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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, 2003
COMMISSION FILE NUMBER 001-14039
CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)
DELAWARE 64-0844345
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
200 NORTH CANAL STREET
NATCHEZ, MISSISSIPPI 39120 (601) 442-1601
(Address of Principal Executive (Registrant's telephone number
Offices)(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
- ----------------------------------------- ------------------------------------
Convertible Exchangeable Preferred Stock, New York Stock Exchange
Series A, Par Value $.01 Per Share
Common Stock, Par Value $.01 Per Share New York Stock Exchange
Preferred Stock Purchase Rights New York Stock Exchange
11% Senior Subordinated Notes due 2005 New York Stock Exchange
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|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes |X| No.| |.
The aggregate market value of the voting and non-voting common equity held by
nonaffiliates of the registrant was approximately $78.8 million as of June 30,
2003 (based on the last reported sale price of such stock on the New York Stock
Exchange on such date of $7.12).
As of March 4, 2004, there were 13,976,411 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, 2003) relating to the Annual Meeting of Stockholders to be held on May 6,
2004, which is incorporated into Part III of this Form 10-K.
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PART I.
ITEM 1 AND 2. BUSINESS AND PROPERTIES
OVERVIEW
Callon Petroleum Company has been engaged in the exploration, development,
acquisition and production of oil and gas properties since 1950. Our properties
are geographically concentrated primarily offshore in the Gulf of Mexico and
onshore in Louisiana and Alabama. We were incorporated under the laws of the
state of Delaware in 1994 and succeeded to the business of a publicly traded
limited partnership, a joint venture with a consortium of European institutional
investors and an independent energy company owned by members of current
management. As used herein, the "Company," "Callon," "we," "us," and "our" refer
to Callon Petroleum Company and its predecessors and subsidiaries unless the
context requires otherwise.
In 1989, we began increasing our reserves through the acquisition of producing
properties that were geologically complex, had (or were analogous to fields
with) an established production history from stacked pay zones and were
candidates for exploitation. We focused on reducing operating costs and
implementing production enhancements through the application of technologically
advanced production and recompletion techniques.
Over the past eight years, we have also placed emphasis on the acquisition of
acreage with exploration and development drilling opportunities in the Gulf of
Mexico shelf and deepwater areas. At December 31, 2003 we owned working
interests in a total of 73 blocks/leases covering 157,000 net acres. We joined
with other industry partners, primarily Murphy Exploration and Production, Inc.,
to explore federal offshore blocks acquired in the Gulf of Mexico. We perform
extensive geological and geophysical studies using computer-aided exploration
techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic
or high-resolution 2-D data to facilitate these efforts. We continue to develop
prospects on the shelf through our 3-D seismic partnership using AVO technology.
In 1998, we began exploration in the Gulf of Mexico deepwater area (generally
900 to 5,500 feet of water). In the fourth quarter of 2003, our first two
deepwater projects, the Medusa and Habanero fields, began production. Please see
"Significant Properties" for a more detailed discussion.
We ended the year 2003 with estimated net proved reserves of 217 billion cubic
feet of natural gas equivalent ("Bcfe"). This represents a decrease of 8% from
2002 year-end estimated net proved reserves of 236 Bcfe.
The major focus of our future operations is expected to continue to be the
exploration for and development of oil and gas properties, primarily in the Gulf
of Mexico.
AVAILABILITY OF REPORTS
All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and amendments to such reports as well as other filings we
make pursuant to Section 13(a) and 15(d) of the Securities Exchange Act of 1934
are available free of charge on our Internet website. The address of our
Internet website is www.callon.com. Our SEC filings are available on our website
as soon as they are posted to the EDGAR database on the SEC's website.
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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:
- focus on Gulf of Mexico exploration with a balance between shelf and
deepwater areas using the latest available technology;
- aggressively explore our existing prospect inventory;
- replenish our prospect inventory with increasing emphasis on
prospect generation using AVO technology;
- achieve moderate increases in current production levels through
continued shelf exploration; and
- 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 $50 million in 2003. We incurred
approximately $32 million in the Gulf of Mexico deepwater area primarily for
development costs at our Habanero and Medusa discoveries. Interest of
approximately $5 million and general and administrative costs allocable directly
to exploration and development projects of $8 million were capitalized in 2003.
Our Gulf of Mexico shelf area expenditures account for the remainder of the
total capital expended.
SEC INQUIRIES REGARDING RESERVE INFORMATION
Beginning in October 2002, we received a series of inquiries from the SEC
regarding our Annual Report on Form 10-K for the year ended December 31, 2001
requesting supplemental information concerning operations in the Gulf of Mexico.
The comment letters requested information about the procedures used to classify
the deepwater reserves as proved and requested that our financial statements be
restated to reflect the removal of the reserves attributable to the Boomslang
discovery as proved for all prior periods during which such reserves were
reported as proved. We have reviewed the SEC comments with our independent
petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Both
Huddleston & Co. and we believe that such deepwater reserves are properly
classified as proved. We have responded to all the inquiries from the SEC.
Based on our discussions with others in the oil and gas business, we believe
that the SEC is reviewing generally the procedures used by reserve engineers to
classify oil and gas reserves as proved in the deepwater areas of the Gulf of
Mexico. In particular, the SEC appears to indicate that it is not appropriate to
classify reserves as proved without conducting a "flow test." It has not been
our practice to conduct a flow test on our deepwater properties prior to
classifying the reserves as proved. We believe, and have been advised by
Huddleston & Co., that our procedures for classifying our deepwater reserves as
proved are in accordance with SEC rules and industry practices.
RISK FACTORS
A 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
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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, and 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:
- our revenues, cash flows and earnings;
- the amount of oil and gas that we are economically able to produce;
- our ability to attract capital to finance our operations and the
cost of the capital;
- the amount we are allowed to borrow under our senior secured credit
facility;
- the value of our oil and gas properties; and
- the profit or loss we incur in exploring for and developing our
reserves.
WE MAY BE REQUIRED TO RETROACTIVELY PAY ROYALTIES TO THE MINERALS MANAGEMENT
SERVICE ON ONE OF OUR PROPERTIES WHICH COULD REDUCE REVENUES AND RESERVES. Our
Medusa deepwater property is eligible for royalty suspensions pursuant to the
Deep Water Royalty Relief Act. However, the federal offshore leases covering the
property contain "price threshold" provisions for oil and gas prices. Under this
"price threshold" provision, if the average monthly New York Mercantile Exchange
(NYMEX) sales price for oil or gas during a fiscal year exceeds the price
threshold for oil or gas, respectively, then royalties on the associated
production must be paid to the Minerals Management Service (MMS) at the rate
stipulated in the lease. The price thresholds are adjusted annually by the
implicit price deflator for the GDP. The determination of whether or not
royalties are due as a result of the average NYMEX price exceeding the price
threshold is made during the first quarter of the succeeding year. Any royalty
payments due must be made shortly after this determination is made. If a royalty
payment is due for all production during a year as a result of exceeding the
price threshold, the lessee is required to make monthly royalty payments during
the succeeding fiscal year for the succeeding year's production. If at the end
of any year the average NYMEX price is below the price threshold, the lessee can
apply for a refund for any associated royalties paid during that year and the
lessee will not be required to pay royalties monthly during the succeeding year
for the succeeding year's production.
The thresholds and the average NYMEX prices are calculated by the MMS. The
average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of
natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per
barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the
adjustment for the 2003 GDP implicit price deflator. As a result we will pay
royalties related to 2003 gas production for Medusa, which commenced production
in late November 2003 and will make monthly royalty payments for 2004 gas
production during 2004. Our actual liability for 2004 oil royalties, if any,
cannot be determined until after the end of 2004.
In the year succeeding the year in which any of our properties became subject to
royalties as result of the average NYMEX price exceeding the price threshold,
the portion of reserves attributable to potential future royalties would not be
included in a year-end reserve report. However, if the average NYMEX prices were
below the price thresholds in subsequent years, our reserves would be increased
to reflect reserves previously attributed to future royalties. As a result,
reported oil and gas reserves could materially increase or decrease, depending
on the relation of price thresholds versus the average NYMEX prices. The
reduction in our revenues resulting from an obligation to pay these royalties
and subsequent reduction of our proved reserves could have a material adverse
effect on our results of operations and financial condition. Our reserve report,
as of December 31, 2003, excluded gas reserves for Medusa that are subject to
MMS royalties as a result of the average 2003 NYMEX price for gas exceeding the
price threshold. Oil reserves in this reserve report were not impacted since the
2003 average NYMEX price was below the threshold.
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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. ANY
MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS WILL
MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES. The process
of estimating oil and gas reserves is complex. It requires interpretations of
available technical data and various assumptions, including assumptions relating
to economic factors. Any significant inaccuracies in these interpretations or
assumptions could materially affect the estimated quantities and present value
of reserves shown in this annual report.
In order to prepare these estimates, we must project production rates and the
timing of development expenditures. The assumptions regarding the timing and
costs to commence production from our deepwater wells used in preparing our
reserves are often subject to revisions over time as described under "our
deepwater operations have special operational risks that may negatively affect
the value of those assets." We must also analyze available geological,
geophysical, production and engineering data, the extent, quality and
reliability of which can vary. The process also requires us to make economic
assumptions, such as oil and gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. Therefore, estimates of
oil and gas reserves are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from our estimates. Any significant variance
could materially affect the estimated quantities and present value of reserves
shown in this report. In addition, we may adjust estimates of proved reserves to
reflect production history, results of exploration and development, prevailing
oil and gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net cash flows from our
proved reserves referred to in this report is the current market value of our
estimated oil and gas reserves. In accordance with SEC requirements, we
generally base the estimated discounted future net cash flows from our proved
reserves on prices and costs on the date of the estimate. Actual future prices
and costs may differ materially from those used in the present value estimate.
Information about reserves constitutes forward-looking information. See
"Forward-Looking Statements" for information regarding forward-looking
information. The discounted present value of our oil and gas reserves is
prepared in accordance with guidelines established by the SEC. A purchaser of
reserves would use numerous other factors to value our reserves. The discounted
present value of reserves, therefore, does not represent the fair market value
of those reserves.
On December 31, 2003, approximately 53% of the discounted present value of our
estimated net proved reserves were proved undeveloped. Proved undeveloped oil
volumes represented 58% of total proved oil reserves. Substantially all of these
proved undeveloped reserves were attributable to our deepwater properties.
Development of these properties is subject to additional risks as described
above.
THE SEC MAY REQUIRE US TO BOOK RESERVES AS PROVED IN A MANNER THAT DIFFERS FROM
OUR HISTORICAL PRACTICES AND CURRENT INDUSTRY STANDARDS, AND WHICH MAY RESULT IN
A SIGNIFICANT DOWNWARD REVISION OF OUR PROVED RESERVES. As discussed above,
beginning in October 2002 we received a series of inquiries from the SEC
regarding our Annual Report on Form 10-K for the year ended December 31, 2001
requesting supplemental information concerning our operations in the Gulf of
Mexico. The comment
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letters requested information about the procedures we used to classify our
deepwater reserves as proved and requested that our financials be restated to
reflect the removal of the Boomslang reserves as proved for all prior periods
during which such reserves were reported as proved. We have reviewed the SEC
comments with our independent petroleum reserve engineers, Huddleston & Co.,
Inc. of Houston, Texas. Both Huddleston & Co. and we believe that such reserves
were properly classified as proved. However, if the SEC decides to question our
other deepwater properties and these reserves are ultimately required to be
reclassified as not proved, our proved reserves will be materially reduced. If
the SEC requires us to retroactively classify Boomslang as an unproved property
through December 2002, we would be required to restate our financial position,
results of operations, and supplemental oil and gas reserve data from 1998
through 2002. A material reduction in our proved reserves could have a material
adverse effect on our financial condition and results of operations. We have
responded to all the inquiries from the SEC.
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 properties, our producing
properties usually have high initial production rates, followed by a steep
decline in production. As a result, we must continually locate and develop or
acquire new oil and gas reserves to replace those being depleted by production.
We must do this even during periods of low oil and gas prices when it is
difficult to raise the capital necessary to finance these activities and during
periods of high operating costs when it is expensive to contract for drilling
rigs and other equipment and personnel necessary to explore for oil and gas.
Without successful exploration or acquisition activities, our reserves,
production and revenues will decline rapidly. We cannot assure you that we will
be able to find and develop or acquire additional reserves at an acceptable
cost.
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 2003, 64% of our daily production came from two of
our properties in the Gulf of Mexico. Moreover, one property accounted for 51%
of our production during this period. In addition, at December 31, 2003, most of
our proved reserves were located in four fields in the Gulf of Mexico, with
approximately 94% of our total net proved reserves attributable to these
properties. If mechanical problems, storms or other events curtailed a
substantial portion of this production or if the actual reserves associated with
any one of these producing properties 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:
- unexpected drilling conditions;
- pressure or inequalities in formations;
- equipment failures or accidents;
- adverse weather conditions;
- compliance with governmental requirements; and
- shortages or delays in the availability of drilling rigs and the
delivery of equipment.
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WE DO NOT OPERATE ALL OF OUR PROPERTIES AND HAVE LIMITED INFLUENCE OVER THE
OPERATIONS OF SOME OF THESE PROPERTIES, PARTICULARLY OUR DEEPWATER PROPERTIES.
Our lack of control could result in the following:
- the operator may initiate exploration or development on a faster or
slower pace than we prefer;
- 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
- if an operator refuses to initiate a project, we may be unable to
pursue the project.
Any of these events could materially reduce the value of our properties.
OUR DEEPWATER OPERATIONS HAVE SPECIAL OPERATIONAL RISKS THAT MAY NEGATIVELY
AFFECT THE VALUE OF THOSE ASSETS. Drilling operations in the deepwater area are
by their nature more difficult and costly than drilling operations in shallow
water. Deepwater drilling operations require the application of more advanced
drilling technologies involving a higher risk of technological failure and
usually have significantly higher drilling costs than shallow water drilling
operations. Deepwater wells are completed using sub-sea 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 deepwater, the time required to commence production following a discovery is
much longer than in shallow water and on-shore. Our deepwater discoveries and
prospects will require the construction of expensive production facilities and
pipelines prior to the beginning of production. We cannot estimate the costs and
timing of the construction of these facilities with certainty, and the accuracy
of our estimates will be affected by a number of factors beyond our control,
including the following:
- decisions made by the operators of our deepwater wells;
- the availability of materials necessary to construct the facilities;
- the proximity of our discoveries to pipelines; and
- the price of oil and natural gas.
Delays and cost overruns in the commencement of production will affect the value
of our deepwater prospects and the discounted present value of reserves
attributable to those prospects.
COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT
OPERATIONS. We operate in the highly competitive areas of oil and gas
exploration, development and production. We compete for the purchase of leases
in the Gulf of Mexico from the U. S. government and from other oil and gas
companies. These leases include exploration prospects as well as properties with
proved reserves. Factors that affect our ability to compete in the marketplace
include:
- our access to the capital necessary to drill wells and acquire
properties;
- our ability to acquire and analyze seismic, geological and other
information relating to a property;
- our ability to retain the personnel necessary to properly evaluate
seismic and other information relating to a property;
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- the location of, and our ability to access, platforms, pipelines and
other facilities used to produce and transport oil and gas
production;
- the standards we establish for the minimum projected return on an
investment of our capital; and
- the availability of alternate fuel sources.
Our competitors include major integrated oil companies, substantial independent
energy companies, and affiliates of major interstate and intrastate pipelines
and national and local gas gatherers, many of which possess greater financial,
technological and other resources than we do.
OUR COMPETITORS MAY USE SUPERIOR TECHNOLOGY, WHICH WE MAY BE UNABLE TO AFFORD OR
WHICH WOULD REQUIRE COSTLY INVESTMENT BY US IN ORDER TO COMPETE. Our industry is
subject to rapid and significant advancements in technology, including the
introduction of new products and services using new technologies. As our
competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new
technologies at a substantial cost. In addition, our competitors may have
greater financial, technical and personnel resources that allow them to enjoy
technological advantages and may in the future allow them to implement new
technologies before we can. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to us.
One or more of the technologies that we currently use or that we may implement
in the future may become obsolete, and we may be adversely affected. For
example, marine seismic acquisition technology has been characterized by rapid
technological advancements in recent years, and further significant
technological developments could substantially impair our 3-D seismic data's
value.
WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE
UNABLE TO RAISE CAPITAL. WE WILL BE REQUIRED TO MAKE SUBSTANTIAL CAPITAL
EXPENDITURES TO DEVELOP OUR EXISTING RESERVES, AND TO DISCOVER NEW OIL AND GAS
RESERVES. 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 secured credit facility to borrow funds
to supplement our available cash. The amount we may borrow under our senior
secured credit facility may not exceed a borrowing base determined by the
lenders under such facility 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 secured credit
facility exceed the borrowing base, the lenders may require that we repay the
excess. If this were to occur, we might have to sell assets or seek financing
from other sources. Sales of assets could further reduce the amount of our
borrowing base. We cannot assure you that we would be successful in selling
assets or arranging substitute financing. If we were not able to repay
borrowings under our senior secured credit facility to reduce the outstanding
amount to less than the borrowing base, we would be in default under our senior
secured credit facility. For a description of our senior secured credit facility
and its principal terms and conditions, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations --Liquidity and
Capital Resources."
OUR DECISION TO DRILL A PROSPECT IS SUBJECT TO A NUMBER OF FACTORS AND WE MAY
DECIDE TO ALTER OUR DRILLING SCHEDULE OR NOT DRILL AT ALL. We describe our
current prospects and our plans to explore these
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prospects in this annual report. A prospect is a property on which we have
identified what our geoscientists believe, based on available seismic and
geological information, to be indications of hydrocarbons. Our prospects are in
various stages of evaluation, ranging from a prospect which is ready to drill to
a prospect which will require substantial additional seismic data processing and
interpretation. Whether we ultimately drill a prospect may depend on the
following factors:
- receipt of additional seismic data or the reprocessing of existing
data;
- material changes in oil or gas prices;
- the costs and availability of drilling rigs;
- the success or failure of wells drilled in similar formations or
which would use the same production facilities;
- availability and cost of capital;
- changes in the estimates of the costs to drill or complete wells;
- our ability to attract other industry partners to acquire a portion
of the working interest to reduce exposure to costs and drilling
risks; and
- decisions of our joint working interest owners.
We will continue to gather data about our prospects and it is possible that
additional information may cause us to alter our drilling schedule or determine
that a prospect should not be pursued at all. You should understand that our
plans regarding our prospects are subject to change.
