ONSHORE AND OTHER 1,780 1,021 4,490 10,616 34,258
-------- -------- -------- -------- --------
TOTAL PROVED RESERVES 15,334 33,382 133,403 333,695 $939,325
======== ======== ======== ======== ========
- ----------------
(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, 2000, 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 3.5 Bcf and $29.5
million of pre-tax discounted present value and 2,300 MMcf of 2000
production 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. Callon owns a 20% working interest in
this discovery with BP Amoco holding the remaining working interest.
The operator is evaluating information obtained in a data swap with another
exploration company that has announced a similar discovery adjacent to Entrada
and is incorporating it into the Entrada development plans.
Medusa, Mississippi Canyon Block 538/582
The initial well encountered two intervals with over 120 feet of total pay after
being drilled to a measured depth of 16,241 feet. The test well encountered 59
true vertical feet of pay in the T1 objective in Fault Block A and 61 true
vertical feet of pay in the T4 sand. A sidetrack well, testing the extent of the
discovery, encountered 110 true vertical feet of pay in the T1 objective sand in
Fault Block B. An additional sidetrack well was drilled to test the downdip
limits of the T1 pay sand in Fault Block B and encountered 90 feet (true
vertical depth) of oil pay. A delineation well was drilled in January 2000, and
16
tested the updip limits of the T1 pay sand in Fault Block A. This latest well
was drilled deeper to further delineate the T4 objective, which was discovered
by the original well. Medusa lies in approximately 2,100 feet of water and the
Company owns a 15% working interest with Murphy, the operator owning 60% and
British-Borneo Petroleum, Inc. owning the remaining 25%.
The operator has submitted an Authorization For Expenditure for a floating
production system at Medusa and the integrated project team has been active on
this development project since late third quarter of 2000. The drilling of four
development wells and the completion of one existing wellbore are scheduled to
begin in April 2001. This will provide five initial takepoints for the
production facility. First production is anticipated in late 2002 or early 2003.
Habanero, Garden Banks Block 341
During February 1999 the initial test well on the Company's 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 the second
deepwater success for Callon. Callon owns 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 including sidetracking the existing well with two
additional sidetracks is scheduled to begin by midyear 2001. 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, Callon purchased from Santos USA Corporation an
additional 20% working interest in the Boomslang deepwater discovery on Ewing
Bank Block 994 for $7.3 million. This brought Callon's total working interest in
the well to 55%.
A complete field study has been initiated with a goal of generating a
delineation and development proposal in 2001. Prior to designing production
facilities for Boomslang the Company plans to drill the Sidewinder prospect,
located immediately to the southeast of Boomslang on Ewing Bank Block 995 and
Green Canyon Blocks 24 and 25. Callon owns a 15% working interest in these
leases.
17
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. The Company consummated five acquisitions in this
area for a total of $63.8 million. In total, the Company has 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. The Company was appointed operator of the
Mobile Block 864 unit and three other wells. Net average daily production during
2000 was 15 MMcf per day.
South Marsh Island Block 261
In November 1999, we announced a discovery on this block, which encountered 110
feet of net natural gas pay. We began drilling a second test well in December
1999 and encountered 100 feet of net natural gas pay in five pay sands before it
blew out. We brought the well under control, plugged it and drilled a
replacement well in the first quarter of 2000. Our insurance policy covered the
costs associated with the blowout, the plugging of the well and the drilling of
the replacement well. The #1 well commenced production in May 2000 and was
shut-in during January 2001 after depleting. An evaluation of new seismic
indicated the productive sand is compartmentalized by faulting and the well is
currently scheduled for sidetrack drilling to a separate fault block. The #3
well commenced production in May 2000. Upon depletion, the well is scheduled to
be recompleted in a behind pipe oil sand. We drilled a fourth well in the second
quarter of 2000 and encountered 165 net feet of pay in four pay sands. The
fourth well commenced production on February 10, 2001. We own a 100% working
interest in these wells.
East Cameron Block 275
In December 1999, we announced a discovery, which encountered net natural gas
pay of 160 feet in five intervals between 5,800 feet and 10,500 feet. The well
commenced production in April 2000. The well was recompleted in October 2000 and
subsequently shut-in for work on the host production platform. The well came
back online January 12, 2001. We own a 100% working 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. The well depleted this productive zone in January 2001 and was
recompleted to a behind pipe gas zone in February 2001. We operate this well.
Snapper, High Island Block A-494
In January 1999, we announced a discovery on our Snapper prospect, which we
drilled to a total depth of 8,800 feet. We own a 50% working interest in this
well, which is operated by PetroQuest Energy. The well began production in July
1999.
18
ONSHORE
We own various small royalty and working interests in several onshore areas,
which as of December 31, 2000 had total net proved reserves of 10.6 Bcfe with a
discounted present value of $34.2 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.
OIL AND GAS RESERVES
The following table sets forth certain information about the estimated proved
reserves of the Company as of the dates set forth below.
YEARS ENDED DECEMBER 31,
----------------------------------------
2000(a) 1999(a) 1998
------- ------- ----
(IN THOUSANDS)
Proved developed:
Oil (Bbls) 2,192 1,376 2,079
Gas (Mcf) 67,463 82,109 76,895
Proved undeveloped:
Oil (Bbls) 31,190 22,458 4,819
Gas (Mcf) 65,940 34,326 11,135
Total proved:
Oil (Bbls) 33,382 23,834 6,898
Gas (Mcf) 133,403 116,435 88,030
Estimated pre-tax future net cash flows $1,610,320 $528,659 $152,552
========== ======== ========
Pre-tax discounted present value $ 939,325 $296,513 $99,751
========== ======== ========
Standardized measure of discounted future
net cash flows $ 671,197 $256,322 $99,751
========== ======== ========
(a) The estimates include 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 and 3.5 Bcf, $31.8 million of pre- tax future net
cash flows and $29.5 million of pre-tax discounted present value flows in
2000 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.
The Company's 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 the 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 the control of the Company and 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
19
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.
The Company has 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 drilled and completed by the Company
during the periods indicated. All such wells were drilled in the continental
United States including federal and state waters in the Gulf of Mexico.
The Company owned working and royalty interests in approximately 254 gross (7.0
net) producing oil and 289 gross (30.0 net) producing gas wells as of December
31, 2000. 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 the Company's
wells produce both oil and gas. At December 31, 2000, the Company had one gross
(0.1 net) exploratory oil well in progress.
LEASEHOLD ACREAGE
The following table shows the approximate developed and undeveloped (gross and
net) leasehold acreage of the Company as of December 31, 2000.