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:
- our drilling operations may encounter unexpected formations or
pressures, which could cause damage to equipment or personal injury;
- we may experience equipment failures which curtail or stop
production; and
- 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 capsizing, collisions, hurricanes and other adverse weather
conditions. These conditions can cause substantial damage to facilities and
interrupt production. Offshore operations are also subject to more extensive
governmental regulation.
We cannot assure you that we will be able to maintain adequate insurance at
rates we consider reasonable to cover our possible losses from operating
hazards. The occurrence of a significant event not fully insured or indemnified
against could materially and adversely affect our financial condition and
results of operations.
WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT FROM
PRICE INCREASES. Part of our business strategy is to reduce our exposure to the
volatility of oil and gas prices by hedging a portion of our production. In a
typical hedge transaction, we will have the right to receive from the other
parties to the hedge the excess of the fixed price specified in the hedge over a
floating price based on a market index, multiplied by the quantity hedged. If
the floating price exceeds the fixed price, we are required to pay the other
parties this difference multiplied by the quantity hedged. We are required to
pay the difference between the floating price and the fixed price when the
floating price exceeds the fixed
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price regardless of whether we have sufficient production to cover the
quantities specified in the hedge. Significant reductions in production at times
when the floating price exceeds the fixed price could require us to make
payments under the hedge agreements even though such payments are not offset by
sales of production. Hedging will also prevent us from receiving the full
advantage of increases in oil or gas prices above the fixed amount specified in
the hedge. We also enter into price "collars" to reduce the risk of changes in
oil and gas prices. Under a collar, no payments are due by either party so long
as the market price is above a floor set in the collar and below a ceiling. If
the price falls below the floor, the counter-party to the collar pays the
difference to us and if the price is above the ceiling, we pay the counter-party
the difference. 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 operation and maintenance of our facilities
and the discharge of materials into the environment or otherwise relating to
environmental protection. For a discussion of the material regulations
applicable to us, see "Federal Regulations," "State Regulations," and
"Environmental Regulations." These laws and regulations may:
- require that we acquire permits before commencing drilling;
- restrict the substances that can be released into the environment in
connection with drilling and production activities;
- limit or prohibit drilling activities on protected areas such as
wetlands or wilderness areas; and
- 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:
- the extent of domestic production and imports of oil and gas;
- the proximity of the gas production to gas pipelines;
- the availability of pipeline capacity;
- the demand for oil and gas by utilities and other end users;
- the availability of alternative fuel sources;
- the effects of inclement weather;
- state and federal regulation of oil and gas marketing; and
- federal regulation of gas sold or transported in interstate
commerce.
10
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 OF THE
CARRYING VALUE OF OUR OIL AND GAS PROPERTIES. 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 which we use to account for
our oil and gas properties, the net capitalized costs of our oil and gas
properties may not exceed the present value, discounted at 10%, of future net
cash flows from estimated net proved reserves, using period end oil and gas
prices or prices as of the date of our auditor's report, plus the lower of cost
or fair market value of our unproved properties. If net capitalized costs of our
oil and gas properties exceed this limit, we must charge the amount of the
excess to earnings. This type of charge will not affect our cash flows, but will
reduce the book value of our stockholders' equity. We review the carrying value
of our properties 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:
- our oil and gas reserve quantities, and the discounted present value
of these reserves;
- the amount and nature of our capital expenditures;
- drilling of wells;
- the timing and amount of future production and operating costs;
- business strategies and plans of management; and
- 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:
- general economic conditions;
- the volatility of oil and natural gas prices;
- the uncertainty of estimates of oil and natural gas reserves;
- the impact of competition;
- the availability and cost of seismic, drilling and other equipment;
- operating hazards inherent in the exploration for and production of
oil and natural gas;
- difficulties encountered during the exploration for and production
of oil and natural gas;
- difficulties encountered in delivering oil and natural gas to
commercial markets;
- changes in customer demand and producers' supply;
- the uncertainty of our ability to attract capital;
- compliance with, or the effect of changes in, the extensive
governmental regulations regarding the oil and natural gas business;
- actions of operators of our oil and gas properties; and
- weather conditions.
11
The information contained in this report, including the information set forth
under the heading "Risk Factors," identifies additional factors that could
affect our operating results and performance. We urge you to carefully consider
these factors and the other cautionary statements in this report. Our
forward-looking statements speak only as of the date made, and we have no
obligation to update these forward-looking statements.
CORPORATE OFFICES
Our headquarters are located in Natchez, Mississippi, in approximately 51,500
square feet of owned space, with a field office in Houston, Texas. We also
maintain owned or leased field offices in the area of the major fields in which
we operate properties or have a significant interest. Replacement of any of our
leased offices would not result in material expenditures by us as alternative
locations to our leased space are anticipated to be readily available.
EMPLOYEES
We had 94 employees as of December 31, 2003, none of whom are currently
represented by a union. We believe that we have good relations with our
employees. We employ 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 us 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.
In February, 2000, the FERC issued Order No. 637, a final rule designed to
continue the restructuring of the gas industry initiated by an earlier final
rule, Order No. 636, that instituted "open access" transportation. Order No. 637
further revised the FERC's policies governing interstate pipeline transportation
rates and penalties and further refined the regulatory framework governing
transportation terms and conditions to improve open access transportation. The
rule has been implemented on a pipeline-by-pipeline basis in individual
compliance proceedings, many of which have been settled or have otherwise been
terminated. A few proceedings, however, are still pending final resolution.
In Order No. 644 issued November 13, 2003, the FERC imposed new standards of
conduct, inter alia, for "all sellers for resale" marketing gas under blanket
market certificates. The standards include a requirement of accurate reporting,
if any, of the price of arm's-length deals to price index publishers and a
requirement to notify the FERC as to whether the marketer reports transactions
to price index publishers. In Order No. 2004, issued on November 25, 2003, the
FERC issued standards of conduct covering regulated interstate pipelines and
public utilities ("Transmission Providers") to govern the relationships between
regulated Transmission Providers and all of their energy affiliates. Among other
things, these measures are intended to
12
increase confidence and transparency in the gas market in the wake of recent
events involving anticompetitive behavior and market abuse.
On February 12, 2004, the FERC issued a notice of proposed rulemaking in Docket
No. RM04-4 designed to standardize the procedures for determining the
creditworthiness of shippers on interstate pipelines and to adopt certain
standards published by the North American Energy Standards Board with respect to
shipper creditworthiness. The standards are intended to facilitate and increase
transparency in the creditworthiness evaluation process.
The FERC is presently reviewing in Docket No. PL04-3 whether it should adopt
standards for "interchangeability" of natural gas, that is, whether it should
standardize the composition and quality of natural gas transported through the
delivery system, including interstate pipelines. Although the standards, if any,
are likely to be voluntary, at the present time the approach that the FERC will
take and the potential impact on gas supply are not clear.
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 ("OCSLA"), 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 OCSLA over gathering facilities, if necessary, to permit
non-discriminatory access to service. In an effort to heighten its oversight of
the OCS, the FERC recently attempted to promulgate reporting requirements for
all OCS "service providers," including gatherers, but the regulations were
struck down as ultra vires by a federal district court in October, 2003. In
addition, the FERC recently reasserted NGA jurisdiction over certain offshore
gathering facilities over which it had previously disclaimed jurisdiction where
it determined that the FERC's open access regulatory regime was being frustrated
by an interstate pipeline in concert with an affiliated gathering company. 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 the 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 us at market prices not subject at this time to price controls. The
price that we receive 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. Pursuant
to the Energy Policy Act of 1992, which "grandfathered" certain existing rates,
the FERC presently regulates oil pipeline rates under a light-handed,
streamlined regulatory regime where rates are adjusted annually using an index
ceiling based upon the producer price index. The FERC recently modified the
formula for calculating the index such that the index ceilings are now set
slightly higher than in their original iteration. As an exception to indexing,
the FERC will also, under defined circumstances, permit alternative ratemaking
methodologies for interstate oil pipelines such as the use of cost of service
rates, settlement rates, and market-based rates. Market-based rates will be
permitted to the extent the pipeline can demonstrate that it lacks significant
market power in the market in which it proposes to charge market-based rates.
The cumulative effect that these rules have had on moving our production to
market have not been material.
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.
13
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 difficult 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 our
operations.
FEDERAL, STATE OR INDIAN LEASES. In the event we conduct 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 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 our operations on federal leases to
be suspended or terminated. Any such suspension or termination could materially
and adversely affect our 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 we sell our production in the
spot market and therefore pay royalties on production from federal leases, it is
not anticipated that this final rule will have any substantial impact on us.
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. We own interests in numerous
federal onshore oil and gas leases. It is possible that some of our stockholders
may be citizens of foreign countries, which at some time in the future might be
determined to be non-reciprocal under the Mineral Act.
STATE REGULATIONS
Most states regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. The rate of production may be regulated and the maximum daily
production allowable from both oil and gas wells may be established on a market
demand or conservation basis or both.
We 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
14
rates which we 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, installing and operating such facilities. The impact of
such pipeline safety regulations would not be any more adverse to us than it
would be to other similar owners or operators of such pipeline facilities.
ENVIRONMENTAL REGULATIONS
GENERAL. Our activities are subject to federal, state and local laws and
regulations governing environmental quality and pollution control. Although no
assurances can be made, we believe that, absent the occurrence of an
extraordinary event, compliance with existing federal, state and local laws,
rules and regulations regulating the release of materials into the environment
or otherwise relating to the protection of the environment will not have a
material effect upon our capital expenditures, earnings or competitive position
with respect to our existing assets and operations. We cannot predict what
effect future regulation or legislation, enforcement policies, and claims for
damages to property, employees, other persons and the environment resulting from
our operations could have on our activities.
Our activities 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, installing and operating such
facilities. In most instances, the regulatory requirements relate to water and
air pollution control measures. Although we believe that compliance with
environmental regulations will not have a material adverse effect on us, 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 us.
SOLID AND HAZARDOUS WASTE. We currently own or lease, and in the past owned or
leased, properties that have been used for the exploration and production of oil
and gas for many years. Although we have utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
solid wastes may have been disposed or released on or under the properties owned
or leased by us or on or under locations where such wastes have been taken for
disposal. In addition, many of these properties have been operated by third
parties. We have no control over such entities' treatment of hydrocarbons or
other solid wastes and the manner in which such substances may have been
disposed or released. State and federal laws applicable to oil and gas wastes
and properties have gradually become stricter over time. Under new laws, we
could be required to remediate property, including groundwater, containing or
impacted by 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 or mitigate existing contamination.
We generate wastes, including hazardous wastes that are subject to the federal
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes.
The EPA and various state agencies have limited the disposal options for certain
wastes, including wastes designated as hazardous under the RCRA and similar
state statutes ("Hazardous Wastes"). Furthermore, it is possible that certain
wastes generated by our oil and gas operations that are (currently exempt from
treatment as) Hazardous Wastes may in the future be
15
designated as Hazardous Wastes under RCRA or other applicable statutes and,
therefore, may be subject to more rigorous and costly disposal requirements.
SUPERFUND. The federal Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, generally imposes
joint and several liability for costs of investigation and remediation and for
natural resource damages, without regard to fault or the legality of the
original conduct, on certain classes of persons with respect to the release into
the environment of substances designated under CERCLA as hazardous substances
("Hazardous Substances"). These classes of persons, or so-called potentially
responsible parties ("PRPs"), include the current and certain past owners and
operators of a facility where there has been a release or threat of release of a
Hazardous Substance and persons who disposed of or arranged for the disposal of
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 PRPs the costs of such
action. Although CERCLA generally exempts "petroleum" from the definition of
Hazardous Substance, in the course of its operations, we have generated and will
generate wastes that may fall within CERCLA's definition of Hazardous Substance.
We may also be the owner or operator of sites on which Hazardous Substances have
been released. To our knowledge, neither we nor our predecessors have been
designated as a PRP by the EPA under CERCLA. We also do not know of any prior
owners or operators of our properties that are named as PRPs related to their
ownership or operation of such properties.
CLEAN WATER ACT. The Clean Water Act ("CWA") imposes restrictions and strict
controls regarding the discharge of wastes including produced waters and other
oil and natural gas wastes, into waters of the United States, a term broadly
defined. These controls have become more stringent over the years, and it is
probable that additional restrictions will be imposed in the future. Permits
must be obtained to discharge pollutants into federal waters. The CWA provides
for civil, criminal and administrative penalties for unauthorized discharges of
oil and hazardous substances and of other pollutants. It imposes substantial
potential liability for the costs of removal or remediation associated with
discharges of oil or hazardous substances and other pollutants. State laws
governing discharges to water also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In addition, the EPA has promulgated regulations that may require us to obtain
permits to discharge storm water runoff, including discharges associated with
construction activities. In the event of an unauthorized discharge of wastes, we
may be liable for penalties and costs.
OIL POLLUTION ACT. The Oil Pollution Act of 1990 ("OPA"), which amends and
augments oil spill provisions of the CWA, imposes certain duties and liabilities
on certain "responsible parties" related to the prevention of oil spills and
damages resulting from such spills in or threatening United States waters or
adjoining shorelines. A liable "responsible party" includes the owner or
operator of a facility, vessel or pipeline that is a source of an oil discharge
or that poses the substantial threat of discharge, or the lessee or permittee of
the area in which a discharging facility is located. The OPA assigns joint and
several liability, without regard to fault, to each liable party for oil removal
costs and a variety of public and private damages. Although defenses and
limitations exist to the liability imposed by OPA, they are limited. In the
event of an oil discharge or substantial threat of discharge, we may be liable
for costs and damages.
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
16
upon worst case oil-spill discharge volume calculations. We believe that we have
established adequate proof of financial responsibility for our offshore
facilities.
AIR EMISSIONS. Our operations are subject to local, state and federal
regulations for the control of emissions from sources of air pollution. Federal
and state laws require new and modified sources of air pollutants to obtain
permits prior to commencing construction. Major sources of air pollutants are
subject to more stringent, federally imposed requirements including additional
permits. Federal and state laws designed to control hazardous (toxic) air
pollutants, might require installation of additional controls. Administrative
enforcement actions for failure to comply strictly with air pollution
regulations or permits are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could bring lawsuits for civil penalties or require us to forego construction,
modification or operation of certain air emission sources.
COASTAL COORDINATION. There are various federal and state programs that regulate
the conservation and development of coastal resources. The federal Coastal Zone
Management Act ("CZMA") was passed in 1972 to preserve and, where possible,
restore the natural resources of the Nation's coastal zone. The CZMA provides
for federal grants for state management programs that regulate land use, water
use and coastal development.
Various states, such as Alabama, Louisiana and Texas, also have coastal
management programs, which provide for, among other things, the coordination
among local and state authorities to protect coastal resources through
regulating land use, water, and coastal development. Coastal management programs
also may provide for the review of state and federal agency rules and agency
actions for consistency with the goals and policies of the state coastal
management plan. This review may impact agency permitting and review activities
and add an additional layer of review to certain activities undertaken by us.
OSHA AND OTHER REGULATIONS. We are 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 CERCLA and similar state statutes require us to organize
and/or disclose information about hazardous materials used or produced in its
operations.
Our management believes that we are 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 us.
PROPERTY SUMMARY
We are engaged in the exploration, development, acquisition and production of
oil and gas properties and provide oil and gas property management services for
other investors. Our properties are concentrated offshore in the Gulf of Mexico
and onshore, primarily, in Louisiana and Alabama. We have historically grown our
reserves and production by focusing primarily on low to moderate risk
exploration and acquisition opportunities in the Gulf of Mexico shelf area. Over
the last several years, we have expanded our area of exploration to include the
Gulf of Mexico deepwater area. As of December 31, 2003, our estimated net proved
reserves totaled 23.7 million barrels of oil ("MBbl") and 74.7 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 $570.5 million. Gas constitutes approximately 34% of
our total estimated proved reserves and approximately 42% of our total estimated
proved reserves are proved developed reserves.
17
Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block
341) discoveries began production in the fourth quarter of 2003. These two
deepwater discoveries are expected to increase our projected 2004 production by
approximately 85% from 2003 levels. A detail discussion of each of these
properties is provided in the "Significant Properties" section of this report.
SIGNIFICANT PROPERTIES
The following table shows discounted cash flows and estimated net proved oil and
gas reserves by major field, within the focus area, for our seven largest fields
and for all other properties combined at December 31, 2003.
ESTIMATED NET PROVED RESERVES PRE-TAX
------------------------------ DISCOUNTED
OIL GAS TOTAL PRESENT VALUE
OPERATOR (MBBLS) (MMCF) (MMCFE) ($000)
-------- -------- -------- -------- -------------
(A)(B)
GULF OF MEXICO DEEPWATER:
Mississippi Canyon Blocks 538/582
"Medusa" Murphy 10,312 6,173 68,043 $160,297
Garden Banks Block 341
"Habanero" Shell 4,687 11,207 39,328 124,876
Garden Banks Blocks 738/782/826/827
"Entrada" BP Amoco 7,772 29,126 75,760 185,608
GULF OF MEXICO SHELF:
Mobile Blocks 863/864/907/908 Callon -- 4,873 4,873 15,641
Mobile Blocks 952/953/955 Callon -- 15,229 15,229 60,487
Ship Shoal Blocks 28/35 Callon 6 701 739 3,115
ONSHORE AND OTHER:
Big Escambia Creek Exxon 422 1,188 3,718 6,116
Other Various 510 6,194 9,253 14,323
-------- -------- -------- --------
TOTAL NET PROVED RESERVES 23,709 74,691 216,943 $570,463
======== ======== ======== ========
(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, 2003, as set forth in the Company's
reserve reports prepared by its independent petroleum reserve engineers,
Huddleston & Co., Inc. of Houston, Texas.
(b) Includes a reduction for estimated plugging and abandonment costs that is
reflected as a liability on our balance sheet at December 31, 2003, in
accordance with Statement of Financial Accounting Standards No. 143.
18
GULF OF MEXICO DEEPWATER
Medusa, Mississippi Canyon Blocks 538/582
Our Medusa deepwater discovery was announced in September 1999, when we drilled
the initial test well in 2,235 feet of water to a total depth of 16,241 feet and
encountered over 120 feet of pay in two intervals. Subsequent sidetrack drilling
from the wellbore was used to determine the extent of the discovery and a second
successful well was drilled in the first quarter of 2000 to further delineate
the extent of the pay intervals. We own a 15% working interest, Murphy, the
operator, owns a 60% working interest and Agip Ventures, formerly British-Borneo
Petroleum, Inc., owns the remaining 25% working interest.
In 2001 a drilling program began which included four development wells and one
sidetrack. The program included production casing being set on six wells to
provide initial production take-points. The program was completed in the first
half of 2002. Also in 2001, the operator submitted an Authorization for
Expenditure for a floating production system, spar, at Medusa and awarded the
contract to J. Ray McDermott, Inc. The spar hull was barged to Mississippi
Canyon Block 582 during the first quarter of 2003, uprighted, moored and placed
in position to receive the production deck. The topside deck and production
facilities were delivered and lifted into place atop the spar hull during the
second quarter of 2003. The A-1 well, the first of six, was completed and tied
into the spar and commenced production in late November 2003. The A-2 well
commenced production in January 2004 and during February 2004 the field produced
approximately 19,000 barrels of oil and 18 million cubic feet of gas per day.
Initial production from the A-3 well is expected during March 2004 and will be
followed by initial production from the A-6 and A-4 wells in the second quarter
of 2004 with production from the A-5 well expected early in the 3rd quarter of
2004. Peak production from the field is expected to reach approximately 40,000
barrels of crude oil and 35 million cubic feet of natural gas per day.
In December 2003, we transferred our undivided 15% working interest in the spar
production facilities to Medusa Spar LLC in exchange for cash proceeds of
approximately $25 million and a 10% ownership interest in the LLC. A detailed
discussion of this transaction is included in Management's Discussion and
Analysis of Financial Condition and Results of Operations-"Off-Balance Sheet
Arrangements".
Habanero, Garden Banks Block 341
During February 1999 the initial test well on our Habanero deepwater discovery
encountered over 200 feet of net pay in two zones. Located in 2,000 feet of
water, the well was drilled to a measured depth of 21,158 feet. We own an 11.25%
working interest in the well. The well is operated by Shell Deepwater
Development Inc., which owns a 55% working interest, with the remaining working
interest being owned by Murphy.
A field delineation program began in mid-year 2001, which included three
sidetracks of the discovery well. Production casing was set on this well through
one of the sidetracks to the Habanero 52 oil and gas sand and the Habanero 55
gas sand. Initial production will be from the Habanero 55 gas sand and future
recompletions are scheduled up-hole to the Habanero 52 oil and gas sand. Also, a
development well was drilled in the summer of 2003 which provides a take-point
for production from the Habanero 52 oil sand.
19
By means of a sub-sea completion and tie back to an existing production facility
in the area operated by Shell, production from the Habanero 52 oil sand
commenced in late November 2003. Production from the Habanero 55 gas sand
commenced in January, after mechanical adjustments were made down hole. Gross
production during February 2003 from the Habanero field was approximately 22,000
barrels of oil and 56 million cubic feet of gas per day.
Entrada, Garden Banks Blocks 738/782/826/827
The Entrada discovery is located in approximately 4,500 feet of water in the
Gulf of Mexico. Two wells and seven sidetracks have been drilled to date on
Garden Banks 782 on a northwest plunging salt ridge along the southern edge of
the Entrada Basin. Multiple stacked amplitudes trapped against a salt or fault
interface characterize the Entrada Area. We own a 20% working interest in this
discovery with BP Amoco, the operator, holding the remaining working interest.
The owners of an adjacent discovery have announced their plans to construct
production facilities to enable them to be a regional off-take point in
Southeastern Garden Banks. These plans include handling third party tie-ins. We
expect to tie-in Entrada to this regional off-take point with initial production
anticipated in 2006. First production from the adjacent discovery is expected in
late 2004. Information obtained in a data swap with the adjacent owners is being
incorporated into the Entrada development plans. An integrated project team was
formed by the working interest owners during 2002 to begin planning the
development of the field. The team has been reviewing alternate development
plans which could accelerate field development.
GULF OF MEXICO SHELF
Mobile Blocks 863/864/ 907/908
We own an average 67.9% working interest in these blocks and we are the
operator. The Mobile 864 unit, in which we have a 66.4% working interest, has
three producing wells, unit production facilities and covers portions of these
four blocks. During 2003 the unit produced an average of 4.9 MMcf per day net to
us.
Mobile Blocks 952/953/955
We own a 100% working interest in these three blocks and we are the operator. In
the fourth quarter of 2001, we initiated a production acceleration program for
Mobile Blocks 952, 953 and 955, which were being produced through the Mobile
Block 864 unit facilities. An acceleration well was successfully drilled in the
fourth quarter of 2001 and stand-alone production facilities were installed and
production flow lines were rerouted to the new facilities. Production commenced
through the new facilities in April 2002. In order to completely produce the
proved reserves of the field we drilled a development well on Mobile Block 955
during the first quarter of 2004. The well is flowing without compression and
commenced production in March 2004 at a gross rate of approximately 8 MMcf per
day. The installation of compression facilities at the well site is expected to
be completed by June 2004 and should increase the production rate by an
additional 2-3 MMcf per day. Production from the field for 2003 was 19.6 MMcf
per day net to us. Production for 2002 was 14.0 MMcf per day net to us.
20
Ship Shoal Blocks 28/35
We successfully drilled an exploratory well at Ship Shoal Blocks 28 and 35
during the third quarter of 2002. The well was drilled to a measured depth of
15,237 feet (12,295 feet of true vertical depth) and encountered 140 feet of net
natural gas pay. The well was completed as a single producer in the deepest of
three productive intervals and first production commenced in late April, 2003
and averaged 1.7 MMcfe per day net to us through December 31, 2003. We operate
and own a 22% working interest.
ONSHORE AND OTHER
Big Escambia Creek
This gas field in south Alabama produces from the Smackover formation at depths
ranging from 15,100 to 15,600 feet and is operated by ExxonMobil. We own an
average working interest of 4.9% (5.5% net revenue interest), in six wells and a
2.2% average royalty interest in another five wells. This field produced 0.7
MMcfe per day to our interest in 2003. The field has an estimated reserve life
in excess of 10 years given current production rates.
Other
We own various royalty and working interests in numerous onshore areas and the
Gulf of Mexico other than the fields discussed above.
21
OIL AND GAS RESERVES
The following table sets forth certain information about our estimated proved
reserves as of the dates set forth below.
YEARS ENDED DECEMBER 31,
---------------------------------
2003 2002(a) 2001(a)
--------- --------- ---------
(IN THOUSANDS)
Proved developed:
Oil (Bbls) 9,919 1,056 885
Gas (Mcf) 31,415 37,631 52,375
Mcfe 90,926 43,966 57,683
Proved undeveloped:
Oil (Bbls) 13,790 22,988 29,324
Gas (Mcf) 43,276 53,908 69,078
Mcfe 126,017 191,833 245,023
Total proved:
Oil (Bbls) 23,709 24,043 30,209
Gas (Mcf) 74,691 91,539 121,453
Mcfe 216,943 235,799 302,706
Estimated pre-tax future net cash flows(b) $ 838,847 $ 970,198 $ 473,896
========= ========= =========
Pre-tax discounted present value (b) $ 570,463 $ 623,946 $ 272,053
========= ========= =========
Standardized measure of discounted future
net cash flows(b) $ 519,026 $ 556,046 $ 254,857
========= ========= =========
(a) The estimates include reserve volumes of approximately 1.2 Bcf, $2.9
million of pre-tax discounted present value in 2001, attributable to
a volumetric production payment. Standardized measure of discounted
future net cash flows does not include any volumes or cash flows
associated with the volumetric production payment.
(b) Includes a reduction for estimated plugging and abandonment costs
that is reflected as a liability on our balance sheet at December
31, 2003, in accordance with Statement of Financial Accounting
Standards No. 143.
Our independent reserve engineers, Huddleston & Co., Inc., prepared the
estimates of the proved reserves and the future net cash flows and present value
thereof attributable to such proved reserves. Reserves were estimated using oil
and gas prices and production and development costs in effect on December 31 of
each such year, without escalation, and were otherwise prepared in accordance
with Securities and Exchange Commission regulations regarding disclosure of oil
and gas reserve information.
There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond our control or the control of the
reserve engineers. Reserve engineering is a subjective
22
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact manner. The accuracy of any reserve or cash flow estimate
is a function of the quality of available data and of engineering and geological
interpretation and judgment. Estimates by different engineers often vary,
sometimes significantly. In addition, physical factors, such as the results of
drilling, testing and production subsequent to the date of an estimate, as well
as economic factors, such as an increase or decrease in product prices that
renders production of such reserves more or less economic, may justify revision
of such estimates. Accordingly, reserve estimates could be different from the
quantities of oil and gas that are ultimately recovered.
We have not filed any reports with other federal agencies which contain an
estimate of total proved net oil and gas reserves during our last fiscal year.
PRESENT ACTIVITIES AND PRODUCTIVE WELLS
The following table sets forth the wells we have drilled and completed during
the periods indicated. All such wells were drilled in the continental United
States primarily in federal and state waters in the Gulf of Mexico.
YEARS ENDED DECEMBER 31,
---------------------------------------------
2003 2002 2001
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Development:
Oil 2 .23 2 .30 6 .45
Gas -- -- -- -- 4 3.17
Non-productive -- -- 1 .40 -- --
----- ----- ----- ----- ----- -----
Total 2 .23 3 .70 10 3.62
===== ===== ===== ===== ===== =====
Exploration:
Oil 1 .15 -- -- -- --
Gas -- -- 1 .22 3 2.00
Non-productive 1 .20 1 .50 12 5.77
----- ----- ----- ----- ----- -----
Total 2 .35 2 .72 15 7.77
===== ===== ===== ===== ===== =====
The following table sets forth our productive wells as of December 31, 2003:
WELLS
--------------
GROSS NET
------ -----
Oil:
Working interest 39.00 3.05
Royalty interest 188.00 3.20
------ ----
Total 227.00 6.25
====== ====
Gas:
Working interest 41.00 21.11
Royalty interest 209.00 1.67
------ ----
Total 250.00 22.78
====== =====
23
A well is categorized as an oil well or a natural gas well based upon the ratio
of oil to gas reserves on a Mcfe basis. However, some of our wells produce both
oil and gas. At December 31, 2003, we had no wells with multiple completions. At
December 31, 2003, we had 1 gross (0.03 net) exploratory oil well in progress.
LEASEHOLD ACREAGE
The following table shows our approximate developed and undeveloped (gross and
net) leasehold acreage as of December 31, 2003.
LEASEHOLD ACREAGE
-----------------------------------
DEVELOPED UNDEVELOPED
---------------- ----------------
LOCATION GROSS NET GROSS NET
-------------- ------- ------ ------- ------
Louisiana 6,554 4,179 3,770 1,179
Other states 680 362 681 509
Federal waters 101,743 73,483 295,180 77,207
------- ------ ------- ------
Total 108,977 78,024 299,631 78,895
======= ====== ======= ======
As of December 31, 2003, we owned various royalty and overriding royalty
interests in 1,336 net developed and 6,862 net undeveloped acres. In addition,
we owned 4,711 developed and 121,289 undeveloped mineral acres.
MAJOR CUSTOMERS
Our production is sold generally 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 12-month
periods ended:
DECEMBER 31,
----------------------
2003 2002 2001
---- ---- ----
Petrocom Energy Group, Ltd. 4% 4% --
Dynegy 5% 7% 8%
Prior Energy Corporation 20% -- 20%
Reliant Energy Services 28% 70% 49%
Louis Dreyfus Energy Services 27% -- --
Because alternative purchasers of oil and gas are readily available, we believe
that the loss of any of these purchasers would not result in a material adverse
effect on our ability to market future oil and gas production.
TITLE TO PROPERTIES
We believe that the title to our oil and gas properties is good and defensible
in accordance with standards generally accepted in the oil and gas industry,
subject to such exceptions which, in our opinion, are not so
24
material as to detract substantially from the use or value of such properties.
Our properties are typically subject, in one degree or another, to one or more
of the following:
- royalties and other burdens and obligations, express or implied,
under oil and gas leases;
- overriding royalties and other burdens created by us or our
predecessors in title;
- a variety of contractual obligations (including, in some cases,
development obligations) arising under operating agreements, farmout
agreements, production sales contracts and other agreements that may
affect the properties or their titles;
- back-ins and reversionary interests existing under purchase
agreements and leasehold assignments;
- liens that arise in the normal course of operations, such as those
for unpaid taxes, statutory liens securing obligations to unpaid
suppliers and contractors and contractual liens under operating
agreements;
- pooling, unitization and communitization agreements, declarations
and orders; and easements, restrictions, rights-of-way and other
matters that commonly affect property.
To the extent that such burdens and obligations affect our rights to production
revenues, they have been taken into account in calculating our net revenue
interests and in estimating the size and value of our reserves. We believe that
the burdens and obligations affecting our properties are conventional in the
industry for properties of the kind owned by us.
ITEM 3. LEGAL PROCEEDINGS
We are a defendant in various legal proceedings and claims, which arise in the
ordinary course of our business. We do not believe the ultimate resolution of
any such actions will have a material affect on our financial position or
results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth
quarter of 2003.
25
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock trades on the New York Stock Exchange under the symbol "CPE".
The following table sets forth the high and low sale prices per share as
reported for the periods indicated.
QUARTER ENDED HIGH LOW
-------------- ------ ------
2002:
First quarter $ 9.40 $ 3.97
Second quarter 8.39 4.50
Third quarter 5.15 3.20
Fourth quarter 6.25 3.35
2003:
First quarter $ 4.35 $ 3.35
Second quarter 8.44 3.66
Third quarter 7.95 5.46
Fourth quarter 11.48 7.31
As of March 4, 2004, there were approximately 4,514 common stockholders of
record.
We have never paid dividends on our common stock and intend to retain our cash
flow from operations, net of preferred stock dividends, for the future operation
and development of our business. In addition, our primary credit facility and
the terms of our outstanding subordinated debt prohibit the payment of cash
dividends on our common stock.
In December 2003, we borrowed $185 million pursuant to an amended and restated
senior unsecured credit agreement dated December 23, 2003. In connection with
our borrowings under the senior unsecured credit agreement, we issued to the
lenders under the credit agreement warrants to purchase an aggregate of
2,775,000 shares of our common stock at an exercise price of $10.00 per share.
The warrants are exercisable for seven years from the date of issuance. The
issuance of the warrants was exempt pursuant to Section 4(2) of the Securities
Act of 1933.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth, as of the dates and for the periods indicated,
selected financial information about us. The financial information for each of
the five years in the period ended December 31, 2003 has been derived from our
audited Consolidated Financial Statements for such periods. The information
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements and Notes thereto. The following information is not necessarily
indicative of our future results.
26
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
2003 2002 2001 2000 1999
---------- ---------- ---------- ---------- ----------
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil and gas sales $ 73,697 $ 61,171 $ 60,010 $ 56,310 $ 37,140
---------- ---------- ---------- ---------- ----------
Operating expenses:
Lease operating expenses 11,301 11,030 11,252 9,339 7,536
Depreciation, depletion and amortization 28,253 27,096 21,081 17,153 16,727
General and administrative 4,713 4,705 4,635 4,155 4,575
Accretion expense 2,884 -- -- -- --
Loss on mark-to-market commodity derivative contracts 535 708 -- -- --
---------- ---------- ---------- ---------- ----------
Total operating expenses 47,686 43,539 36,968 30,647 28,838
---------- ---------- ---------- ---------- ----------
Income (loss) from operations 26,011 17,632 23,042 25,663 8,302
---------- ---------- ---------- ---------- ----------
Other (income) expenses:
Interest expense 30,614 26,140 12,805 8,420 6,175
Other income (444) (1,004) (1,742) (1,767) (1,853)
Loss on early extinguishment of debt 5,573 -- -- --
Gain on sale of pipeline -- (2,454) -- -- --
Gain on sale of Enron derivatives -- (2,479) -- -- --
Writedown of Enron derivatives -- -- 9,186 -- --
---------- ---------- ---------- ---------- ----------
Total other (income) expenses 35,743 20,203 20,249 6,653 4,322
---------- ---------- ---------- ---------- ----------
Net income (loss) before income taxes (9,732) (2,571) 2,793 19,010 3,980
Income tax expense (benefit) 8,432 (900) 977 6,463 1,353
---------- ---------- ---------- ---------- ----------
Net income (loss) before Medusa Spar LLC and
cumulative effect of change in accounting principle (18,164) (1,671) 1,816 12,547 2,627
Loss on Medusa Spar LLC, net of tax (8) -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income (loss) before cumulative effect of change in
in accounting principle (18,172) (1,671) 1,816 12,547 2,627
Cumulative effect of change in accounting principle,
net of tax 181 -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income (loss) (17,991) (1,671) 1,816 12,547 2,627
Preferred stock dividends 1,277 1,277 1,277 2,403 2,497
---------- ---------- ---------- ---------- ----------
Net income (loss) available to common shares $ (19,268) $ (2,948) $ 539 $ 10,144 $ 130
========== ========== ========== ========== ==========
27
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
----------------------------------------------------
2003 2002 2001 2000 1999
-------- -------- -------- -------- --------
Net income (loss) available to common shares $(19,268) $ (2,948) $ 539 $ 10,144 $ 130
======== ======== ======== ======== ========
Net income (loss) per common share:
Basic:
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .82 $ .01
Cumulative effect of change in accounting principle,
net of tax .01 -- -- -- --
-------- -------- -------- -------- --------
Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .82 $ .01
======== ======== ======== ======== ========
Diluted:
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .80 $ .01
Cumulative effect of change in accounting principle,
net of tax .01 -- -- -- --
-------- -------- -------- -------- --------
Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .80 $ .01
======== ======== ======== ======== ========
Shares used in computing net income (loss) per common share:
Basic 13,662 13,387 13,273 12,420 8,976
======== ======== ======== ======== ========
Diluted 13,662 13,387 13,366 12,745 9,075
======== ======== ======== ======== ========
BALANCE SHEET DATA (END OF PERIOD):
Oil and gas properties, net $390,163 $377,661 $343,158 $258,613 $194,365
Total assets $496,032 $410,613 $372,095 $301,569 $259,877
Long-term debt, less current portion $214,885 $248,269 $161,733 $134,000 $100,250
Stockholders' equity $133,261 $140,960 $147,224 $136,328 $124,380
- ----------
We use the full-cost method of accounting. Under this method of
accounting, our net capitalized costs to acquire, explore and develop oil
and gas properties may not exceed the standardized measure of our proved
reserves. If these capitalized costs exceed a ceiling amount, the excess
is charged to expense.