LEASEHOLD ACREAGE
-----------------
DEVELOPED UNDEVELOPED
LOCATION GROSS NET GROSS NET
-------- ----- --- ----- ---
Alabama 13,394 13,246 256 29
Louisiana 8,925 6,309 2,375 700
Other States 912 440 1,471 1,142
Federal Waters 135,612 88,071 356,990 112,322
------- ------- ------- -------
Total 158,843 108,066 361,092 114,193
======= ======= ======= =======
20
As of December 31, 2000, the Company owned various royalty and overriding
royalty interests in 1,336 net developed acres and 6,862 undeveloped acres. In
addition, the Company owned 6,247 developed and 119,753 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,
------------
2000 1999 1998
---- ---- ----
Adams Resources Marketing, Ltd. 14% 16% --
Columbia Energy Services -- 29% 22%
Dynegy Marketing & Trade -- 12% 23%
PG&E Energy Trading Corporation -- -- 26%
Reliant Energy Services 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
The Company believes that the title to its 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 the opinion of the Company, are
not so material as to detract substantially from the use or value of such
properties. The Company's 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 the Company or its 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 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 the
Company's rights to production revenues, they have been taken into account in
calculating the Company's net revenue interests and
21
in estimating the size and value of the Company's reserves. The Company believes
that the burdens and obligations affecting its properties are conventional in
the industry for properties of the kind owned by the Company.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in various legal proceedings and claims, which arise
in the ordinary course of Callon's business. Callon does not believe the
ultimate resolution of any such actions will have a material affect on the
Company's 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 2000.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's 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
------------- ---- ---
1999:
First quarter $ 11.875 $ 8.875
Second quarter 11.250 9.875
Third quarter 15.375 10.000
Fourth quarter 15.375 11.625
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
22
As of March 16, 2001, there were approximately 5,283 common stockholders of
record.
The Company has not paid dividends on the Common Stock and intends to retain its
cash flow from operations, net of preferred stock dividends, for the future
operation and development of its business. In addition, the Company's primary
credit facility and the terms of the Company's outstanding subordinated debt
restrict payments of dividends on its Common Stock.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth, as of the dates and for the periods indicated,
selected financial information for the Company. The financial information for
each of the five years in the period ended December 31, 2000 have been derived
from the audited Consolidated Financial Statements of the Company 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 future results for the Company.
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales $ 56,310 $ 37,140 $ 35,624 $ 42,130 $ 25,764
Interest and other 1,767 1,853 2,094 1,508 946
--------- --------- --------- --------- ---------
Total revenues 58,077 38,993 37,718 43,638 26,710
--------- --------- --------- --------- ---------
Costs and expenses:
Lease operating expenses 9,339 7,536 7,817 8,123 7,562
Depreciation, depletion and amortization 17,153 16,727 19,284 16,488 9,832
General and administrative 4,155 4,575 5,285 4,433 3,495
Interest 8,420 6,175 1,925 1,957 313
Accelerated vesting and retirement benefits -- -- 5,761 -- --
Impairment of oil and gas properties -- -- 43,500 -- --
--------- --------- --------- --------- ---------
Total costs and expenses 39,067 35,013 83,572 31,001 21,202
--------- --------- --------- --------- ---------
Income (loss) from operations 19,010 3,980 (45,854) 12,637 5,508
Income tax expense (benefit) 6,463 1,353 (15,100) 4,200 50
--------- --------- --------- --------- ---------
Net income (loss) 12,547 2,627 (30,754) 8,437 5,458
Preferred stock dividends 2,403 2,497 2,779 2,795 2,795
--------- --------- --------- --------- ---------
Net income (loss) available to common shares $ 10,144 $ 130 $ (33,533) $ 5,642 $ 2,663
========= ========= ========= ========= =========
Net income (loss) per common share:
Basic $ .82 $ .01 $ (4.17) $ .91 $ .46
Diluted $ .80 $ .01 $ (4.17) $ .88 $ .45
Shares used in computing net income (loss) per common share:
Basic 12,420 8,976 8,034 6,194 5,835
Diluted 12,745 9,075 8,034 6,422 5,952
BALANCE SHEET DATA (END OF PERIOD):
Oil and gas properties, net $ 258,613 $ 194,365 $ 141,905 $ 150,494 $ 82,489
Total assets $ 301,569 $ 259,877 $ 181,652 $ 190,421 $ 118,520
Long-term debt, less current portion $ 134,000 $ 100,250 $ 78,250 $ 60,250 $ 24,250
Stockholders' equity $ 136,328 $ 124,380 $ 84,484 $ 113,701 $ 77,864
- ---------------
23
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 the standardized measure, 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 ($28.7 million after-tax) during the fourth quarter of 1998.
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 the
Company's financial condition and results of operations. The Company's 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. The Company's
revenues, profitability and future growth and the carrying value of its oil and
gas properties are substantially dependent on prevailing prices of oil and gas
and its ability to find, develop and acquire additional oil and gas reserves
that are economically recoverable. The Company's ability to maintain or increase
its 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 increased significantly at
December 31, 2000 to 334 billion cubic feet of natural gas equivalent (Bcfe).
This represents an increase of 28% over previous year-end 1999 estimated proved
reserves of 259 Bcfe. This increase in 2000 is primarily due to results of
drilling activity in the deepwater areas of the Gulf of Mexico, along with
drilling successes on the Gulf of Mexico Shelf area.
24
These reserve estimates include 3.5 Bcfe at December 31, 2000 and 5.8 Bcfe at
December 31, 1999 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 the control of the
Company. 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 the Company's carrying value of its proved reserves,
borrowing capacity, revenues, profitability and cash flows from operations. The
Company uses 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 its future production and does not
use them for trading purposes. On a Mcfe basis, natural gas represents 86% of
the budgeted 2001 production and 40% of proved reserves at year-end.
Inflation has not had a material impact on the Company and is not expected to
have a material impact on the Company in the future.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of capital are its cash flows from operations,
borrowings under our bank Credit Facility and sales of debt and equity
securities. Net cash and cash equivalents decreased during 2000 by $22.8
million. Cash provided from operating activities during 2000 totaled $28.7
million. The Company completed the sale of its Senior Subordinated Notes due
2005 in October 2000 for net proceeds of approximately $31.5 million. An
additional $24.9 million (net) was borrowed under our bank Credit Facility.
Dividends paid on preferred stock were $2.2 million. Average debt outstanding
was $118.3 million during 2000 compared to $96.9 million in 1999. At December
31, 2000, the Company had working capital of $1.1 million.