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in an understanding of our
financial condition and results of operations. Our Consolidated 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
We have been engaged in the exploration, development, acquisition and production
of oil and gas properties since 1950. Our revenues, profitability and future
growth and the carrying value of our oil and gas properties are substantially
dependent on prevailing prices of oil and gas and our ability to find, develop
and acquire additional oil and gas reserves that are economically recoverable.
Our ability to maintain or increase our borrowing capacity and to obtain
additional capital on attractive terms is also influenced by oil and gas prices.
Significant events of our financial and operating results for the year ended
December 31, 2003 included:
- borrowing $185 million for a term of seven-years at an interest rate
of 9.75% pursuant to a senior unsecured credit agreement;
- the contribution of our 15% working interest in the Medusa spar
production facilities into a limited liability company in return for
approximately $25 million of cash and a 10% interest in the limited
liability company which will earn a throughput fee for production
processed in the Medusa area; and
- the commencement of production from two of our deepwater
discoveries, Medusa and Habanero, in late November 2003 which is
expected to increase production for 2004 by approximately 80% over
2003 levels.
- a charge of $11.5 million to income tax expense as the result of
establishing a valuation allowance against our deferred tax asset
required by SFAS 109 "Accounting for Income Taxes". This charge was
taken due to the negative evidence resulting from the cumulative
losses incurred for the three year period ending December 31, 2003.
Relevant accounting guidance suggests that positive future
expectations about income are diminished by such losses. If the
Company achieves profitable operations in 2004, the Company expects
it will reverse a portion of the valuation allowance in an amount at
least sufficient to eliminate any tax provision in that period. See
Note 3 to the Company's Consolidated Financial Statements for a more
detailed discussion.
These financial transactions allowed us to redeem $62.9 million of senior
subordinated notes which were maturing in 2004, redeem $85.0 million of 12%
loans maturing in March 2005 and reduce the outstanding balance under our senior
secured credit facility. As a result, we expect that planned 2004 capital
expenditures of approximately $65 million will be funded with cash flows from
operations and draws under our senior secured credit facility, if necessary. The
current borrowing base of $45 million under the senior secured credit facility,
which had $30.0 million outstanding against it on December 31, 2003, is
currently under review and may be increased since a majority of our reserves for
Medusa and Habanero are now classified as proved developed reserves. This credit
facility matures on June 30, 2004 and we
29
anticipate extending the due date or replacing it with a facility with similar
or more favorable terms. For a more detailed discussion of outstanding debt see
Note 5 to our Consolidated Financial Statements.
Our estimated net proved oil and gas reserves decreased at December 31, 2003 to
217 billion cubic feet of natural gas equivalent (Bcfe). This represents a
decrease of 8% from previous year-end 2002 estimated proved reserves of 236
Bcfe.
We incurred a major downward revision to proved reserves in 2002 at our
Boomslang discovery. The initial exploratory well drilled at this location in
1998 encountered 185 feet of pay. The well was drilled with mechanical problems
and was subsequently determined not to be a viable well for completion and
production of the estimated proved reserves encountered in this initial well. A
second well, drilled in the fourth quarter of 2002, to serve as a production
take point, was drilled in a down dip direction from the first well targeting
what was anticipated to be a better sand development in the three separate
reservoirs found in the first well, but still up dip of the lowest known
hydrocarbons in the first well. Reservoir sand quality changed dramatically,
reducing the estimated reservoir volumes found and booked as estimated proved
reserves by the first well to an extent that the partners determined that the
risk of development was not economic. Callon had a 40% working interest. The
Company's proved reserves in the prior year included 7.2 million barrels of oil
and 13 billion cubic feet of natural gas attributable to Boomslang.
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond our control. These
factors include weather conditions in the United States, the condition of the
United States economy, the actions of the Organization of Petroleum Exporting
Countries, governmental regulation, political stability in the Middle East and
elsewhere, the foreign supply of crude oil and natural gas, the price of foreign
imports and the availability of alternate fuel sources. Any substantial and
extended decline in the price of crude oil or natural gas would have an adverse
effect on our carrying value of our proved reserves, borrowing capacity,
revenues, profitability and cash flows from operations. We use derivative
financial instruments (see Note 6 and Item 7A. "Quantitative and Qualitative
Disclosures About Market Risks") for price protection purposes on a limited
amount of our future production and do not use them for trading purposes. On a
Mcfe basis, natural gas represents 45% of the budgeted 2004 production and 34%
of proved reserves at year-end 2003.
Inflation has not had a material impact on us and is not expected to have a
material impact on us in the future.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
RECENT ACCOUNTING PRONOUNCEMENTS. In June 1998, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards No.
133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities.
The Statement establishes accounting and reporting standards requiring that
every derivative instrument, including certain derivative instruments embedded
in other contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS 133 requires us to report changes in
the fair value of our derivative financial instruments that qualify as cash flow
hedges in other comprehensive income, a component of stockholders' equity, until
realized. We adopted SFAS 133 effective January 1, 2001.
In June 2001, the FASB issued Statement of Financial Accounting Standards No.
143, Accounting for Asset Retirement Obligations ("SFAS 143") effective for
fiscal years beginning after June 15, 2002. SFAS 143 essentially requires
entities to record the fair value of a liability for obligations associated with
the retirement of tangible long-lived assets and the associated asset retirement
costs. We adopted the
30
statement on January 1, 2003 resulting in a cumulative effect of accounting
change of $181,000, net of tax. See Note 8 to our Consolidated Financial
Statements.
In December 2002, the FASB issued Statement of Financial Accounting Standards
No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and
Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123 to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. In addition, this
statement amends the disclosure requirements of SFAS 123 to require disclosures
in both annual and interim financial statements about the method of accounting
for stock-based employee compensation and the effect of the method used on the
reported results. SFAS 148 is effective for the year ended December 31, 2002 and
for interim financial statements commencing in 2003. The adoption of this
pronouncement by us did not have an impact on our financial condition or results
of operations.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
(ARB) 51" ("FIN 46"). FIN 46 addresses consolidation by business enterprises of
variable interest entities ("VIEs"). The primary objective of FIN 46 is to
provide guidance on the identification of, and financial reporting for, entities
over which control is achieved through means other than voting rights; such
entities are known as VIEs. The provisions of FIN 46 are effective immediately
for these variable interest entities created after January 31, 2003. On December
24, 2003, the FASB issued a revision to FIN 46 which among other things deferred
the effective date for certain variable interests created prior to January 31,
2003. Application is required for interests in special-purpose entities in the
periods ending after December 15, 2003 and application is required for all other
types of variable interest entities in the periods ending after March 31, 2004.
We adopted FIN 46, as revised, as of December 31, 2003, which had no impact on
the financial statements.
In June 2001, the FASB issued Statement of Financial Accounting Standards No.
141 ("SFAS 141"), "Business Combinations," which requires the use of the
purchase method of accounting for business combinations initiated after June 30,
2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also
issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"),
"Goodwill and Other Intangible Assets," which discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and initiates an
annual review of impairment. The new standard also requires that all intangible
assets be aggregated and presented as a separate line item in the balance sheet.
The adoption of SFAS No. 141 and 142 had no impact on the Company's financial
position or results of operations. A reporting issue has arisen regarding the
application of certain provisions of SFAS No. 141 and 142 to companies in the
oil and gas industry. The issue is whether SFAS No. 141 requires registrants to
classify the costs of mineral rights associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide specific footnote disclosures. Historically, the
Company has included the costs of mineral rights associated with extracting oil
and gas as a component of oil and gas properties. These costs include those to
acquire contract based drilling and mineral use rights such as delay rentals,
lease bonuses, commissions and brokerage fees, and other leasehold costs.
The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas
mineral rights to an upcoming agenda, which may result in a change in the
classification of these amounts, as described above. The Company will continue
to classify its oil and gas leasehold costs as tangible oil and gas properties
until further guidance is provided. The Company's cash flows and results of
operations would not be affected since such intangible assets would continue to
be depleted and assessed for impairment in accordance with full cost accounting
rules, as allowed by SFAS No. 142. Further, the Company believes
31
that the amounts that would be classified as intangible assets as of December
31, 2003 and 2002, would be immaterial.
PROPERTY AND EQUIPMENT. We follow the full-cost method of accounting for oil and
gas properties whereby all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves, including certain overhead
costs, are capitalized into the "full-cost pool." The amounts we capitalize into
the full-cost pool are depleted (charged against earnings) using the
unit-of-production method. The full-cost method of accounting for our proved oil
and gas properties requires that we make estimates based on assumptions as to
future events which could change. These estimates are described below.
Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We
calculate depletion by using the capitalized costs in our full-cost pool plus
future development and abandonment costs (combined, the depletable base) and our
estimated net proved reserve quantities. Capitalized costs added to the
full-cost pool and other costs added to the depletable base include the
following:
- the cost of drilling and equipping productive wells, dry hole costs,
acquisition costs of properties with proved reserves, delay rentals
and other costs related to exploration and development of our oil
and gas properties;
- our payroll and general and administrative costs and costs related
to fringe benefits paid to employees directly engaged in the
acquisition, exploration and/or development of oil and gas
properties as well as other directly identifiable general and
administrative costs associated with such activities. Such
capitalized costs do not include any costs related to our production
of oil and gas or our general corporate overhead;
- costs associated with properties that do not have proved reserves
attributed to them are excluded from the full cost pool. These
unevaluated property costs are added to the full cost pool at such
time as wells are completed on the properties, the properties are
sold or we determine these costs have been impaired. Our
determination that a property has or has not been impaired (which is
discussed below) requires that we make assumptions about future
events;
- our estimates of future costs to develop proved properties are added
to the full cost pool for purposes of the DD&A computation. We use
assumptions based on the latest geologic, engineering, regulatory
and cost data available to us to estimate these amounts. However,
the estimates we make are subjective and may change over time. Our
estimates of future development costs are periodically updated as
additional information becomes available; and
- prior to the adoption of SFAS 143, estimated costs to dismantle,
abandon and restore a proved property were added to the full cost
pool for the purposes of DD&A. Subsequent to the adoption of SFAS
143, effective January 1, 2003, these costs are included in the full
cost pool. Such cost estimates are periodically updated as
additional information becomes available. As discussed above under
Accounting Pronouncements, specifically SFAS 143, beginning January
1, 2003, we changed the method for which we account for such costs.
Capitalized costs included in the full-cost pool are depleted and charged
against earnings using the unit of production method. Under this method, we
estimate our quantity of proved reserves at the beginning of each accounting
period. For each barrel of oil equivalent produced during the period, we record
a depletion charge equal to the amount included in the depletable base (net of
accumulated depreciation, depletion and amortization) divided by our estimated
net proved reserve quantities.
Because we use estimates and assumptions to calculate proved reserves (as
discussed below) and the amounts included in the full-cost pool, our depletion
calculations will change if the estimates and assumptions are not realized. Such
changes may be material.
32
Ceiling Test. Under the full-cost accounting rules, capitalized costs included
in the full-cost pool, net of accumulated depreciation, depletion and
amortization (DD&A), cost of unevaluated properties and deferred income taxes,
may not exceed the present value of our estimated future net cash flows from
proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or
fair value of unproved properties included in the costs being amortized, net of
related tax effects. These rules generally require that, in estimating future
net cash flow, we assume that future oil and gas production will be sold at the
unescalated market price for oil and gas received at the end of each fiscal
quarter and that future costs to produce oil and gas will remain constant at the
prices in effect at the end of the fiscal quarter. We are required to write-down
and charge to earnings the amount, if any, by which these costs exceed the
discounted future net cash flows, unless prices recover sufficiently before the
date of our financial statements. Given the volatility of oil and gas prices, it
is likely that our estimates of discounted future net cash flows from proved oil
and gas reserves will change in the near term. If oil and gas prices decline
significantly, even if only for a short period of time, it is possible that
writedowns of oil and gas properties could occur in the future.
Estimating Reserves and Present Values. Our estimates of quantities of proved
oil and gas reserves and the discounted present value of such reserves at the
end of each quarter are based on numerous assumptions which are likely to change
over time. These assumptions include:
- the prices at which we can sell our oil and gas production in the
future. Oil and gas prices are volatile, but we are generally
required to assume that they will not change from the prices in
effect at the end of the quarter. In general, higher oil and gas
prices will increase quantities of proved reserves and the present
value of such reserves, while lower prices will decrease these
amounts. Because our properties have relatively short productive
lives, changes in prices will affect the present value more than
quantities of oil and gas reserves; and
- the costs to develop and produce our reserves and the costs to
dismantle our production facilities when reserves are depleted.
These costs are likely to change over time, but we are required to
assume that costs in effect at the end of the quarter will not
change. Increases in costs will reduce oil and gas quantities and
present values, while decreases in costs will increase such amounts.
Because our properties have relatively short productive lives,
changes in costs will affect the present value more than quantities
of oil and gas reserves.
- the potential liability to pay royalties to the Mineral Management
Service on some of the Company's properties which qualify for
royalty relief under the Deep Water Royalty Relief Act could reduce
proved reserves. See Note 7 of our Consolidated Financial Statements
for a more detailed discussion of this potential liability.
In addition, the process of estimating proved oil and gas reserves requires that
our independent and internal reserve engineers exercise judgment based on
available geological, geophysical and technical information. We have described
the risks associated with reserve estimation and the volatility of oil and gas
prices, under "Risk Factors" .
Unproved Properties. Costs associated with properties that do not have proved
reserves, including capitalized interest, are excluded from the full-cost pool.
These unproved properties are included in the line item "Unevaluated properties
excluded from amortization." Unproved property costs are transferred to the
full-cost pool when wells are completed on the properties or the properties are
sold. In addition, we are required to determine whether our unproved properties
are impaired and, if so, add the costs of such properties to the full-cost pool.
We determine whether an unproved property should be impaired by periodically
reviewing our exploration program on a property by property basis. This
determination may require the exercise of substantial judgment by our
management.
33
DERIVATIVES. We use derivative financial instruments for price protection
purposes on a limited amount of our future production and do not use them for
trading purposes. Such derivatives were accounted for in years prior to 2001 as
hedges and have been recognized as an adjustment to oil and gas sales in the
period in which they are related. We currently use the accounting treatment for
derivatives specified under SFAS 133.
INCOME TAXES. We follow 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.
SFAS 109 provides for the weighing of positive and negative evidence in
determining whether it is more likely than not that a deferred tax asset is
recoverable. We have incurred losses in 2002 and 2003 and have losses on an
aggregate basis for the three-year period ended December 31, 2003. However, as
discussed in Note 5, in December 2003 we refinanced nearly all our highest cost
debt, incurring an early extinguishment loss of $5.6 million, but achieving
significant interest savings in the future. In addition, as discussed in Note 5,
the first two of our deepwater projects began production in November 2003, which
is expected to result in a significant increase in 2004 production as compared
to 2003. Nevertheless, relevant accounting guidance suggests that a recent
history of cumulative losses constitutes significant negative evidence, and that
future expectations about income are overshadowed by such recent losses. As a
result, we established a valuation allowance of $11.5 million as of December 31,
2003. If we achieve profitable operations in 2004, we expect to reverse a
portion of the valuation allowance in an amount at least sufficient to eliminate
any tax provision in that period. See Note 3 of our Consolidated Financial
Statements for further disclosure.
LIQUIDITY AND CAPITAL RESOURCES
Our primary sources of capital are cash flows from operations, borrowings from
financial institutions and the sale of debt and equity securities. Net cash and
cash equivalents increased during 2003 to $8.7 million, up $2.9 million. Cash
provided from operating activities during 2003 totaled $34.6 million, up from
$12.2 million in 2002. Cash provided by operating activities during 2004 is
expected to increase significantly due to the Medusa and Habanero deepwater
projects commencing production in late November 2003. Dividends paid on
preferred stock were $1.3 million. Most of our outstanding debt was restructured
during December 2003. The restructuring of our debt is discussed in the
following paragraphs.
In December 2003 we borrowed $185 million pursuant to a senior unsecured credit
facility with a stated interest rate of 9.75%. The net proceeds from the loans
of $181.3 million were used to redeem $22.9 million of 10.125% senior
subordinated notes due July 31, 2004, $40 million of 10.25% senior subordinated
notes due September 15, 2004, $85 million of our 12% loans due March 31, 2005
plus a 1% call premium of $850,000 and to reduce the balance outstanding under
our senior secured revolving credit facility. A charge of $5.3 million was
incurred in 2003 as a result of the early extinguishment of debt for the 12%
loans due March 31, 2005 and a charge of approximately $1.4 million will be
incurred in 2004 for the early extinguishment of the $22.9 million 10.125%
senior subordinated notes due July 31, 2004 and the $40 million 10.25% senior
subordinated notes due September 15, 2004. We exercised covenant defeasance
under the indentures for the 10.125% and 10.25% notes on December 8, 2003 and
distributed a required 30-
34
day redemption notice. The funds necessary to redeem the notes were placed in
trust and the trustee paid the holders of the notes on January 8, 2004. The
funds in trust were classified on our December 31, 2003 balance sheet as
restricted cash. In conjunction with the new senior unsecured notes, we issued
detachable warrants to purchase 2.775 million of our common stock at an exercise
price of $10 per share. This senior unsecured debt matures December 8, 2010. See
Note 5 of our Consolidated Financial Statements for a more detailed description
of these securities.
In December 2003, we announced the formation of a limited liability company,
Medusa Spar LLC, which now owns a 75% undivided ownership interest in the
deepwater spar production facilities on our Medusa Field in the Gulf of Mexico.
We contributed a 15% undivided ownership interest in the production facility to
the LLC in return for approximately $25 million in cash and a 10% ownership
interest in the LLC. Our cash proceeds were used to reduce the balance
outstanding under our senior secured credit facility. The LLC will earn a tariff
based upon production volume throughput from the Medusa area. We are obligated
to process our share of production from the Medusa field and any future
discoveries in the area through the spar production facilities. The LLC used the
cash proceeds from $83.7 of non-recourse financing and a cash contribution by
one of the LLC owners to acquire its 75% interest in the spar. The balance of
the LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil
Corporation (NYSE:MUR). We are accounting for our 10% ownership interest in the
LLC under the equity method.
Our remaining maturities for unsecured debt, excluding the $185 million in 9.75%
loans due 2010, consists of $10 million of the 12% loans with a due date of
March 31, 2005 and $33 million of 11% senior subordinated notes with a due date
of December 15, 2005. These 2005 maturities will be retired by our primary
sources of capital which are cash flows from operations, borrowings from
financial institutions and the sale of debt and equity securities. See Note 5 of
our Consolidated Financial Statements for a more detailed description of these
securities
Borrowings under our senior secured credit facility are secured by mortgages
covering substantially all of our producing oil and gas properties. This
facility had a $45 million borrowing base on December 31, 2003 with $30 million
outstanding against it. As of February 29, 2004, $20 million in loans were
outstanding under the facility. The borrowing base is currently being reviewed
by the lenders and could be increased due to our proved producing reserves
increasing as a result of the Medusa and Habanero fields commencing production
late in the fourth quarter of 2003. The facility expires on June 30, 2004 and we
are currently reviewing options to extend the maturity date or to replace the
facility with one that is similar or with more favorable terms. See Note 5 of
our Consolidated Financial Statements for a more detailed description of the
credit facility.
Outstanding debt on December 31, 2003 was $308.1 million, and after retirement
of the 2004 notes using restricted cash on January 8, 2004, debt was $245.2
million, compared to $249.6 million on December 31, 2002. The senior secured
credit facility, our two senior unsecured credit facilities and the indenture
for our senior subordinated debt contain various covenants including
restrictions on additional indebtedness and payment of cash dividends as well as
maintenance of certain financial ratios. We were in compliance with these
covenants at December 31, 2003.
Capital expenditure plans for 2004 include:
- the completion of the development projects for Medusa and Habanero;
- the drilling of a satellite prospect in the Medusa field;
- the drilling and completion of a proved undeveloped location in the
Mobile Blocks 952/953/955 field;
- the acquisition of seismic and leases; and
35
- discretionary capital projects for the exploratory drilling of deep
shelf prospects we developed through our 3-D seismic partnership
using AVO technology.
We anticipate that cash flow generated during 2004 and current availability
under our senior secured credit facility, if necessary, will provide the $65
million, which includes capitalized interest and general and administrative
expenses, of capital necessary to fund these planned capital expenditures and
the current portion of our asset retirement obligation in the amount of $8.6
million.
The following table describes our outstanding contractual obligations (in
thousands) as of December 31, 2003:
CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE
OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS
----------- ------- --------- --------- --------- ----------
Senior Secured Revolving Credit Facility $30,000 $30,000(b) $ -- $ -- $ --
10.125% Senior Subordinated Notes 22,915 22,915(a) -- -- --
10.25% Senior Subordinated Notes 40,000 40,000(a) -- -- --
12% Senior Loans 10,000 -- 10,000 -- --
9.75% Senior Unsecured Credit Facility 185,000 -- -- -- 185,000
11% Senior Subordinated Notes 33,000 -- 33,000 -- --
Capital lease (future minimum payments) 4,421 1,890 1,261 577 693
Throughput Commitments:
Medusa Spar 23,128 5,628 8,660 5,532 3,308
Medusa Oil Pipeline 1,129 269 460 186 214
(a) These notes were retired with restricted cash on January 8, 2004.
(b) This facility matures June 30, 2004 and is expected to be extended or
replaced with a new facility.
36
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect to our
oil and gas operations for each of the three years in the period ended December
31, 2003.
DECEMBER 31,
---------------------------------
2003(A) 2002(A)(B) 2001(A)(B)
------- ---------- ----------
Production:
Oil (MBbls) 268 226 273
Gas (MMcf) 12,315 14,215 13,566
Total production (MMcfe) 13,923 15,571 15,206
Average daily production (MMcfe) 38.1 42.7 41.7
Average sales price:
Oil (per Bbl) $ 28.72 $ 23.11 $ 22.95
Gas (per Mcf) $ 5.36 $ 3.94 $ 3.96
Total (per Mcfe) $ 5.29 $ 3.93 $ 3.95
Oil and Gas revenues:
Gas revenue $66,001 $55,949 $53,729
Oil revenue 7,696 5,222 6,281
------- ------- -------
Total $73,697 $61,171 $60,010
======= ======= =======
Oil and gas production costs:
Lease operating expenses $11,301 $11,030 $11,252
Additional per Mcfe data:
Sale price $ 5.29 $ 3.93 $ 3.95
Lease operating expenses .81 .71 .73
------- ------- -------
Operating margin $ 4.48 $ 3.22 $ 3.22
======= ======= =======
Depletion $ 2.03 $ 1.73 $ 1.37
Accretion $ .21 $ -- $ --
General and administrative (net of management fees) $ .34 $ .30 $ .30
(a) Average sales price includes hedging gains and losses.
(b) Production volumes include 1,200 MMcf for the year 2002 and 2,300 MMcf for
2001, at an average price of $2.08 per Mcf associated with a volumetric
production payment.
37
OFF-BALANCE SHEET ARRANGEMENTS
In December 2003, we announced the formation of a limited liability company,
Medusa Spar LLC, which now owns a 75% undivided ownership interest in the
deepwater spar production facilities on our Medusa Field in the Gulf of Mexico.
We contributed a 15% undivided ownership interest in the production facility to
Medusa Spar LLC in return for approximately $25 million in cash and a 10%
ownership interest in the LLC. The LLC will earn a tariff based upon production
volume throughput from the Medusa area. We are obligated to process our share of
production from the Medusa field and any future discoveries in the area through
the spar production facilities. This arrangement allows us to defer the cost of
the Spar production facility over the life of the Medusa field. Our cash
proceeds were used to reduce the balance outstanding under our senior secured
credit facility. The LLC used the cash proceeds from $83.7 of non-recourse
financing and a cash contribution by one of the LLC owners to acquire its 75%
interest in the spar. The balance of Medusa Spar LLC is owned by Oceaneering
International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are
accounting for our 10% ownership interest in the LLC under the equity method.
SEC INQUIRIES REGARDING RESERVE INFORMATION
Beginning in October 2002 we received a series of inquiries from the SEC
regarding our Annual Report on Form 10-K for the year ended December 31, 2001
requesting supplemental information concerning our operations in the Gulf of
Mexico. The comment letters requested information about the procedures we used
to classify our deepwater reserves as proved and requested that our financials
be restated to reflect the removal of the Boomslang reserves as proved for all
prior periods during which such reserves were reported as proved. We have
reviewed the SEC comments with our independent petroleum reserve engineers,
Huddleston & Co., Inc., of Houston, Texas. Both Huddleston & Co. and we believe
that such deepwater reserves are properly classified as proved. The Company has
responded to all of the SEC inquiries.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2003 AND
2002
OIL AND GAS REVENUES
Total oil and gas revenues increased 20% from $61.2 million in 2002 to $73.7 in
2003 while total production for 2003 decreased by 11% versus 2002. Realized oil
and gas prices were substantially higher when compared to the same period in
2002 and accounted for the increase in revenue. Gas revenues for 2002 included
$9.2 million of non-cash revenue related to the Enron derivatives discussed in
Note 6 to the Consolidated Financial Statements.
Gas production during 2003 totaled 12.3 Bcf and generated $66.0 million in
revenues compared to 14.2 Bcf and $55.9 million in revenues during the same
period in 2002. Average gas prices for 2003 were $5.36 per Mcf compared to $3.94
per Mcf during the same period last year. The decrease in production was
primarily due to the depletion of the lowest productive zone of the East Cameron
Block 294 field. The well at East Cameron Block 294 was returned to production
after a recompletion to a behind pipe zone in the third quarter of 2003. Also,
the sale of the North and Northwest Dauphin Island fields in the fourth quarter
of 2002 and the normal and expected declines in production from other properties
contributed to the variance.
Oil production during 2003 totaled 268,000 barrels and generated $7.7 million in
revenues compared to 226,000 barrels and $5.2 million in revenues for the same
period in 2002. Average oil prices received in
38
2003 were $28.72 per barrel compared to $23.11 per barrel in 2002. The increase
in production was due to the initial production from our deepwater discoveries,
Medusa and Habanero, which began producing late in the fourth quarter of 2003.
This was offset slightly by downtime for maintenance to the facility and
equipment at the Big Escambia Creek Field operated by ExxonMobil Corporation and
normal and expected declines in production from older properties.
LEASE OPERATING EXPENSES
Lease operating expenses for 2003 increased by 2% to $11.3 million compared to
$11.0 million for the same period in 2002. The increase was primarily due to the
increase in lease operating expenses for the Mobile Block 864 area resulting
from the implementation of the accelerated production program in the second
quarter of 2002 and lease operating expenses related to our deepwater
discoveries, Medusa and Habanero, which began producing late in the fourth
quarter of 2003. The increase was slightly offset as a result of the sale of
North and Northwest Dauphin Island fields in the fourth quarter of 2002 which
reduced lease operating expenses for 2003.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization for 2003 and 2002 were $28.3 million
and $27.1 million, respectively. The 4% increase was due primarily to the
downward reserve revisions for our Boomslang field at Ewing Bank Block 994 at
the end of 2002. This decrease in estimated proved reserves increased the
depletable cost per unit of production.
ACCRETION EXPENSE
Accretion expense of $2.9 million represents accretion for our asset retirement
obligations for 2003.
GENERAL AND ADMINISTRATIVE
General and administrative expenses for 2003, net of amounts capitalized, were
$4.7 million and flat with the amount incurred in 2002.
INTEREST EXPENSE
Interest expense increased by 17% in 2003 to $30.6 million compared to $26.1
million in 2002. This was a result of higher debt levels.
LOSS ON EARLY EXTINGUISHMENT OF DEBT
A loss of $5.6 million was incurred in December of 2003 for the write-off of
deferred financing costs and bond discounts associated with the early
extinguishment of $85 million of the 12% loans due in 2005 plus a 1% pre-payment
premium.
INCOME TAXES
The income tax expense of $8.4 million in 2003 was primarily due to a charge of
$11.5 million to establish a valuation allowance against our deferred tax asset
required by SFAS 109 "Accounting for Income Taxes". This charge was taken due to
the negative evidence resulting from the cumulative losses incurred for the
three year period ending December 31, 2003. Relevant accounting guidance
suggests that positive future expectations about income are diminished by such
losses. If the Company achieves
39
profitable operations in 2004, the Company expects it will reverse a portion of
the valuation allowance in an amount at least sufficient to eliminate any tax
provision in that period. See Note 3 to the Company's Consolidated Financial
Statements for a more detailed discussion.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002 AND
2001
OIL AND GAS REVENUES
Oil and gas revenues for 2002 were $61.2 million, a 2% increase from the 2001
amount of $60.0 million. Oil and gas production of 15,571 MMcfe during 2002
increased as well from the 2001 amount of 15,206 MMcfe.
Oil production decreased from 273,000 barrels in 2001 to 226,000 barrels in 2002
but the average sales price increased from $22.95 in 2001 to $23.11 in 2002. As
a result, oil revenues dropped from $6.3 million in 2001 to $5.2 million in
2002. The production decrease was primarily due to older properties' normal and
expected decline in production.
Gas revenues for 2002 were $55.9 million based on sales of 14.2 Bcf at an
average sales price of $3.94 per Mcf. For 2001, gas revenues were $53.7 million
based on production of 13.6 Bcf sold at an average sales price of $3.96 per Mcf.
Our gas production in 2002 increased when compared to last year due primarily to
the acceleration program at Mobile Blocks 952/953/955 area initiated in the
fourth quarter of 2001.
LEASE OPERATING EXPENSES
Lease operating expenses remained relatively stable at $11.0 million ($.71 per
Mcfe) in 2002 compared to $11.3 million ($.73 per Mcfe) in 2001.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased by 28% due in large part to
the downward reserve revisions at Boomslang. This decrease in estimated proved
reserves, over which depletable costs are amortized, increased the per unit
depletion rate, while production remained relatively constant between years.
Total charges increased from $21.1 million or $1.39 per Mcfe in 2001, to $27.1
million, or $1.74 per Mcfe in 2002.
GENERAL AND ADMINISTRATIVE
General and administrative expenses for 2002 were $4.7 million, or $.30 per
Mcfe, compared to $4.6 million, or $.30 per Mcfe, in 2001.
INTEREST EXPENSE
Interest expense for 2002 was $26.1 million increasing from $12.8 million in
2001. This is a result of an increase in our long-term debt as well as higher
interest rates associated with additional debt incurred in 2002.
40
INCOME TAXES
Our 2002 results included a deferred income tax benefit of $900,000. We
evaluated the deferred income tax asset in light of our reserve quantity
estimates, our long-term outlook for oil and gas prices and our expected level
of future revenues and expenses. We believe it is more likely than not, based
upon this evaluation, that we will realize the recorded deferred income tax
asset. However, there is no assurance that such asset will ultimately be
realized.
41
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. In recent months, the prices for oil and gas have increased;
however, they remain extremely volatile and sometimes experience large
fluctuations as a result of relatively small changes in supplies, weather
conditions, economic conditions and government actions. The Company enters into
derivative financial instruments to hedge oil and gas price risks for the
production volumes to which the hedge relates. The derivatives reduce the
Company's exposure on the hedged volumes to decreases in commodity prices and
limit the benefit the Company might otherwise have received from any increases
in commodity prices on the hedged volumes.
The Company also enters into price "collars" to reduce the risk of changes in
oil and gas prices. Under these arrangements, no payments are due by either
party so long as the market price is above the floor price set in the collar and
below the ceiling. If the price falls below the floor, the counter-party to the
collar pays the difference to the Company and if the price is above the ceiling,
the counter-party receives the difference from the Company. The Company enters
into these various agreements to reduce the effects of volatile oil and gas
prices and does not enter into hedge transactions for speculative purposes. See
Note 6 to the Consolidated Financial Statements for a description of the
Company's hedged position at December 31, 2003. There have been no significant
changes in market risks faced by the Company since the end of 2003.
Based on projected annual sales volumes for 2004 (excluding forecast production
increases over 2003), a 10% decline in the prices we receive for our crude oil
and natural gas production would have an approximate $13.7 million impact on our
revenues.
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
---------
Report of Independent Auditors 44 and 45
Consolidated Balance Sheets as of December 31, 2003 46
and 2002
Consolidated Statements of Operations for Each of the Three Years
in the Period Ended December 31, 2003 47
Consolidated Statements of Stockholders' Equity
for Each of the Three Years in the Period Ended December 31, 2003 48
Consolidated Statements of Cash Flows for Each of the Three Years
in the Period Ended December 31, 2003 49
Notes to Consolidated Financial Statements 50
43
REPORT OF INDEPENDENT AUDITORS
The Stockholders and Board of Directors
Callon Petroleum Company
We have audited the accompanying consolidated balance sheets of Callon
Petroleum Company as of December 31, 2003 and 2002, and the related consolidated
statements of operations, stockholders' equity and cash flows for the two years
in the period ended December 31, 2003. 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. The financial
statements of Callon Petroleum Company as of December 31, 2001 and for the year
then ended, were audited by other auditors who have ceased operations and whose
report dated March 29, 2002, expressed an unqualified opinion on those
statements and included an explanatory paragraph that disclosed the change in
the Company's method of accounting for derivative instruments and hedging
activities discussed in Note 2 to those financial statements.
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 consolidated financial position of Callon
Petroleum Company as of December 31, 2003 and 2002, and the results of its
operations and its cash flows for the two years in the period ended December 31,
2003, in conformity with accounting principles generally accepted in the United
States.
As discussed in Note 1 to the financial statements, effective January 1,
2003, the Company adopted Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations".
ERNST & YOUNG LLP
New Orleans, Louisiana
March 3, 2004
44
The following report is a copy of the audit report previously issued by Arthur
Andersen LLP in connection with Callon Petroleum Company's annual report on Form
10-K for the year ended December 31, 2001. This audit report has not been
reissued by Arthur Andersen LLP in connection with this filing on form 10-K for
the year ended December 31, 2003. The consolidated balance sheet as of December
31, 2000 and the consolidated statements of operations, stockholders' equity and
cash flows for the year ended December 31, 2000, mentioned in the report, are
not required in the Company's annual report for 2003 and are therefore not
presented among the financial statements in this annual report.
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors of Callon Petroleum Company:
We have audited the accompanying consolidated balance sheets of Callon
Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Callon Petroleum Company and
subsidiaries, as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 2 to the consolidated financial statements effective
January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities."
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
MARCH 29, 2002
45
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
---------------------
2003 2002
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents $ 8,700 $ 5,807
Restricted cash 63,345 --
Accounts receivable 10,117 10,875
Other current assets 3,606 570
--------- ---------
Total current assets 85,768 17,252
--------- ---------
Oil and gas properties, full-cost accounting method:
Evaluated properties 802,912 762,918
Less accumulated depreciation, depletion and amortization (447,000) (426,254)
--------- ---------
355,912 336,664
Unevaluated properties excluded from amortization 34,251 40,997
--------- ---------
Total oil and gas properties 390,163 377,661
--------- ---------
Pipeline and other facilities, net -- 853
Other property and equipment, net 1,547 1,890
Deferred tax asset -- 8,767
Long-term gas balancing receivable 1,101 761
Restricted investments 7,420 --
Investment in Medusa Spar LLC 8,471 --
Other assets, net 1,562 3,429
--------- ---------
Total assets $ 496,032 $ 410,613
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 16,020 $ 12,498
Undistributed oil and gas revenues 897 1,109
Accrued net profits interest payable 1,886 1,707
Asset retirement obligations, current portion 8,571 --
Current maturities of long-term debt 93,223 1,320
--------- ---------
Total current liabilities 120,597 16,634
--------- ---------
Long-term debt-excluding current maturities 214,885 248,269
Accounts payable and accrued liabilities to be refinanced -- 3,861
Asset retirement obligations 25,120 --
Accrued retirement benefits 189 204
Other long-term liabilities 1,980 685
--------- ---------
Total liabilities 362,771 269,653
--------- ---------
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, 2003
with a liquidation preference of $15,021,525 6 6
Common Stock, $.01 par value; 20,000,000 shares
authorized; 13,935,311 shares and 13,900,466 shares
outstanding at December 31, 2003 and 2002, respectively 139 139
Capital in excess of par value 169,036 158,370
Unearned restricted stock compensation (372) (826)
Accumulated other comprehensive income (loss) (20) (469)
Retained earnings (deficit) (35,528) (16,260)
--------- ---------
Total stockholders' equity 133,261 140,960
--------- ---------
Total liabilities and stockholders' equity $ 496,032 $ 410,613
========= =========
The accompanying notes are an integral part of these financial statements.