Effective October 31, 2000, the Company entered into a $75.0 million Credit
Facility 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 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 the Company's proved producing oil and gas reserves
as determined by the bank. The Company may borrow, pay, reborrow and repay under
the Credit Facility until July 31, 2002, on which date, the Company must repay
in full all amounts then outstanding. At December 31, 2000, availability under
the Credit Facility was $25 million.
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 $38.2 million were
used to pay down the Credit Facility and finance the capital budget. 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 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 Senior Subordinated Notes due
2005, on October 26, 2000 for net proceeds of $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 the
25
Company's outstanding 10% Senior Subordinated Notes due 2001 in conjunction with
a tender offer. The Company also redeemed the remaining $3.4 million of its 10%
Senior Subordinated Notes due 2001 not tendered in the offer.
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. The Company is in compliance
with these covenants at December 31, 2000.
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. The proceeds from the stock offering were used to pay the
outstanding balance of the Company's Credit Facility and to fund, together with
internally generated cash flows from operations, the remaining portion of the
Company's 1999 and part of the 2000 capital expenditure budget.
The Company's plans for 2001 include capital expenditures budgeted at $90
million. The Company currently expects to spend $21 million to drill up to 14
wells in the shelf area of the Gulf of Mexico. An estimated $18 million, net to
the Company, will be required to complete and develop the successful wells. This
estimate is dependent on exploration success. Plans also call for $36 million to
be invested in the deepwater area of the Gulf of Mexico with $18 million of the
investment allocated to development of the Company's four deepwater discoveries.
The Company will continue to build its portfolio of drilling prospects and is
budgeted to spend approximately $9 million on seismic and new Gulf of Mexico
lease acquisitions.
Projected cash flows from operations, cash on hand and borrowings under the
Credit Facility are anticipated to be sufficient to fund the Company's shelf
drilling program and seismic and lease acquisitions. Conventional debt or equity
offerings may be used to finance the Company's capital expenditure program, but
other options are being considered for the Company's deepwater development
projects. One such option is to develop a discovery as a production hub, with
some or all of the financing provided by a partner, and charge other companies
with discoveries in the area for access to the processing equipment on the
platform.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect to the
oil and gas operations of the Company for each of the three years in the period
ended December 31, 2000.
DECEMBER 31,
-------------------------------------
2000(a)(b) 1999(a)(b) 1998(a)
---------- --------- -----------
Production:
Oil (MBbls) 232 330 310
Gas (MMcf) 13,943 14,606 14,036
Total production (MMcfe) 15,334 16,589 15,894
Average daily production (MMcfe) 41.9 45.5 43.5
Average sales price:
Oil (per Bbl) $ 27.88 $ 12.16 $ 12.41
Gas (per Mcf) $ 3.57 $ 2.27 $ 2.26
Total production (per Mcfe) $ 3.67 $ 2.24 $ 2.24
Average costs (per Mcfe):
Lease operating expenses (excluding severance taxes) $ .55 $ .39 $ .44
Severance taxes $ .06 $ .07 $ .06
Depletion $ 1.10 $ .99 $ 1.19
General and administrative (net of management fees) $ .27 $ .28 $ .33
- ------------
(a) Includes hedging gains and losses
(b) Includes volumes of 2,300 MMcf and 1,300 MMcf for 2000 and 1999,
respectively, at an average price of $2.08 per Mcf associated with a
volumetric production payment.
26
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.
27
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.
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 a
combination of an increase in the amortization base by 56% (primarily 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 capitalized 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
The Company's 2000 results include a deferred income tax expense of $6.5
million. The Company has 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. The Company believes 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, 1999 AND
1998
OIL AND GAS REVENUES
Oil and gas revenues for 1999 were $37.1 million, a 4% increase from the 1998
amount of $35.6 million. Similarly, 1999 oil and gas production of 16,589 MMcfe
increased by 4% over the 1998 amount of 15,894 MMcfe.
28
Oil production increased from 310,000 barrels in 1998 to 330,000 barrels in 1999
but the average sales price declined from $12.41 in 1998 to $12.16 in 1999. As a
result, oil revenues went from $3.8 million in 1998 to $4.0 million in 1999. The
increase in oil production was primarily from Main Pass 26 and Eugene Island 335
offset by the loss of production in 1999 from the Black Bay Field, which was
sold in 1998.
Gas revenues for 1999 were $33.1 million based on sales of 14.6 Bcf at an
average sales price of $2.27 per Mcf. For 1998, gas revenues were $31.8 million
based on production of 14 Bcf sold at an average sales price of $2.26 per Mcf.
When compared to 1998, the Company in 1999 added gas production from new
discoveries at Main Pass 26 and Eugene Island 335 but has experienced reduced
production from several Shallow Miocene properties, which normally have steep
decline curves. Except for the increase at Main Pass 31, which was the result of
a recompletion, other properties continue to experience normal and expected
declines.
LEASE OPERATING EXPENSES AND SEVERANCE TAXES
Lease operating expenses, including severance taxes, decreased from $7.8 million
in 1998 to $7.5 million in 1999 as a result of a decrease in operating expenses
in the Main Pass 163 Area and the North Dauphin Island Field as well as the sale
of the Black Bay Field in 1998. This decline was offset by the Snapper, Main
Pass 36, Main Pass 26 and Kemah properties, which began operations in 1999.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization decreased due to the combined effect of
the net increase in proved reserves during 1999 (primarily in the fourth quarter
of 1999), the level of finding costs attributable to reserves added in 1999 and
the reduction of the full cost pool due to an impairment of oil and gas
properties at December 31, 1998. Total charges decreased from $19.3 million, or
$1.21 per Mcfe in 1998, to $16.7 million, or $1.01 per Mcfe in 1999.
GENERAL AND ADMINISTRATIVE
General and administrative expenses for 1999 were $4.6 million, or $.28 per
Mcfe, compared to $5.3 million, or $.33 per Mcfe, in 1998. This 13% decrease is
primarily due to a reduction of staff in 1999 along with an increase in overhead
allocable to employees directly engaged in the acquisition, exploration and
development of oil and gas properties in 1999.
INTEREST EXPENSE
Interest expense for 1999 and 1998 was $6.2 million and $1.9 million,
respectively. This increase is a result of a decrease in interest capitalized on
unevaluated oil and gas properties and the increase in interest rates and in
average debt outstanding in 1999 versus 1998. This average debt outstanding
increase is directly related to the Senior Subordinated Notes issued in July
1999 and the Credit Facility borrowings during the year. The Common Stock
offering completed in November 1999 reduced Credit Facility debt at the end of
1999.