46
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2003 2002 2001
-------- -------- --------
Operating revenues:
Oil and gas sales $ 73,697 $ 61,171 $ 60,010
-------- -------- --------
Operating expenses:
Lease operating expenses 11,301 11,030 11,252
Depreciation, depletion and amortization 28,253 27,096 21,081
General and administrative 4,713 4,705 4,635
Accretion expense 2,884 -- --
Loss on mark-to-market commodity derivative contracts 535 708 --
-------- -------- --------
Total operating expenses 47,686 43,539 36,968
-------- -------- --------
Income from operations 26,011 17,632 23,042
-------- -------- --------
Other (income) expenses:
Interest expense 30,614 26,140 12,805
Other income (444) (1,004) (1,742)
Loss on early extinguishment of debt 5,573 -- --
Gain on sale of pipeline -- (2,454) --
Gain on sale of Enron derivatives -- (2,479) --
Writedown of Enron derivatives -- -- 9,186
-------- -------- --------
Total other (income) expenses 35,743 20,203 20,249
-------- -------- --------
Income (loss) before income taxes (9,732) (2,571) 2,793
Income tax expense (benefit) 8,432 (900) 977
-------- -------- --------
Net income (loss) before Medusa Spar LLC and cumulative
effect of change in accounting principle (18,164) (1,671) 1,816
Loss from Medusa Spar LLC, net of tax (8) -- --
-------- -------- --------
Income (loss) before cumulative effect of change in
accounting principle (18,172) (1,671) 1,816
Cumulative effect of change in accounting principle, net of tax 181 -- --
-------- -------- --------
Net income (loss) (17,991) (1,671) 1,816
Preferred stock dividends 1,277 1,277 1,277
-------- -------- --------
Net income (loss) available to common shares $(19,268) $ (2,948) $ 539
======== ======== ========
Net income (loss) per common share:
Basic
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (1.42) $ (0.22) $ .04
Cumulative effect of change in accounting principle, net of tax 0.01 -- --
-------- -------- --------
Net income (loss) available to common $ (1.41) $ (0.22) $ .04
======== ======== ========
Diluted
Net income (loss) available to common before cumulative
effect of change in accounting principle $ (1.42) $ (0.22) $ .04
Cumulative effect of change in accounting principle, net of tax 0.01 -- --
-------- -------- --------
Net income (loss) available to common $ (1.41) $ (0.22) $ .04
======== ======== ========
Shares used in computing net income (loss):
Basic 13,662 13,387 13,273
======== ======== ========
Diluted 13,662 13,387 13,366
======== ======== ========
The accompanying notes are an integral part of these financial statements.
47
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
Unearned Accumulated Total
Restricted Capital in Other Retained Stock-
Preferred Common Stock Excess of Comprehensive Earnings holders'
Stock Stock Compensation Par Value Income (Loss) (Deficit) Equity
--------- ------ ------------ ---------- ------------- ------------- ---------
Balances, December 31, 2000 $ 6 $133 $ -- $ 150,040 $ -- $ (13,851) $136,328
-------- ---- ----- --------- ------- --------- --------
Comprehensive income:
Net income -- -- -- -- -- 1,816
Other comprehensive income -- -- -- -- 5,971 --
--------
Total comprehensive income 7,787
Preferred stock dividend -- -- -- -- -- (1,277) (1,277)
Shares issued pursuant to employee
benefit and option plan -- 1 -- 942 -- -- 943
Employee stock purchase plan -- -- -- 357 -- -- 357
Tax benefits related to stock
compensation plans -- -- -- 18 -- -- 18
Warrants -- -- -- 3,068 -- -- 3,068
-------- ---- ----- --------- ------- --------- --------
Balances, December 31, 2001 6 134 -- 154,425 5,971 (13,312) 147,224
-------- ---- ----- --------- ------- --------- --------
Comprehensive income:
Net loss -- -- -- -- -- (1,671)
Other comprehensive loss -- -- -- -- (6,440) --
--------
Total comprehensive loss (8,111)
Preferred stock dividends -- -- -- -- -- (1,277) (1,277)
Shares issued pursuant to employee
benefit and option plan -- 1 -- 770 -- -- 771
Employee stock purchase plan -- -- -- 79 -- -- 79
Tax benefits related to stock
compensation plans -- -- -- (29) -- -- (29)
Restricted stock -- 3 (826) 1,849 -- -- 1,026
Warrants -- 1 -- 1,276 -- -- 1,277
-------- ---- ----- --------- ------- --------- --------
Balances, December 31, 2002 6 139 (826) 158,370 (469) (16,260) 140,960
-------- ---- ----- --------- ------- --------- --------
Comprehensive income:
Net loss -- -- -- -- -- (17,991)
Other comprehensive income -- -- -- -- 449 --
--------
Total comprehensive loss (17,542)
Preferred stock dividends -- -- -- -- -- (1,277) (1,277)
Shares issued pursuant to employee
benefit and option plan -- 1 -- 427 -- -- 428
Employee stock purchase plan -- -- -- 127 -- -- 127
Restricted stock -- (1) 454 (516) -- -- (63)
Warrants -- -- -- 10,628 -- -- 10,628
-------- ---- ----- --------- ------- --------- --------
Balances, December 31, 2003 $ 6 $139 $(372) $ 169,036 $ (20) $ (35,528) $133,261
======== ==== ===== ========= ======= ========= ========
The accompanying notes are an integral part of these financial statements.
48
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(IN THOUSANDS)
2003 2002 2001
--------- -------- --------
Cash flows from operating activities:
Net income (loss) $ (17,991) $ (1,671) $ 1,816
Adjustments to reconcile net income (loss) to
cash provided by operating activities:
Depreciation, depletion and amortization 29,264 27,774 21,709
Accretion expense 2,884 -- --
Amortization of deferred costs 6,568 5,521 2,485
Non-cash loss on early extinguishment of debt 4,423
Amortization of deferred production payment revenue -- (2,406) (4,830)
Cumulative effect of change in accounting principle (181) -- --
Non-cash derivative income -- (9,186) --
Non-cash mark-to-market commodity derivative contracts 487 708 --
Non-cash charge related to compensation plans 858 1,267 942
Deferred income tax expense (benefit) 8,432 (900) 977
Gain on sale of pipeline -- (2,454) --
Writedown of Enron derivatives -- -- 9,186
Changes in current assets and liabilities:
Accounts receivable, trade (1,438) (4,967) 3,336
Advance to operators (1,501) (98) 1,131
Other current assets (1,166) (6) (2)
Current liabilities 5,185 3,198 (8,782)
Investment in derivative contracts -- (1,687) --
Increase in accounts payable and accrued liabilities
to be refinanced -- -- 9,558
Change in gas balancing receivable (340) (288) 170
Change in gas balancing payable (491) (390) 355
Change in other long-term liabilities (15) 67 (1,749)
Change in other assets, net (349) (2,315) (1,071)
--------- -------- --------
Cash provided (used) by operating activities 34,629 12,167 35,231
--------- -------- --------
Cash flows from investing activities:
Capital expenditures (50,705) (66,023) (113,833)
Sale of Medusa Spar to Medusa Spar, LLC 24,908 -- --
Proceeds from sale of pipeline and other facilities 1,500 6,784 --
Cash proceeds from sale of mineral interests 982 4,492 1,195
--------- -------- --------
Cash provided (used) by operating activities (23,315) (54,747) (112,638)
--------- -------- --------
Cash flows from financing activities:
Change in accounts payable and accrued liability to be refinanced (3,861) (5,697) --
Increase in debt 198,000 109,900 155,000
Payment on debt (133,000) (58,085) (84,900)
Restricted cash (63,345) -- --
Debt issuance costs (3,745) (2,291) (2,374)
Equity issued related to employee stock plans 127 79 357
Capital lease (1,320) (1,129) 5,612
Cash dividends on preferred stock (1,277) (1,277) (1,277)
--------- -------- --------
Cash provided (used) by financing activities (8,421) 41,500 72,418
--------- -------- --------
Net increase (decrease) in cash and cash equivalents 2,893 (1,080) (4,989)
Cash and cash equivalents:
Balance, beginning of period 5,807 6,887 11,876
--------- -------- --------
Balance, end of period $ 8,700 $ 5,807 $ 6,887
========= ======== ========
The accompanying notes are an integral part of these financial statements.
49
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
GENERAL
Callon Petroleum Company ("the Company" or "Callon") 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 ("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 ("FASB") issued Statement
of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for
Derivative Instruments and Hedging Activities. The Statement establishes
accounting and reporting standards requiring that every derivative instrument,
including certain derivative instruments embedded in other contracts, be
recorded in the balance sheet as either an asset or liability measured at its
fair value. The Company adopted SFAS 133 effective January 1, 2001. The
cumulative effect of the accounting change, net of tax, recorded as other
comprehensive loss was $3.8 million.
50
SFAS 133 requires the Company to report changes in the fair value of its
derivative financial instruments that qualify as cash flow hedges in other
comprehensive income, a component of stockholders' equity, until realized. See
Note 6 for a discussion of the Company's derivative financial instruments.
In June 2001, the FASB issued Statement of Financial Accounting Standards No.
143, Accounting for Asset Retirement Obligations ("SFAS 143") effective for
fiscal years beginning after June 15, 2002. SFAS 143 essentially requires
entities to record the fair value of a liability for obligations associated with
the retirement of tangible long-lived assets and the associated asset retirement
costs. Callon adopted the statement on January 1, 2003 resulting in a cumulative
effect of accounting change of $181,000, net of tax. See Note 8.
In December 2002, the FASB issued Statement of Financial Accounting Standards
No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and
Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123, "Accounting
for Stock-Based Compensation", to provide alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, this statement amends the disclosure
requirements of SFAS 123 to require disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on the reported results. SFAS 148
was effective for the year ended December 31, 2002 and for interim financial
statements commencing in 2003. The adoption of this pronouncement by the Company
did not have an impact on its financial condition or results of operations. See
Stock-Based Compensation for related disclosures.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
(ARB) 51" ("FIN 46"). FIN 46 addresses consolidation by business enterprises of
variable interest entities ("VIEs"). The primary objective of FIN 46 is to
provide guidance on the identification of, and financial reporting for, entities
over which control is achieved through means other than voting rights; such
entities are known as VIEs. The provisions of FIN 46 are effective immediately
for these variable interest entities created after January 31, 2003. On December
24, 2003, the FASB issued a revision to FIN 46 which among other things deferred
the effective date for certain variable interests created prior to January 31,
2003. Application is required for interests in special-purpose entities in the
periods ending after December 15, 2003 and application is required for all other
types of variable interest entities in the periods ending after March 31, 2004.
The Company adopted FIN 46, as revised, as of December 31, 2003, which had no
impact on the financial statements.
In June 2001, the FASB issued Statement of Financial Accounting Standards No.
141 ("SFAS 141"), "Business Combinations," which requires the use of the
purchase method of accounting for business combinations initiated after June 30,
2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also
issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"),
"Goodwill and Other Intangible Assets," which discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and initiates an
annual review of impairment. The new standard also requires that all intangible
assets be aggregated and presented as a separate line item in the balance sheet.
The adoption of SFAS No. 141 and 142 had no impact on the Company's financial
position or results of operations. A reporting issue has arisen regarding the
application of certain provisions of SFAS No. 141 and 142 to companies in the
oil and gas industry. The issue is whether SFAS No. 141 requires registrants to
classify the costs of mineral rights associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide specific footnote disclosures. Historically, the
Company has included the costs of mineral rights associated with extracting oil
and gas as
51
a component of oil and gas properties. These costs include those to acquire
contract based drilling and mineral use rights such as delay rentals, lease
bonuses, commissions and brokerage fees, and other leasehold costs.
The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas
mineral rights to an upcoming agenda, which may result in a change in the
classification of these amounts, as described above. The Company will continue
to classify its oil and gas leasehold costs as tangible oil and gas properties
until further guidance is provided. The Company's cash flows and results of
operations would not be affected since such intangible assets would continue to
be depleted and assessed for impairment in accordance with full cost accounting
rules, as allowed by SFAS No. 142. Further, the Company believes that the
amounts that would be classified as intangible assets as of December 31, 2003
and 2002 would be immaterial.
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. See Note 3.
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 ($13.2 million in
2003, $9.6 million in 2002 and $10.0 million in 2001) do not include any costs
related to production or general corporate overhead. Costs associated with
unevaluated properties, including capitalized interest on such costs, 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 that 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 accumulated amortization and deferred
taxes relating to oil and gas properties, 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 9.
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 available geological, engineering and regulatory data. 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
52
or discovery. Until January 1, 2003, such costs were capitalized as oil and gas
properties as the actual restoration, dismantlement and abandonment activities
took place. As discussed above under Accounting Pronouncements, beginning
January 1, 2003, the Company changed the method for which we account for such
costs upon adoption of SFAS 143 and these costs are included in the full cost
pool. For purposes of the full cost ceiling test, the Company nets the Asset
Retirement Obligation liability against the net capitalized costs of oil and gas
properties and includes cash outflows associated with asset retirement
obligations in the calculation of the full cost ceiling amount.
Depreciation of other property and equipment is provided using the straight-line
method over estimated lives of three to 20 years. Depreciation of pipeline and
other facilities is provided using the straight-line method over estimated lives
of 15 to 27 years.
SALE OF PRODUCTION PAYMENT INTEREST
In June 1999, the Company acquired a working interest in the Mobile Block 864
Area where the Company already owned an interest. Concurrent with this
acquisition, the seller received a volumetric production payment, valued at
approximately $14.8 million, from production attributable to a portion of the
Company's interest in the area over a 39-month period. The Company recorded a
liability associated with the sale of this production payment interest because a
substantial obligation for future performance existed. Under the terms of the
sale, the Company was obligated to deliver the production volumes free and clear
of royalties, lease operating expenses, production taxes and all capital costs.
The production payment was amortized, beginning in June 1999, to oil and gas
sales on the units-of-production method as associated hydrocarbons were
delivered, and expired in July 2002.
NATURAL GAS IMBALANCES
The Company follows the 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.
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 are accounted for 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 $103,000 and $143,000 at December 31, 2003 and 2002,
respectively. Net charge offs were $40,000 in 2003 and net recoveries were
$75,000 in 2002. There were no provisions to expense in the three-year period
ended December 31, 2003.
ACCOUNTS PAYABLE AND ACCRUED LIABILITIES TO BE REFINANCED
These amounts included in the Consolidated Balance Sheet represent capital
expenditures in accounts payable and accrued liabilities that were refinanced
with the availability under the Company's senior secured credit facility
subsequent to December 31, 2002. Amounts in 2003 were classified as short term
because of the maturity of the Credit Facility on June 30, 2004.
53
STOCK-BASED COMPENSATION
The Company's pro forma net income (loss) and net income (loss) per share of
common stock for the 12-month periods ended December 31, 2003, 2002 and 2001 had
compensation costs been recorded using the fair value method in accordance with
SFAS 123, as amended by SFAS 148 are presented below pursuant to the disclosure
requirements of SFAS 148 (in thousands except per share data):
2003 2002 2001
-------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net income (loss) available to common shares,
as reported $(19,268) $(2,948) $ 539
Stock-based compensation expense included
in net income as reported, net of tax 17 270 397
Deduct: Total stock-based
compensation expense under fair
value based method, net of tax (202) (907) (1,775)
-------- ------- -------
Pro forma net income (loss) available to
common shares $(19,453) $(3,585) $ (839)
======== ======= =======
Basic earnings (loss) per share: As Reported (1.41) (.22) .04
Pro Forma (1.42) (.27) (.06)
Diluted earnings (loss) per share: As Reported (1.41) (.22) .04
Pro Forma (1.42) (.27) (.06)
See Note 11 for descriptions and additional disclosures related to the plans.
MAJOR CUSTOMERS
The Company's production is sold generally on month-to-month contracts at
prevailing prices. The following table identifies customers to whom it sold a
significant percentage of its total oil and gas production during each of the
12-month periods ended:
DECEMBER 31,
------------------
2003 2002 2001
---- ---- ----
Petrocom Energy Group, Ltd. 4% 4% --
Dynegy 5% 7% 8%
Prior Energy Corporation 20% -- 20%
Reliant Energy Services 28% 70% 49%
Louis Dreyfus Energy Services 27% -- --
Because alternative purchasers of oil and gas are readily available, the Company
believes that the loss of any of these purchasers would not result in a material
adverse effect on its 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.
54
The Company paid no federal income taxes for the three years ended December 31,
2003. During the years ended December 31, 2003, 2002 and 2001, the Company made
cash payments for interest of $27,913,000, $25,507,000 and $16,441,000,
respectively.
PER SHARE AMOUNTS
Basic income or loss per common share was computed by dividing net income or
loss by the weighted average number of shares of common stock outstanding during
the year. Diluted income or loss per common share was determined on a weighted
average basis using common shares issued and outstanding adjusted for the effect
of stock options considered common stock equivalents computed using the treasury
stock method and the effect of the convertible preferred stock (if dilutive).
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. In
addition, below are the shares relating to stock options, warrants and
restricted stock that were not included in diluted shares for the twelve-month
periods ended December 31, 2003 and 2002 due to the fact that the Company had a
loss for these periods. The Company had net income for the period ended December
31, 2001 and therefore had no such shares for this period.
TWELVE MONTHS ENDED DECEMBER 31,
--------------------------------
(IN THOUSANDS)
2003 2002
---- ----
Stock options 63 13
Warrants 424 372
Restricted Stock 248 122
A reconciliation of the basic and diluted per share computation is as follows
(in thousands, except per share amounts):
2003 2002 2001
-------- ------- -------
(a) Net income (loss) available to common shares $(19,268) $(2,948) $ 539
Preferred dividends assuming conversion of
preferred stock (if dilutive) -- -- --
-------- ------- -------
(b) Income (loss) available to common shares assum-
ing conversion of preferred stock (if dilutive) $(19,268) $(2,948) $ 539
======== ======= =======
(c) Weighted average shares outstanding 13,662 13,387 13,273
Dilutive impact of stock options -- -- 27
Dilutive impact of restricted stock -- -- --
Dilutive impact of warrants -- -- 66
Convertible preferred stock (if dilutive) -- -- --
-------- ------- -------
(d) Total diluted shares 13,662 13,387 13,366
======== ======= =======
Stock options and warrants excluded due to the
exercise price being greater than the stock price 2,297 2,250 1,438
Basic income (loss) per share (a/c) $ (1.41) $ (.22) $ .04
Diluted income (loss) per share (b/d) $ (1.41) $ (.22) $ .04
55
FAIR VALUE OF FINANCIAL INSTRUMENTS
Fair value of cash, cash equivalents, accounts receivable, accounts payable, the
capital lease and the senior secured credit facility approximates book value at
December 31, 2003 and 2002. Fair value of long-term debt (specifically, the
10.125%, the 10.25%, the 11% Senior Subordinated Notes and the 12% loans) have
an estimated fair value of 100% of face value at December 31, 2003.
3. INCOME TAXES
The Company has recorded a deferred tax asset at December 31, 2003 and 2002 and
a valuation allowance at December 31, 2003 as follows:
DECEMBER 31,
---------------------
2003 2002
-------- --------
(IN THOUSANDS)
Federal net operating loss carryforwards $ 61,805 $ 42,464
Statutory depletion carryforward 4,255 4,251
Temporary differences:
Oil and gas properties (66,725) (39,159)
Pipeline and other facilities -- (299)
Non-oil and gas property (16) (30)
Other 1,620 1,540
SFAS 143-Asset Retirement Obligations 10,563 --
-------- --------
Total tax asset 11,502 8,767
Valuation allowance (11,502) --
-------- --------
Net tax asset $ -- $ 8,767
======== ========
SFAS 109 provides for the weighing of positive and negative evidence in
determining whether it is more likely than not that a deferred tax asset is
recoverable. The Company has incurred losses in 2002 and 2003 and has losses on
an aggregate basis for the three-year period ended December 31, 2003. However,
as discussed in Note 5, in December 2003 the Company refinanced nearly all its
highest cost debt, incurring an early extinguishment loss of $5.6 million, but
achieving significant interest savings in the future. In addition, as discussed
in Note 5, the first two of the Company's deepwater projects began production in
November 2003, which is expected to result in a significant increase in 2004
production as compared to 2003. Nevertheless, relevant accounting guidance
suggests that a recent history of cumulative losses constitutes significant
negative evidence, and that future expectations about income are overshadowed by
such recent losses. As a result, the Company established a valuation allowance
of $11.5 million as of December 31, 2003. If the Company achieves profitable
operations in 2004, the Company expects it will reverse a portion of the
valuation allowance in an amount at least sufficient to eliminate any tax
provision in that period.
56
Below is a reconciliation of the reported amount of income tax expense
attributable to continuing operations for the year to the amount of income tax
expense that would result from applying domestic federal statutory tax rates to
pretax income from continuing operations.
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2000
---- ---- ----
Income tax expense (benefit) computed at the statutory
federal income tax rate (35%) (35%) 35%
Change in valuation allowance 118% -- --
Write off of NOL's 4% -- --
---- ---- ----
Effective income tax rate 87% (35%) 35%
==== ==== ====
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.
4. OTHER COMPREHENSIVE INCOME
A recap of the Company's 2003, 2002 and 2001 comprehensive income (net of tax)
is shown below (in thousands):
YEARS ENDED DECEMBER 31,
------------------------------
2003 2002 2001
-------- -------- --------
Other comprehensive income (loss):
Cumulative effect of change in
accounting principle $ -- $ -- $ (3,764)
Change in derivatives fair value 449 (469) 9,735
Amortization of Enron derivatives -- (5,971) --
-------- -------- --------
Total other comprehensive income (loss) $ 449 $ (6,440) $ 5,971
======== ======== ========
57
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
DECEMBER 31,
2003 2002
--------- ---------
(IN THOUSANDS)
Senior Secured Credit Facility $ 30,000* $ 65,000
Senior Subordinated Notes (due 2004) - these notes were
retired with restricted cash on 01/08/2004:
10.125% notes net of discount 21,772* 20,086
10.250% notes 40,000* 40,000
12% Senior Loans (due 2005) net of discount 9,490 87,020
11% Senior Subordinated Notes (due 2005) 33,000 33,000
9.75% Senior Loans (due 2010) net of discount 170,684 --
Capital Lease 3,162 4,483
--------- ---------
Total Long-term Debt 308,108* 249,589
Less current portion 93,223* 1,320
--------- ---------
Long-term portion $214,885 $248,269
========= =========
* $62.9 million of 2004 senior subordinated notes are in this
current portion and were retired on January 8, 2004. Total Long-term
Debt after retirement of the 2004 notes was $245.2 million. The
senior secured credit facility comprises $30 million of the current
portion. It is expected that the maturity date of the facility will
be renegotiated and extended or the facility will be replaced.
SENIOR SECURED CREDIT FACILITY. The Company negotiated its senior secured credit
facility effective October 31, 2000 with Wachovia Bank, National Association,
formerly First Union National Bank. Borrowings under the senior secured credit
facility are secured by mortgages covering substantially all of the Company's
producing oil and gas properties. On June 30, 2002 the Company amended the
senior secured credit facility to increase availability under the revolving
borrowing base from $50 million to $75 million under a dual tranche loan. The
Tranche A revolver bears interest at 0.25% to 0.75% above a defined base rate
depending on utilization of the borrowing base or, at the option of the Company,
LIBOR plus 2% to 2.5% based on utilization of the borrowing base and has a
maximum aggregate credit amount of $45 million until Tranche B is retired. The
range of interest rates on the Tranche A revolver was 3.12% to 5.00% for the 12
months ended December 31, 2003. The Tranche B part of the facility bears an
interest rate of 15% and has an aggregate maximum credit amount of $30 million.
The weighted average interest rate for the senior secured credit facility debt
outstanding at December 31, 2003 and 2002 was 15% and 9%, respectively. Under
the senior secured 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.
There were no borrowings outstanding on Tranche A and there was $30 million
outstanding against Tranche B at December 31, 2003. On December 21, 2003, the
Company exercised its right to call the Tranche B loan with a 30-day notice and
on January 21, 2004, the Company drew $27 million under Tranche A and redeemed
the Tranche B principal plus a 1% call premium. Repayment of Tranche B cancelled
any future credit amounts available under Tranche B. Currently, the facility
provides for a $45.0 million borrowing base under Tranche A which is adjusted
periodically on the basis of the discounted present value of future net cash
flows attributable to our proved producing oil and gas reserves
58
and other factors deemed relevant by the lenders. The borrowing base for Tranche
A is currently being reviewed by the lenders and could be increased due to the
Company's proved producing reserves increasing as a result of the Medusa and
Habanero fields commencing production in the fourth quarter of 2003. This
facility expires on June 30, 2004 and the Company is currently reviewing options
to extend the maturity date or to replace the facility with one that is similar
or with more favorable terms. Borrowings under the credit facility are
classified as current at December 31, 2003.
SENIOR SUBORDINATED NOTES (DUE 2004). Covenant defeasance was exercised under
the indentures for the 10.125% and 10.25% notes on December 8, 2003 and a
required 30-day redemption notice was distributed to holders. The funds
necessary to redeem the notes were placed in trust, from the net proceeds of the
new 9.75% loans and the trustee paid the holders of the notes on January 8,
2004. The terms of the covenant defeasance that were exercised did not meet the
requirements for legal defeasance under SFAS 140, "Accounting for Transfers and
Servicing of Financial Instruments and Extinguishment of Debt", and therefore
these notes are considered outstanding at December 31, 2003. The funds in trust
were classified on the Company's December 31, 2003 consolidated balance sheet as
restricted cash.
On September 15, 2002, $36 million of the Company's 10.125% Senior Subordinated
Notes ("Notes") that were issued on July 31, 1997, were due. The holders of
$22.9 million of the Notes consented to an extension of such Notes until July
31, 2004. The Company granted 274,980 warrants (with a fair market value of
approximately $1.3 million) to purchase Common Stock of the Company and paid
consent fees in the amount of $2.3 million to the holders of the Notes that
granted the extensions. These amounts were treated as an additional discount on
the debt. The warrants have a term of five years and an exercise price of $0.01.
The holders of the Notes had exercised approximately 116,000 warrants as of
December 31, 2003. The holders of the Notes that did not consent to the
extension were paid on the maturity date in September 2002. Interest on the
Notes was payable quarterly, on March 15, June 15, September 15, and December 15
of each year.
The Company accounted for the extension of the $22.9 million in Notes described
above as an extinguishment of the Notes and the issuance of new securities were
recorded at a fair value of $19.3 million. The net loss on extinguishment was
not significant. Costs deferred with the extensions were being amortized through
July 2004. As a result of the redemption of the Notes on January 8, 2004, the
unamortized balance of the discount and the deferred costs of $1.1 million will
be expensed during the first quarter of 2004 as a loss on early extinguishment
of debt.
On July 15, 1999, the Company completed the sale of $40 million of Senior
Subordinated Notes due 2004 at 10.25%. These notes were not entitled to any
mandatory sinking fund payments and were subject to redemption at the Company's
option at par plus unpaid interest at any time after March 15, 2001. Interest
was paid quarterly. The notes were redeemed on January 8, 2004. These notes are
classified as current at December 31, 2003.
12% SENIOR UNSECURED CREDIT FACILITY (DUE 2005). In July 2001, the Company
entered into a $95 million senior unsecured credit facility with a private
lender. The Company borrowed $45 million upon closing of the loan and borrowed
the remaining $50 million in December 2001. The loans bear interest at the rate
of 12% per year. Under the terms of the agreement, Callon also issued warrants
to purchase, at a nominal exercise price, 265,210 shares of its Common Stock
(fair value of $3.1 million) and conveyed an overriding royalty interest equal
to 2% of the Company's net interest in four existing deepwater discoveries (fair
value of $5.9 million). These amounts were treated as an additional discount on
the debt. The warrants and the overriding royalty interest were earned by the
lender based on the ratio of the
59
amount of the loan proceeds advanced to the total loan facility amount. The
loans will mature March 31, 2005 and have an effective interest rate of
approximately 16%.
The Company recorded these borrowings at a value of $84 million net of discount.
Deferred costs associated with the loans are being amortized through March 2005.
Upon redemption of $85 million of the loans on December 30, 2003 the pro rata
portion of the unamortized balance of the discount and the associated deferred
costs in the amount of $4.4 million and a 1% call premium of $850,000 were
expensed during the fourth quarter of 2003 as a loss on early extinguishment of
debt.
11% SENIOR SUBORDINATED NOTES (DUE 2005). On October 26, 2000 the Company
completed the sale of $33 million of 11% Senior Subordinated Notes due December
15, 2005. The Company netted $31.5 million from the offering after deducting the
underwriters' discount and offering expenses.
9.75% SENIOR LOANS (DUE 2010). In December 2003 the Company borrowed $185
million pursuant to a senior unsecured credit facility. The loans under the
credit facility have a stated interest rate of 9.75% and a seven-year maturity.
The net proceeds of $181.3 million were used to redeem $22.9 million of 10.125%
senior subordinated notes due July 31, 2004, $40 million of 10.25% senior
subordinated notes due September 15, 2004 and $85 million of our 12% loan due
March 31, 2005 issued pursuant to a senior unsecured credit agreement dated July
29, 2001 plus a 1% pre-payment premium of $850,000, and to reduce the balance
outstanding under the Company's senior secured credit facility. In conjunction
with the new senior unsecured notes, the Company issued detachable warrants to
purchase 2.775 million of our common stock at an exercise price of $10 per
share. The warrants were valued at $10.6 million and were treated as an
additional discount on the debt. This senior unsecured debt matures December 8,
2010 and has an effective interest rate of 11.4%. The Company recorded the
issuance of these new securities at a fair value of $171 million. Deferred costs
of $14 million associated with the notes will be amortized over the life of the
notes.
REMAINING MATURITIES FOR UNSECURED DEBT. Our remaining maturities for unsecured
debt consist of the $185 million in 9.75% loans due 2010, $10 million of the 12%
loans with a due date of March 31, 2005 and $33 million of 11% senior
subordinated notes with a due date of December 15, 2005. These 2005 maturities
will be retired by our primary sources of capital which are cash flows from
operations, borrowings from financial institutions and the sale of debt and
equity securities.
CAPITAL LEASE. In December 2001, the Company entered into a 10-year gas
processing agreement associated with a production facility on Callon's Mobile
Block 952 field with Hanover Compression Limited Partnership, which is being
accounted for as a capital lease. Total minimum obligations are $8.4 million
with interest representing approximately $2.8 million and the present value
minimum obligations were $5.6 million ($1.2 million current).
RESTRICTIVE COVENANTS. The senior secured credit facility, the senior
subordinated debt and the senior unsecured credit facilities contain various
covenants including restrictions on additional indebtedness and payment of cash
dividends as well as maintenance of certain financial ratios. The Company was in
compliance with these covenants at December 31, 2003.
60
FUTURE MINIMUM LEASE PAYMENTS AND DEBT MATURITIES (IN THOUSANDS) ARE AS FOLLOWS:
CAPITAL LEASE
YEAR PAYMENTS DEBT
---- -------- ----
2004 $1,890 $ 92,915*
2005 822 43,000
2006 439 --
2007 348 --
2008 228 --
Thereafter 694 185,000
* These maturities consist of $62.9 million of senior subordinated notes which
were retired on January 8, 2004 and $30 million under the senior secured credit
facility which matures June 30, 2004 and which the Company expects will be
renegotiated and extended or replaced with a new facility.
6. DERIVATIVES
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.
In 2003 and 2002, the Company purchased and sold various put options and call
options and elected not to designate these derivative financial instruments as
hedges and accordingly, the changes in fair value of these contracts were
recorded through earnings. A loss of approximately $666,000 and $708,000 was
recognized for the twelve month periods ended December 31, 2003 and 2002,
respectively. The fair value of the open contracts at December 31, 2003 was a
current liability of $134,640. At December 31, 2002 the fair value was a current
asset of $352,500.
During 2002, the Company entered into costless natural gas collar contracts in
effect for February 2003 through October 2003. These agreements were for volumes
of 275,000 Mcf per month with an average ceiling price of $4.79 and a floor
price of $3.52. These contracts were accounted for as cash flow hedges under
SFAS 133. The fair value of these collar contracts at December 31, 2002 was
recorded on the balance sheet as a liability of $721,350. The Company recognized
a reduction of $2,932,000 in oil and gas sales related to the settlements of
such collars for the 12 months ended December 31, 2003.
During 2003, the Company entered into additional costless natural gas collar
contracts in effect for May 2003 through October 2003. These agreements were for
volumes of 200,000 Mcf per month with a ceiling price of $5.80 and a floor price
of $5.00. The Company elected not to designate these derivative financial
instruments as hedges and accordingly, the changes in fair value of these
contracts were recorded through earnings. For the twelve month period ended
December 31, 2003, the Company recognized a gain of approximately $131,600.
In 2001, the Company entered into derivative contracts for 2002 production with
Enron North America Corp. ("Enron"). In the fourth quarter of 2001, the Company
charged to expense (non-cash) $9.2 million representing the fair market value of
these derivatives as of September 30, 2001. As the contracts matured, the
Company recorded non-cash revenue each month. For the twelve month period ended
December 31, 2002, the Company recorded approximately $9.2 million, as non-cash
oil and gas revenues.
61
Also, in the second quarter of 2002, the Company completed the sale of its
claims against Enron for $2.5 million and reported a pre-tax gain of that
amount.
In the fourth quarter of 2003, Callon entered into two natural gas collar
contracts which are listed below:
Collars
Volumes per Quantity Floor Ceiling
Product Month Type Price Price Period
----------- ----------- -------- ------- ------- ----------
Natural Gas 100,000 MMBtu $ 5.25 $7.25 12/03-03/04
Natural Gas 100,000 MMBtu $ 5.00 $7.20 01/04-03/04
These contracts are accounted for as cash flow hedges under SFAS 133. The
Company recognized an increase of $52,500 in oil and gas sales related to the
settlements of such collars in the twelve month period ended December 31, 2003.
The fair value of these collar contracts at December 31, 2003 was recorded on
the balance sheet as a liability in the amount of $30,400.
In the first quarter of 2004, Callon entered into various derivative contracts
which are listed in the table below:
Swaps
Volumes per Quantity
Product Month Type Average Period
--------- ----------- -------- --------- -----------
Oil 30,000 Bbls $ 31.29 02/04-01/05
Oil 15,000 Bbls $ 30.00 04/04-03/05
Oil 15,000 Bbls $ 30.00 07/04-12/04
Collars
Average Average
Volumes per Quantity Floor Ceiling
Product Month Type Price Price Period
----------- ----------- -------- --------- -------- -----------
Oil 45,000 Bbls $ 29.33 $ 32.17 02/04-01/05
Oil 15,000 Bbls $ 30.00 $ 32.50 02/04-10/04
Natural Gas 500,000 MMBtu $ 5.00 $ 6.08 04/04-11/04
Natural Gas 100,000 MMBtu $ 5.00 $ 5.60 06/04-11/04
Natural Gas 300,000 MMBtu $ 5.00 $ 6.91 12/04-03/05
These contracts will be accounted for as cash flow hedges under SFAS 133.
7. COMMITMENTS AND CONTINGENCIES
As described in Note 10, 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, 2003, total estimated site
restoration, dismantlement and abandonment costs were approximately $7.4
million, 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 Notes 2 and 8.
62
From time to time, the Company, as part of the Consolidation and other capital
transactions, entered into registration rights agreements whereby certain
parties to the transactions are entitled to require the Company to register
common stock of the Company owned by them with the Securities and Exchange
Commission for sale to the public in firm commitment public offerings and
generally to include shares owned by them, at no cost, in registration
statements filed by the Company. Costs of the offering will not include broker's
discounts and commissions, which will be paid by the respective sellers of the
common stock.
The Company is involved in various claims and lawsuits incidental to its
business. In the opinion of management, the ultimate liability thereunder, if
any, will not have a material adverse effect on the financial position or
results of operations of the Company.
The Company may be required to retroactively pay royalties to the Minerals
Management Service on one of the Company's properties which could reduce
revenues and reserves. The Company's Medusa deepwater property is eligible for
royalty suspensions pursuant to the Deep Water Royalty Relief Act. However, the
federal offshore leases covering this property contains "price threshold"
provisions for oil and gas prices. Under this "price threshold" provision, if
the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or
gas during a fiscal year exceeds the price threshold for oil or gas,
respectively, then royalties on the associated production must be paid to the
Minerals Management Service (MMS) at the rate stipulated in the lease. The price
thresholds are adjusted annually by the implicit price deflator for the GDP. The
determination of whether or not royalties are due as a result of the average
NYMEX price exceeding the price threshold is made during the first quarter of
the succeeding year. Any royalty payments due must be made shortly after this
determination is made. If a royalty payment is due for all production during a
year as a result of exceeding the price threshold, the lessee is required to
make monthly royalty payments during the succeeding fiscal year for the
succeeding year's production. If at the end of any year the average NYMEX price
is below the price threshold, the lessee can apply for a refund for any
associated royalties paid during that year and the lessee will not be required
to pay royalties monthly during the succeeding year for the succeeding year's
production.
The thresholds and the average NYMEX prices are calculated by the MMS. The
average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of
natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per
barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the
adjustment for the 2003 GDP implicit price deflator. As a result the Company
will pay royalties related to 2003 gas production for Medusa, which commenced
production in late November 2003 and will make monthly royalty payments for 2004
gas production during 2004. The actual liability for 2004 oil royalties, if any,
cannot be determined until after the end of 2004.