INCOME TAXES
The Company's 1999 results include a deferred income tax expense of $1.4
million. The Company has 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. The Company believes 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.
29
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The Company's revenues are derived from the sale of its crude oil and natural
gas production. From time to time, the Company has entered into hedging
transactions that lock in for specified periods the prices the Company will
receive for the production volumes to which the hedge relates. The hedges reduce
the Company's exposure on the hedged volumes to decreases in commodities prices
and limit the benefit the Company might otherwise have received from any
increases in commodities prices on the hedged volumes.
As of December 31, 2000, the Company had open collar contracts with third
parties whereby minimum floor prices and maximum ceiling prices are contracted
and applied to related contract volumes. These agreements in effect for 2001 are
for average gas volumes of 390,000 Mcf per month beginning in January 2001
through October 2001 at (on average) a ceiling price of $5.86 and floor price of
$4.69. The Company had no open oil hedging contracts at December 31, 2000.
The calculation of the fair market value of the outstanding hedging contracts as
of December 31, 2000 indicated a $5.8 million market value liability based on
market prices at that date. Natural gas prices have declined significantly since
year-end. As a result, and if the price decline for natural gas is sustained
throughout the contract periods, the market value liability of the derivatives
described above have decreased significantly also.
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 Company adopted SFAS 133 effective
January 1, 2001.
This statement establishes accounting and reporting standards that differ from
those used in prior years. SFAS 133 requires that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured at its
fair value at the date of adoption and requires that future changes in the
derivatives fair value be recognized currently in earnings unless specific hedge
accounting criteria are met. Special accounting for qualifying hedges allows a
derivative instrument's gain or loss to offset related results on the hedged
item in the income statement, to the extent effective, and requires that the
Company must formally document, designate, and assess effectiveness of
transactions that receive hedge accounting. The Company believes that its hedges
described above, to the extent of intrinsic value, will qualify as cash flow
hedges under SFAS 133.
The Company has not yet quantified all effects of adopting SFAS 133 on its
future financial statements. However, the Statement will increase volatility in
earnings and other comprehensive income as market prices for the natural gas
hedged changes.
Based on projected annual sales volumes for 2001 (excluding forecast production
increases over 2000), a 10% decline in the prices the Company receives for its
crude oil and natural gas production would have an approximate $7.1 million
impact on the Company's revenues. The hypothetical impact on the decline in oil
and gas prices does not include the incremental gain that would be realized upon
a decline in prices by the oil and gas hedging contracts in place as of December
31, 2000.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
----
Report of Independent Public Accountants 32
Consolidated Balance Sheets as of December 31, 2000 33
and 1999
Consolidated Statements of Operations for Each of the Three Years
in the Period Ended December 31, 2000 34
Consolidated Statements of Stockholders' Equity
for Each of the Three Years in the Period Ended December 31, 2000 35
Consolidated Statements of Cash Flows for Each of the Three Years
in the Period Ended December 31, 2000 36
Notes to Consolidated Financial Statements 37
31
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,
2000 and 1999, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. 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, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
February 22, 2001
32
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
-------------------------------
2000 1999
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 11,876 $ 34,671
Accounts receivable 9,244 5,362
Advance to operators 1,131 --
Other current assets 207 189
------------ ------------
Total current assets 22,458 40,222
------------ ------------
Oil and gas properties, full-cost accounting method:
Evaluated properties 589,549 511,689
Less accumulated depreciation, depletion and amortization (378,589) (361,758)
------------ ------------
210,960 149,931
Unevaluated properties excluded from amortization 47,653 44,434
------------ ------------
Total oil and gas properties 258,613 194,365
------------ ------------
Pipeline and other facilities, net 5,537 5,860
Other property and equipment, net 1,790 1,450
Deferred tax asset 8,573 14,995
Long-term gas balancing receivable 643 243
Other assets, net 3,955 2,742
------------ ------------
Total assets $ 301,569 $ 259,877
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 17,842 $ 16,786
Undistributed oil and gas revenues 1,411 2,082
Accrued net profits interest payable 2,146 1,676
------------ ------------
Total current liabilities 21,399 20,544
------------ ------------
Long-term debt 134,000 100,250
Deferred revenue on sale of production payment 7,236 12,080
Accrued retirement benefits 1,886 2,107
Long-term gas balancing payable 720 516
------------ ------------
Total liabilities 165,241 135,497
------------ ------------
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, 2000 and
1,045,461 outstanding at December 31, 1999 with
a liquidation
preference of $15,021,525 at December 31, 2000 6 11
Common Stock, $.01 par value; 20,000,000
shares authorized; 13,327,675 and 12,239,238 shares
outstanding at December 31, 2000 and 1999, respectively 133 122
Treasury stock (99,078 shares at cost) (1,183) (1,183)
Capital in excess of par value 151,223 149,425
Retained earnings (deficit) (13,851) (23,995)
------------ ------------
Total stockholders' equity 136,328 124,380
------------ ------------
Total liabilities and stockholders' equity $ 301,569 $ 259,877
============ ============
The accompanying notes are an integral part of these financial statements.
33
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2000 1999 1998
------------ ------------ ------------
Revenues:
Oil and gas sales $ 56,310 $ 37,140 $ 35,624
Interest and other 1,767 1,853 2,094
------------ ------------ ------------
Total revenues 58,077 38,993 37,718
------------ ------------ ------------
Costs and expenses:
Lease operating expenses 9,339 7,536 7,817
Depreciation, depletion and amortization 17,153 16,727 19,284
General and administrative 4,155 4,575 5,285
Interest 8,420 6,175 1,925
Accelerated vesting and retirement benefits -- -- 5,761
Impairment of oil and gas properties -- -- 43,500
------------ ------------ ------------
Total costs and expenses 39,067 35,013 83,572
------------ ------------ ------------
Income (loss) from operations 19,010 3,980 (45,854)
Income tax expense (benefit) 6,463 1,353 (15,100)
------------ ------------ ------------
Net income (loss) 12,547 2,627 (30,754)
Preferred stock dividends 2,403 2,497 2,779
------------ ------------ ------------
Net income (loss) available to common shares $ 10,144 $ 130 $ (33,533)
============ ============ ============
Net income (loss) per common share:
Basic $ .82 $ .01 $ (4.17)
============ ============ ============
Diluted $ .80 $ .01 $ (4.17)
============ ============ ============
Shares used in computing net income (loss) per common share:
Basic 12,420 8,976 8,034
============ ============ ============
Diluted 12,745 9,075 8,034
============ ============ ============
The accompanying notes are an integral part of these financial statements.
34
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
UNEARNED
COMPENSATION CAPITAL IN RETAINED
PREFERRED COMMON TREASURY RESTRICTED EXCESS OF EARNINGS
STOCK STOCK STOCK STOCK PAR VALUE (DEFICIT)
---------- ---------- ---------- ------------- ----------- ----------
Balances, December 31, 1997 $ 13 $ 79 $ -- $ (2,232) $ 106,433 $ 9,408
Net income (loss) -- -- -- -- -- (30,754)
Preferred stock dividends -- -- -- -- 15 (2,779)
Shares issued pursuant to employee
benefit and option plan -- -- -- -- 235 --
Employee stock purchase plan -- -- -- -- 163 --
Restricted stock plan -- 2 -- (2,731) 2,584 --
Earned portion of restricted stock -- -- -- 4,963 -- --
Conversion of preferred shares to common -- 1 -- -- (1) --
Stock buyback plan -- -- (915) -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Balances, December 31, 1998 13 82 (915) -- 109,429 (24,125)
Net income (loss) -- -- -- -- -- 2,627
Sale of common stock -- 37 -- -- 40,994 --
Preferred stock dividends -- -- -- -- -- (2,222)
Shares issued pursuant to employee
benefit and option plan -- -- -- -- 274 --
Employee stock purchase plan -- -- -- -- 67 --
Restricted stock plan -- (2) -- -- (1,613) --
Conversion of preferred shares to common (2) 5 -- -- 274 (275)
Stock buyback plan -- -- (268) -- -- --
---------- ---------- ---------- ---------- ---------- ----------
Balances, December 31, 1999 11 122 (1,183) -- 149,425 (23,995)
Net income (loss) -- -- -- -- -- 12,547
Preferred stock dividends -- -- -- -- -- (1,978)
Shares issued pursuant to employee
benefit and option plan -- -- -- -- 1,069 --
Employee stock purchase plan -- -- -- -- 269 --
Tax benefits related to stock compensation plans -- -- -- -- 41 --
Conversion of preferred shares to common (5) 11 -- -- 419 (425)
---------- ---------- ---------- ---------- ---------- ----------
Balances, December 31, 2000 $ 6 $ 133 $ (1,183) $ -- $ 151,223 $ (13,851)
========== ========== ========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements.
35
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN THOUSANDS)
2000 1999 1998
------------ ------------ ------------
Cash flows from operating activities:
Net income (loss) $ 12,547 $ 2,627 $ (30,754)
Adjustments to reconcile net income (loss) to
cash provided by operating activities:
Depreciation, depletion and amortization 17,598 17,232 19,791
Impairment of oil and gas properties -- -- 43,500
Amortization of deferred costs 1,034 707 619
Amortization of deferred production payment revenue (4,844) (2,710) --
Deferred income tax expense (benefit) 6,463 1,353 (15,100)
Noncash charge related to compensation plans 1,069 275 7,583
Changes in current assets and liabilities:
Accounts receivable (3,882) 662 6,144
Advance to operators (1,131) 1,271 (1,271)
Other current assets (18) (11) 57
Current liabilities 1,077 1,981 (876)
Change in gas balancing receivable (400) (44) 43
Change in gas balancing payable 204 27 85
Change in other long-term liabilities (221) (216) --
Change in other assets, net (751) (134) (116)
------------ ------------ ------------
Cash provided (used) by operating activities 28,745 23,020 29,705
------------ ------------ ------------
Cash flows from investing activities:
Capital expenditures (81,849) (51,709) (63,501)
Cash proceeds from sale of mineral interests -- -- 9,909
------------ ------------ ------------
Cash provided (used) by investing activities (81,849) (51,709) (53,592)
------------ ------------ ------------
Cash flows from financing activities:
Equity issued related to employee stock plans 269 68 414
Purchase of treasury shares -- (268) (915)
Payment on debt (29,250) (42,500) --
Increase in debt 63,000 64,500 18,000
Deferred financing costs (1,496) (1,823) --
Restricted stock plan -- (1,615) (130)
Sale of common stock -- 41,031 --
Cash dividends on preferred stock (2,214) (2,333) (2,779)
------------ ------------ ------------
Cash provided (used) by financing activities 30,309 57,060 14,590
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents (22,795) 28,371 (9,297)
Cash and cash equivalents:
Balance, beginning of period 34,671 6,300 15,597
------------ ------------ ------------
Balance, end of period $ 11,876 $ 34,671 $ 6,300
============ ============ ============
The accompanying notes are an integral part of these financial statements.
36
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
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.
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. SFAS
133 is effective for fiscal years beginning after June 15, 2000, with earlier
application permitted. The Company adopted SFAS 133 effective January 1, 2001.
37
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 comprehensive discussion of our derivative financial instruments.
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.
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.
38
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 in years prior to and including
2000 as hedges and have been recognized as an adjustment to oil and gas sales in
the period in which they are related. Future accounting treatment will be 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 $78,000 and $38,000 at December 31, 2000 and 1999,
respectively. Net recoveries were $40,000 in 2000. There were no provisions to
expense in the three-year period ended December 31, 2000.
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,
----------------------------
2000 1999 1998
------ ------ ------
Adams Resources Marketing, Ltd. 14% 16% --
Columbia Energy Services -- 29% 22%
Dynegy Marketing & Trade -- 12% 23%
PG&E Energy Trading Corporation -- -- 26%
Reliant Energy Services 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.
The Company paid no federal income taxes for the three years ended December 31,
2000. During the years ended December 31, 2000, 1999 and 1998, the Company made
cash payments of $11,449,000, $9,013,000 and $6,229,000 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 per common share for 2000 and 1999 were 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
39
the treasury stock method. In 1998, all options were excluded from the
computation of diluted loss per share because they were antidilutive. 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):
2000 1999 1998
------------ ------------ ------------
(a) Net income (loss) available for common stock $ 10,144 $ 130 $ (33,533)
Preferred dividends assuming conversion of
preferred stock (if dilutive) -- -- --
(b) Income available for common stock assuming
conversion of preferred stock (if dilutive) $ 10,144 $ 130 $ (33,533)
(c) Weighted average shares outstanding 12,420 8,976 8,034
Dilutive impact of stock options 325 99 --
Convertible preferred stock (if dilutive) -- -- --
(d) Total diluted shares 12,745 9,075 8,034
Stock options excluded due to antidilutive impact -- -- 163
Basic income (loss) per share (a/c) $ .82 $ .01 $ (4.17)
Diluted income (loss) per share (b/d) $ .80 $ .01 $ (4.17)
FAIR VALUE OF FINANCIAL INSTRUMENTS
Fair value of cash, cash equivalents, accounts receivable, accounts payable and
long-term debt approximates book value at December 31, 2000 and 1999. Fair value
of long-term debt (specifically, the 10%, the 10.125%, the 10.25% and the 11%
Senior Subordinated Notes) was based on quoted market value.
The calculation of the fair market value of the outstanding hedging contracts
(see Note 6) as of December 31, 2000 indicated a $5.8 million market value
liability based on market prices at that date. See Note 6 for further discussion
related to the derivative activity of the Company.
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 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 2000 and 1999.
Accordingly, the Company has recorded a deferred tax asset at December 31, 2000
and 1999 as follows:
40
DECEMBER 31,
-------------------------------
2000 1999
------------ ------------
(IN THOUSANDS)
Federal net operating loss carryforwards $ 14,352 $ 13,143
Statutory depletion carryforward 4,152 4,087
Temporary differences:
Oil and gas properties (8,937) (2,200)
Pipeline and other facilities (1,938) (2,051)
Non-oil and gas property (81) (102)
Other 1,025 2,118
------------ ------------
Total tax asset 8,573 14,995
Valuation allowance -- --
------------ ------------
Net tax asset $ 8,573 $ 14,995
============ ============
At December 31, 2000, the Company had, for federal tax reporting purposes, net
operating loss carryforwards of $41.0 million, which expire in 2001 through
2015. 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 differed from
the provision for income taxes at the statutory rate as follows:
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Computed expense (benefit) at the expected
statutory rate $ 6,463 $ 1,353 $ (15,590)
Other -- -- 490
------------ ------------ ------------
Deferred income tax expense (benefit) $ 6,463 $ 1,353 $ (15,100)
============ ============ ============
4. 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.
41
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
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 1.75% above a defined "Eurodollar" rate for
periods up to six months. The weighted average interest rate for the Credit
Facility debt outstanding at December 31, 2000 and 1999 was 8.53% and 9.00%,
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.
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.
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
42
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 the Company's outstanding 10% Senior Subordinated Notes due 2001 in
conjunction with a tender offer. The Company also redeemed the remaining $3.4
million of its 10% Senior Subordinated Notes due 2001 not tendered in the offer.
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. The Company is in compliance
with these covenants at December 31, 2000.
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, and are reported in 2000 and prior years as a component of
oil and gas revenues. Gains or losses attributable to the termination of a
contract are deferred and recognized in revenue when the oil and gas production
is sold. Approximately $3,290,000 and $1,559,000 were recognized as a reduction
of oil and gas revenue in 2000 and 1999 respectively, and $1,886,000 was
recognized as additional oil and gas revenue in 1998 as a result of such
agreements.
As of December 31, 2000, the Company had open collar contracts with third
parties whereby minimum floor prices and maximum ceiling prices are contracted
and applied to related contract volumes. These agreements in effect for 2001 are
for average gas volumes of 390,000 Mcf per month beginning in January 2001
through October 2001 at (based on a weighted average of the contracts) a ceiling
price of $5.86 and floor price of $4.69. The Company had no open oil hedging
contracts at December 31, 2000.
As discussed in Note 2, the Company adopted SFAS 133 effective January 1, 2001.
This statement establishes accounting and reporting standards that differ from
those used in prior years. SFAS 133 requires that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured at its
fair value at the date of adoption. The statement requires that future changes
in the derivatives fair value be recognized currently in earnings unless
specific hedge accounting criteria are met. Special accounting for qualifying
hedges allows a derivative instrument's gain or loss to offset related results
on the hedged item in the income statement, to the extent effective, and
requires that the Company must formally document, designate, and assess
effectiveness of transactions that receive hedge accounting. The Company
believes that its hedges described above, to the extent of intrinsic value, will
qualify as cash flow hedges under SFAS 133.
The Company has not yet quantified all effects of adopting SFAS 133 on its
future financial statements. However as discussed in the following paragraphs,
the Statement will increase volatility in earnings and other comprehensive
income.
43
The Company will record a market value liability in 2001 of $5.8 million related
to the fair value of the derivatives outstanding at January 1, 2001 with a
corresponding charge, net of tax, to other comprehensive income. This transition
adjustment will be reclassified into earnings in the same period or periods
during which the hedged forecasted transactions affects earnings, adjusted for
any future changes in fair value.
Oil and gas prices have declined significantly since January 1, 2001(the date of
the transition entry to record the derivatives at fair value) causing
substantially all of the liability recorded on the balance sheet at that date to
be reversed in the first quarter of 2001.
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, 2000 total estimated site
restoration, dismantlement and abandonment costs were approximately $6,227,000,
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.
The Company, as part of the Consolidation, entered into Registration Rights
Agreements whereby the former stockholders of certain of the Constituent
Entities are entitled to require the Company to register Common Stock of the
Company owned by them with the Securities and Exchange Commission for sale to
the public in a firm commitment public offering 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 discounts and commissions, which will be
paid by the respective sellers of the Common Stock.
44
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,
-----------------------------------------
2000 1999 1998
--------- --------- ---------
(IN THOUSANDS)
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance $ 511,689 $ 444,579 $ 398,046
Property acquisition costs 3,211 24,153 9,464
Exploration costs 51,837 37,427 42,617
Development costs 25,242 5,530 4,361
Sale of mineral interests (2,430) -- (9,909)
--------- --------- ---------
End of period balance $ 589,549 $ 511,689 $ 444,579
========= ========= =========
Unevaluated Properties (excluded from
amortization) -
Beginning of period balance $ 44,434 $ 42,679 $ 35,339
Additions 4,381 4,890 11,156
Capitalized interest 4,548 3,497 4,440
General and administrative costs 5,036 3,623 4,515
Transfers to evaluated (10,746) (10,255) (12,771)
--------- --------- ---------
End of period balance $ 47,653 $ 44,434 $ 42,679
========= ========= =========
Accumulated depreciation, depletion
and amortization
Beginning of period balance $ 361,758 $ 345,353 $ 282,891
Provision charged to expense 16,831 16,405 18,962
Impairment of oil and gas properties -- -- 43,500
--------- --------- ---------
End of period balance $ 378,589 $ 361,758 $ 345,353
========= ========= =========
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 $12.3 million incurred in 2000, $7.5 million incurred
in 1999 and $27.9 million incurred in 1998 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 majority of these costs will be
evaluated over the next five-year period.
Depletion per unit-of-production (thousand cubic feet of gas equivalent)
amounted to $1.10, $.99 and $1.19 for the years ended December 31, 2000, 1999,
and 1998, respectively.
IMPAIRMENT OF OIL AND GAS PROPERTIES-1998
Under full-cost accounting rules, the capitalized costs of proved oil and gas
properties are subject to a "ceiling test", which limits such costs to the
estimated present value net of related tax effects, discounted at a 10 percent
interest rate, of future net cash flows from proved reserves, based on current
economic and operating conditions (PV10). If capitalized costs exceed this
limit, the excess is charged to expense. During the fourth quarter of 1998, the
Company recorded a noncash impairment provision related to oil and gas
45
properties in the amount of $43.5 million ($28.7 million after-tax) primarily
due to the significant decline in oil and gas prices at December 31, 1998.
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,
2000 and 1999, the Trusts' assets (all cash and investments) totaled $6,227,000
and $5,690,000 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, 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.
46
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:
- - 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 $500,000, $466,000, and $468,000 in the
years 2000, 1999 and 1998, respectively.
- - 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.
- - 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.
- - 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. 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 $800,973 were recognized
in income in 2000 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 Compensation", the Company's net income and
earnings per common share would have been reduced to the following pro forma
amounts:
47
2000 1999 1998
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income (loss) available for
common shares: As Reported $ 10,144 $ 130 $ (33,533)
Pro Forma 8,418 (1,212) (34,421)
Basic earnings (loss) per share: As Reported .82 .01 (4.17)
Pro Forma .68 (.14) (4.28)
Diluted earnings (loss) per share: As Reported .80 .01 (4.17)
Pro Forma .66 (.14) (4.28)
A summary of the status of the Company's two stock option plans at December 31,
2000, 1999 and 1998 and changes during the years then ended is presented in the
table and narrative below:
2000 1999 1998
---------------------------- --------------------------- --------------------------
WTD AVG WTD AVG WTD AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
------------ ------------ ------------ ------------ ------------ ------------
Outstanding, beginning of year 1,536,500 $ 10.60 1,266,000 $ 11.00 1,041,000 $ 11.19
Granted (at market) 135,000 14.73 270,500 9.27 225,000 10.08
Granted (below market) 653,000 10.50 -- -- -- --
Exercised (20,333) 9.00 -- -- -- --
Forfeited -- -- -- -- -- --
Expired -- -- -- -- -- --
------------ ------------ ------------ ------------ ------------ ------------
Outstanding, end of year 2,304,167 $ 10.83 1,536,500 $ 10.60 1,266,000 $ 11.00
============ ============ ============ ============ ============ ============
Exercisable, end of year 1,647,657 $ 10.71 1,247,600 $ 10.47 802,250 $ 10.90
============ ============ ============ ============ ============ ============
Weighted average fair value of
options granted (at market) $ 7.68 $ 4.94 $ 4.31
============ ============ ============
Weighted average fair value of
options granted (below market) $ 7.90 N/A N/A
============
At December 31, 2000, 2,129,167 of the 2,304,167 options outstanding have
exercise prices between $9 and $13.50 with a weighted average exercise price of
$10.51 and a weighted average remaining contractual life of 6.85 years. Of these
options, 1,546,357 are exercisable at a weighted average exercise price of
$10.46. 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 8.98 years. Of these options, 101,300 are
exercisable at a weighted average exercise price of $14.46.
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 2000, 1999 and 1998.
The Company awarded 225,000 performance shares under the 1996 Plan to the
Company's Executive officers on August 23, 1996. All of the performance shares
granted were scheduled to vest in whole on January 1, 2001. The unearned portion
was being amortized as compensation expense on a straight-line basis over the
vesting period. An additional 25,000 shares were issued under the 1994 Plan in
1997 and 165,500 shares were issued to certain key employees other than the
Company's Executive officers in 1998.
48
Approximately $4,963,000 in 1998 and $714,000 in 1997 of compensation cost were
charged to expense related to the restricted shares granted. In December 1998,
the Company approved the accelerated vesting of all performance shares. As a
result, an additional charge of $3,469,000 which represents the future
unamortized expense related to unvested shares at the date the acceleration of
vesting occurred, was expensed in 1998.
In addition, the Company recorded a provision of approximately $2.3 million for
retirement benefits approved by the compensation committee of the Board of
Directors in December of 1998.
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.
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")
49
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. 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, 2000, 1999 and 1998
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.
The 2000 estimates have been adjusted (per SEC guidelines) to exclude (i)
volumes (approximately 3.5 billion cubic feet of natural gas) and (ii) future
revenues of approximately $31.8 million associated with the volumetric
production payment described in Note 4. The adjustments resulted in a reduction
of approximately $29.5 million in standardized measure of discounted net cash
flows, before tax, associated with this volumetric production payment.
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 present values 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.
50
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,
--------------------------------------------
2000 1999 1998
---------- ---------- ----------
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period 23,834 6,898 3,402
Revisions to previous estimates 85 (686) (99)
Purchase of reserves in place -- 2,629 162
Sales of reserves in place -- -- (1,531)
Extensions and discoveries 9,695 15,323 5,274
Production (232) (330) (310)
---------- ---------- ----------
End of period 33,382 23,834 6,898
========== ========== ==========
Natural Gas (MMcf):
Beginning of period 110,621 88,030 88,738
Revisions to previous estimates (4,817) (11,492) (8,631)
Purchase of reserves in place 347 4,733 4,414
Sales of reserves in place -- -- (684)
Extensions and discoveries 35,387 42,662 18,229
Production (11,616) (13,312) (14,036)
---------- ---------- ----------
End of period 129,922 110,621 88,030
========== ========== ==========
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period 1,376 1,774 2,976
========== ========== ==========
End of period 2,192 1,376 1,774
========== ========== ==========
Natural Gas (MMcf):
Beginning of period 76,295 76,895 88,010
========== ========== ==========
End of period 63,982 76,295 76,895
========== ========== ==========
51
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 ($9.14 for natural gas and $26.71 for oil for the 2000 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,
-----------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
Future cash inflows $ 2,080,680 $ 847,930 $ 256,325
Future costs -
Production (284,667) (207,615) (67,192)
Development and net abandonment (217,507) (123,749) (36,581)
----------- ----------- -----------
Future net inflows before income taxes 1,578,506 516,567 152,552
Future income taxes (472,637) (109,238) --
----------- ----------- -----------
Future net cash flows 1,105,869 407,329 152,552
10% discount factor (434,672) (151,007) (52,801)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows $ 671,197 $ 256,322 $ 99,751
=========== =========== ===========
CHANGES IN STANDARDIZED MEASURE
YEARS ENDED DECEMBER 31,
--------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Standardized measure - beginning of period $ 256,322 $ 99,751 $ 128,079
Sales and transfers, net of production costs (42,132) (27,076) (27,807)
Net change in sales and transfer prices,
Net of production costs 361,179 57,246 (33,029)
Exchange and sale of in place reserves -- -- (4,445)
Purchases, extensions, discoveries, and improved
recovery, net of future production and
development costs 276,770 181,185 24,294
Revisions of quantity estimates (12,399) (22,438) (9,409)
Accretion of discount 28,581 9,975 13,645
Net change in income taxes (209,090) (29,492) 7,926
Changes in production rates, timing and other 11,966 (12,829) 497
------------ ------------ ------------
Standardized measure - end of period $ 671,197 $ 256,322 $ 99,751
============ ============ ============
52
13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
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
1999
- ----
Total revenues $ 8,374 $ 9,031 $ 10,584 $ 11,004
Total costs and expenses 7,659 8,690 8,986 9,678
Income tax expense 243 116 543 451
Net income 472 225 1,055 875
Net income (loss) per share-basic (0.04) (0.04) 0.06 0.03
Net income (loss) per share-diluted (0.04) (0.04) 0.06 0.03
53
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 4, 2001 which will
be filed with the Securities and Exchange Commission and is incorporated herein
by reference.
54
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 32
through 53.
Report of Independent Public Accountants
Consolidated Balance Sheets as of the Years Ended December 31, 2000 and
1999
Consolidated Statements of Operations for the Three Years in the Period
Ended December 31, 2000
Consolidated Statements of Stockholders' Equity for the Three Years in the
Period Ended December 31, 2000
Consolidated Statements of Cash Flows for the Three Years in the Period
Ended December 31, 2000
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)
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)
55
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 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 25, 1999, Reg. No. 333-80579)
4.7 Rights Agreement between Callon Petroleum Company and American
Stock Transfer & Trust Company, Rights Agent, dated March 30,
2000 (incorporated by reference from Exhibit 4 of the
Company's 8-K filed April 6, 2000)
4.8 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)
4.9 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)
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.
56
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 September 30, 2000 Form 10-Q filed November
13, 2000)
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
57
24. Power of attorney*
99. Additional Exhibits*
- ----------
*Inapplicable to this filing.
(b) Reports on Form 8-K.
The Company filed a Report on Form 8-K on October 27, 2000 under "Item 5 -
Other Events" filing certain exhibits in connection with the offer and
sale of the Company's 11% Senior Subordinated Notes due 2005.
The Company filed a Report on Form 8-K on December 4, 2000 under "Item 5 -
Other Events" which contained the news release regarding the completion of
the redemption of its 10% Senior Subordinated Notes due 2001.
58
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 30, 2001 /s/ Fred L. Callon
---------------- -------------------------------------------------------
Fred L. Callon (principal executive officer, director)
Date: March 30, 2001 /s/ John S. Weatherly
---------------- -------------------------------------------------------
John S. Weatherly (principal financial officer)
Date: March 30, 2001 /s/ James O. Bassi
---------------- -------------------------------------------------------
James O. Bassi (principal accounting officer)
Date: March 30, 2001 /s/ John S. Callon
---------------- -------------------------------------------------------
John S. Callon (director)
Date: March 30, 2001 /s/ Dennis W. Christian
---------------- -------------------------------------------------------
Dennis W. Christian (director)
Date: March 30, 2001 /s/ B. F. Weatherly
---------------- -------------------------------------------------------
B. F. Weatherly (director)
Date: March 30, 2001 /s/ John C. Wallace
---------------- -------------------------------------------------------
John C. Wallace (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 30, 2001 By: /s/ John S. Weatherly
---------------- -------------------------------------------------------
John S. Weatherly, Senior Vice President and
Chief Financial Officer
59
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------
(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)
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 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 25, 1999, Reg. No. 333-80579)
4.7 Rights Agreement between Callon Petroleum Company and American
Stock Transfer & Trust Company, Rights Agent, dated March 30,
2000 (incorporated by reference from Exhibit 4 of the
Company's 8-K filed April 6, 2000)
4.8 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)
4.9 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)
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.
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 September 30, 2000 Form 10-Q filed November
13, 2000)
11. Statement re computation of per sharing 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*
- ----------
*Inapplicable to this filing.
Exhibit 10.2
COUNTERPART TO REGISTRATION RIGHTS AGREEMENT
BY AND BETWEEN CALLON PETROLEUM COMPANY
(FORMERLY CALLON PETROLEUM HOLDING COMPANY)
AND NOCO ENTERPRISES, L.P.
DATED SEPTEMBER 16, 1994
WHEREAS, the parties have caused this Counterpart to be executed and
delivered by their respective duly authorized officers for purposes of Section
7.3 of the above-mentioned Registration Rights Agreement and for purposes of
confirming that the 1,839,836 shares of the common stock of Callon Petroleum
Company to be acquired jointly by Ganger Rolf ASA and Bonheur ASA directly from
Fred. Olsen Energy ASA are "Registrable Securities" as defined in the
Registration Rights Agreement; and
WHEREAS, Ganger Rolf ASA and Bonheur ASA agree to be bound by the terms
of the Registration Rights Agreement;
IN WITNESS WHEREOF, this Counterpart is effective as of the 28th day of
August, 2000.
CALLON PETROLEUM COMPANY
By: /s/ Robert A. Mayfield
Name: Robert A. Mayfield
Title: Corporate Secretary
GANGER ROLF ASA
By: /s/ F. Haavardsson /s/ J. C. Wallace
Name: F. Haavardsson J. C. Wallace
Title: Director Director
BONHEUR ASA
By: /s/ F. Haavardsson /s/ J. C. Wallace
Name: F. Haavardsson J. C. Wallace
Title: Director Director
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference of our report dated February 22, 2001,
included in this Form 10-K, into Callon Petroleum Company's previously
filed Registration Statements on Forms S-8 (File Nos. 33-90410,
333-29537, 333-29529 and 333-47784).
Arthur Andersen LLP
March 29, 2001
New Orleans, Louisiana
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