In the year succeeding the year in which any of the Company's properties became
subject to royalties as the result of the average NYMEX price exceeding the
price threshold, the portion of reserves attributable to potential future
royalties would not be included in a year-end reserve report. However, if the
average NYMEX prices were below the price thresholds in subsequent years, our
reserves would be increased to reflect reserves previously attributed to future
royalties. As a result, reported oil and gas reserves could materially increase
or decrease, depending on the relation of price thresholds versus the average
NYMEX prices. The reduction in revenues resulting from an obligation to pay
these royalties and subsequent reduction of proved reserves could have a
material adverse effect on the Company's results of operations and financial
condition. The Company's reserve report as of December 31, 2003 excluded gas
reserves for Medusa that are subject to MMS royalties as a result of the average
2003 NYMEX price for gas exceeding the price threshold. Oil reserves in this
reserve report were not impacted since the 2003 average NYMEX price was below
the threshold.
63
The Company's activities are subject to federal, state and local laws and
regulations governing environmental quality and pollution control. Although no
assurances can be made, the Company believes that, absent the occurrence of an
extraordinary event, compliance with existing federal, state and local laws,
rules and regulating the release of materials in the environment or otherwise
relating to the protection of the environment will not have a material effect
upon the capital expenditures, earnings or the competitive position of the
Company with respect to its existing assets and operations. The Company cannot
predict what effect additional regulation or legislation, enforcement polices
thereunder, and claims for damages to property, employees, other persons and the
environment resulting from the Company's operations could have on its
activities.
8. ASSET RETIREMENT OBLIGATIONS
As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The
impact of adopting the statement resulted in a gain of $181,000, net of tax,
which is reported as a cumulative effect of change in accounting principle.
Approximately $30.3 million was recorded as the present value of asset
retirement obligations on January 1, 2003 with the adoption of SFAS 143 related
to the Company's oil and gas properties. Interest is accreted on this amount and
reported as accretion expense in the Consolidated Statements of Operations.
Assets, primarily short-term U.S. Government securities, of approximately $7.4
million at December 31, 2003, are recorded as restricted investments. These
assets are held in abandonment trusts dedicated to pay future abandonment costs
of oil and gas properties in which the Company has sold a net profits interest.
If there is any excess of trust assets over abandonment costs, the excess will
be distributed to the net profits interest owners.
The following table summarizes the activity for the Company's asset retirement
obligation:
TWELVE MONTHS ENDED
DECEMBER 31, 2003
-------------------
Asset retirement obligation at beginning of period $ --
Liability recognized in transition 30,251
Accretion expense 2,884
Net profits interest accretion 371
Liabilities incurred 3,649
Liabilities settled (2,847)
Revisions to estimate (617)
-------
Asset retirement obligation at end of period 33,691
Less: current retirement obligation (8,571)
-------
Long-term retirement obligation $25,120
=======
Pro forma net income and earnings per share are not presented for the 12 months
ended December 31, 2002 or 2001 because the pro forma application of SFAS 143 to
the prior periods would not result in pro forma net income and earnings per
share materially different from the actual amounts reported for the periods in
the accompanying Consolidated Statements of Operations.
64
9. 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,
----------------------------------------
2003 2002 2001
--------- --------- ---------
(IN THOUSANDS)
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance $ 762,918 $ 704,937 $ 589,549
Property acquisition costs 1,154 1,471 1,713
Exploration costs 21,390 17,851 85,782
Development costs 33,972 43,151 34,980
SFAS 143-Asset Retirement Obligation 18,002 -- --
Medusa Spar transaction (33,542) -- --
Sale of mineral interests (982) (4,492) (7,087)
--------- --------- ---------
End of period balance $ 802,912 $ 762,918 $ 704,937
========= ========= =========
Unevaluated Properties (excluded from
amortization) -
Beginning of period balance $ 40,997 $ 37,560 $ 47,653
Additions 5,228 5,802 8,760
Capitalized interest 4,862 5,289 4,879
Transfers to evaluated (16,836) (7,654) (23,732)
--------- --------- ---------
End of period balance $ 34,251 $ 40,997 $ 37,560
========= ========= =========
Accumulated depreciation, depletion
and amortization-
Beginning of period balance $ 426,254 $ 399,339 $ 378,589
Provision charged to expense 28,195 26,915 20,750
Cumulative effect of change in accounting
principle (7,449) -- --
--------- --------- ---------
End of period balance $ 447,000 $ 426,254 $ 399,339
========= ========= =========
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 $8.6 million incurred in 2003, $7.1 million incurred
in 2002 and $18.5 million incurred in 2001 and prior. These costs are directly
related to the acquisition and evaluation of unproved properties and major
development projects. The excluded costs and related reserves are included in
the amortization base as the properties are evaluated and proved reserves are
established or impairment is determined. The Company expects that the majority
of these costs will be evaluated over the next three to five-year period.
Depletion per unit-of-production (thousand cubic feet of gas equivalent)
amounted to $2.03, $1.73 and $1.37 for the years ended December 31, 2003, 2002,
and 2001, respectively.
Under the full-cost accounting rules of the SEC, the Company reviews the
carrying value of its proved oil and gas properties each quarter. Under these
rules, capitalized costs of proved oil and gas properties net of accumulated
depreciation, depletion and amortization (DD&A) and deferred income taxes, may
not exceed the present value of estimated future net cash flows from proved oil
and gas reserves, discounted at 10
65
percent, plus the lower of cost or fair value of unproved properties included in
the costs being amortized, net of related tax effects. These rules generally
require pricing future oil and gas production at the unescalated market price
for oil and gas at the end of each fiscal quarter and require a write-down if
the "ceiling" is exceeded, unless prices recover sufficiently before the date of
the auditor's report. Given the volatility of oil and gas prices, it is
reasonably possible that the Company's estimate of discounted future net cash
flows from proved oil and gas reserves could change in the near term. If oil and
gas prices decline significantly, even if only for a short period of time, it is
possible that writedowns of oil and gas properties could occur in the future.
See Note 13 for information regarding the SEC inquiries concerning the Company's
proved reserves.
10. 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
(see Note 7) 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 disbursement of
funds to 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. Estimated future revenues and costs associated
with the NPI and the Trusts are also excluded from the oil and gas reserve
disclosures at Note 13. As of December 31, 2003 and 2002, the Trusts' assets
(all cash and investments) totaled $7,420,000 and $6,896,000 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. SFAS 143, discussed in Note 2 and 8, does not allow the
Abandonment Trusts' assets to be used to offset the associated abandonment
liability. The Company did not record any income or loss associated with the
Trust asset or abandonment liability as a result of adoption of SFAS 143.
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.
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,
66
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.
11. 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 $562,000,
$611,000 and $595,000 in the years 2003, 2002 and 2001, respectively.
The 1994 Stock Incentive Plan (the "1994 Plan"), approved by the
shareholders in 1994, 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 of 10 years from the 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 was approved by the shareholders in 1997 and
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 the 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 to
2,200,000 shares. The excess of the market price over the exercise price
on the approval date of the amendment is amortized over the three-year
vesting period of the options. Compensation costs of $27,000, $416,000 and
$611,000 were recognized in 2003, 2002 and 2001, respectively, related to
these options.
On February 14, 2002, the Board of Directors of the Company approved and
adopted the 2002 Stock Incentive Plan (the "2002 Plan"). Pursuant to the
2002 Plan, 350,000 shares of common stock shall be reserved for issuance
upon the exercise of options or for grants of stock options, stock
appreciation rights or units, bonus stock, or performance shares or units.
This Plan qualified as a "broadly based" plan under the provisions of the
New York Stock
67
Exchange's rules and regulations and therefore did not require shareholder
approval. Because the 2002 Plan is a broadly based plan, the aggregate
number of shares underlying awards granted to officers and directors
cannot exceed 50% of the total number of shares underlying the awards
granted to all employees during any three-year period.
In 2002, the Company awarded 300,000 shares of restricted stock from the
1996 and the 2002 Plan and 70,500 from treasury shares to be issued as
vested. The issuance of the restricted stock using treasury shares did not
require shareholder approval pursuant to the New York Stock Exchange's
rules and regulations, and therefore shareholder approval was not sought.
These shares will generally vest to the recipients over a three-year
period (one-third in each year) beginning in November 2002. The deferred
compensation portion of this grant will be amortized to expense over the
vesting period. The non-cash amortization expense in, 2003 and 2002 was
$454,000 and $496,000, respectively.
In 1997, the Board of Directors authorized the implementation of the
Callon Petroleum Company 1997 Employee Stock Purchase Plan (the "1997
Purchase Plan"), which was approved by the Company's shareholders at the
1997 Annual Meeting. The Plan provides eligible employees of the Company
with the opportunity to acquire a proprietary interest in the Company
through participation in a payroll deduction-based employee stock purchase
plan. An aggregate of 250,000 shares of common stock have been reserved
for issuance over the 10-year term of the 1997 Purchase Plan. The purchase
price per share at which common stock will be purchased on the
participant's behalf on each purchase date within an offering period is
equal to 85 percent of the fair market value per share of common stock.
A summary of the status of the Company's stock option plans for the three most
recent years and changes during the years then ended is presented in the table
and narrative below:
2003 2002 2001
--------------------- ---------------------- ----------------------
WTD AVG WTD AVG WTD AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
---------- -------- ---------- --------- ---------- --------
Outstanding, beginning of year 2,520,417 $ 9.90 2,332,667 $ 10.84 2,304,167 $ 10.83
Granted (at market) 30,000 5.12 310,000 4.45 30,000 11.61
Exercised (500) 4.10 -- -- (1,500) 9.00
Forfeited (99,050) 9.74 (122,250) 14.10 -- --
Expired -- -- -- -- -- --
---------- -------- ---------- ------- ---------- -------
Outstanding, end of year 2,450,867 $ 9.84 2,520,417 $ 9.90 2,332,667 $ 10.84
========== ======== ========== ======= ========== =======
Exercisable, end of year 2,262,067 $ 10.31 2,224,334 $ 10.57 2,057,977 $ 10.80
========== ======== ========== ======= ========== =======
Weighted average fair value of
options granted (at market) $ 2.97 $ 2.44 $ 5.80
========== ========== ==========
68
The following table sets forth additional information regarding options
outstanding at December 31, 2003. Contractual life and exercise prices represent
weighted averages for options outstanding and options exercisable.
Options Outstanding Options Exercisable
------------------------------------- ----------------------
Range of Number Contractual Exercise Number Exercise
exercise prices Outstanding Life (years) Price Exercisable Price
------------------ ----------- ------------ -------- ----------- --------
$ 3.70 to $ 6.41 315,200 8.6 $ 4.47 126,400 $ 4.74
$ 9.00 to $ 12.28 2,070,667 3.9 $ 10.53 2,070,667 $ 10.53
$ 13.56 to $ 15.31 65,000 4.3 $ 14.16 65,000 $ 14.16
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for options granted during the years presented are as follows:
2003 2002 2001
------ ------ ------
Risk free interest rate 4.0% 3.7% 4.5%
Expected life (years) 5.0 5.0 5.0
Expected volatility 65.3% 61.0% 43.9%
Expected dividends -- -- --
12. 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
69
converted into 1,036,098 shares of the Company's Common Stock. Any non-cash
premium negotiated in excess of the conversion rate was recorded as additional
preferred stock dividends and excluded from the Consolidated Statements of Cash
Flows.
The Company adopted a stockholder rights plan on March 30, 2000, designed to
assure that the Company's stockholders receive fair and equal treatment in the
event of any proposed takeover of the Company and to guard against partial
tender offers, squeeze-outs, open market accumulations, and other abusive
tactics to gain control without paying all stockholders a fair price. The rights
plan was not adopted in response to any specific takeover proposal. Under the
rights plan, the Company declared a dividend of one right ("Right") on each
share of the Company's Common Stock. Each Right will entitle the holder to
purchase one one-thousandth of a share of a Series B Preferred Stock, par value
$0.01 per share, at an exercise price of $90 per one one-thousandth of a share.
The Rights are not currently exercisable and will become exercisable only in the
event a person or group acquires, or engages in a tender or exchange offer to
acquire, beneficial ownership of 15 percent or more (one existing stockholder
was granted an exception for up to 21 percent) of the Company's Common Stock.
After the Rights become exercisable, each Right will also entitle its holder to
purchase a number of common shares of the Company having a market value of twice
the exercise price. 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.
13. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 2003, 2002 and 2001
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions. These estimates have been adjusted (per SEC
guidelines) to exclude the volumetric production payment described in Note 2.
There are numerous uncertainties inherent in establishing quantities of proved
reserves. The following reserve data represents estimates only and should not be
construed as being exact. In addition, the standard measure of discounted future
net cash flows should not be construed as the current market value of the
Company's oil and gas properties or the cost that would be incurred to obtain
equivalent reserves. Reference the discussion in Note 7 regarding the Deep Water
Royalty Relief Act and the potential loss of reserves.
Beginning in October 2002, the Company received a series of inquiries from the
SEC regarding its Annual Report on Form 10-K for the year ended December 31,
2001 requesting supplemental information concerning its operations in the Gulf
of Mexico. The comment letters requested information about the procedures the
Company used to classify its deepwater reserves as proved and requested that the
Company's financials be restated to reflect the removal of the Boomslang
reserves as proved for all prior periods during which such reserves were
reported as proved. The Company has reviewed the SEC comments with its
independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston,
Texas. Both Huddleston & Co. and Callon believe that such deepwater reserves are
properly classified as proved. If the SEC requires the Company to retroactively
classify Boomslang as an unproved property through December, 2002, the Company
would be required to restate its financial position, results of operations, and
supplemental oil and gas reserve data from 1999 through 2003. The Company has
responded to all of the SEC inquiries.
70
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,
------------------------
2003 2002 2001
---- ---- ----
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period 24,043 30,209 33,382
Revisions to previous estimates (1) (8,699) (a) (2,290)
Purchase of reserves in place -- -- --
Sales of reserves in place (65) -- (624)
Extensions and discoveries -- 2,759 (a) 14
Production (268) (226) (273)
------- ------- -------
End of period 23,709 24,043 30,209
======= ======= =======
Natural Gas (MMcf):
Beginning of period 91,539 120,299 129,922
Revisions to previous estimates (6,407) (19,284) (a) (4,578)
Purchase of reserves in place -- -- --
Sales of reserves in place (49) -- (1,296)
Extensions and discoveries 1,923 3,584 (a) 7,483
Production (12,315) (13,060) (11,232)
------- ------- -------
End of period 74,691 91,539 120,299
======= ======= =======
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period 1,056 885 2,192
======= ======= =======
End of period 9,919 1,056 885
======= ======= =======
Natural Gas (MMcf):
Beginning of period 37,631 51,221 63,982
======= ======= =======
End of period 31,415 37,631 51,221
======= ======= =======
(a) For the year ended December 31, 2002, revisions to previous estimates and
extensions and discoveries were adjusted from the amounts reported in the
Company's Annual Report on Form 10-K dated March 27, 2003 to reflect the
subsequent changes in properties that were part of property acquisitions or
exploratory drilling programs and should have been classified as extensions
instead of revisions.
71
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 (approximately $5.99 per Mcf for natural gas and $30.50 per Bbl for oil
for the 2003 disclosures, $4.80 per Mcf and $34.22 per Bbl for 2002 disclosures,
and $2.58 per Mcf and $20.10 per Bbl for 2001 disclosures) at each date
presented and have not been escalated. 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,
--------------------------------------
2003 2002 2001
----------- ----------- ----------
(IN THOUSANDS)
Future cash inflows $ 1,170,118 $ 1,261,571 $ 883,145
Future costs -
Production (219,421) (165,559) (220,857)
Development and net abandonment (111,850) (125,813) (191,369)
----------- ----------- ----------
Future net inflows before income taxes 838,847 970,199 470,919
Future income taxes (89,567) (119,020) (30,315)
----------- ----------- ----------
Future net cash flows 749,280 851,179 440,604
10% discount factor (230,254) (295,133) (185,747)
----------- ----------- ----------
Standardized measure of discounted
future net cash flows $ 519,026 $ 556,046 $ 254,857
=========== =========== ==========
CHANGES IN STANDARDIZED MEASURE
YEARS ENDED DECEMBER 31,
----------------------------------
2003 2002 2001
---------- --------- ---------
(IN THOUSANDS)
Standardized measure - beginning of period $ 556,046 $ 254,857 $ 671,197
Sales and transfers, net of production costs (62,396) (38,375) (45,672)
Net change in sales and transfer prices,
net of production costs (41,011) 401,837 (604,391)
Exchange and sale of in place reserves (1,226) -- (5,850)
Purchases, extensions, discoveries, and improved
recovery, net of future production and
development costs incurred 25,632 8,456 9,358
Revisions of quantity estimates (18,018) (103,452) (23,314)
Accretion of discount 62,394 26,915 90,978
Net change in income taxes 16,460 (53,608) 224,290
Changes in production rates, timing and other (18,855) 59,416 (61,739)
--------- --------- ---------
Standardized measure - end of period $ 519,026 $ 556,046 $ 254,857
========= ========= =========
72
14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-----------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
2003
Total revenues $ 21,351 $ 18,482 $ 15,152 $ 19,156
Total costs and expenses 19,503 19,477 18,270 26,623
Income tax expense (benefit) 647 (348) (1,092) 9,225
Income (loss) before cumulative effect of change
in accounting principle 1,201 (647) (2,026) (16,700)
Net income (loss) 1,382 (647) (2,026) (16,700)
Net income (loss) per common share-basic:
Net income (loss) available to common before
cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24)
Cumulative effect of change in accounting principle,
net of tax 0.01 0.00 0.00 0.00
-------- ------- ------- -------
Net income (loss) per share $ 0.08 ($0.07) ($0.17) ($1.24)
Net income (loss) per common share-diluted:
Net income (loss) available to common before
cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24)
Cumulative effect of change in accounting principle,
net of tax 0.01 0.00 0.00 0.00
-------- ------- ------- -------
Net income (loss) per share $ 0.08 ($0.07) (0.17) (1.24)
2002
Total revenues $ 11,624 $ 20,489 $ 15,786 $ 19,209
Total costs and expenses 15,399 16,888 17,786 19,606
Income tax expense (benefit) (1,321) 1,260 (700) (139)
Net income (loss) (2,454) 2,341 (1,300) (258)
Net income (loss) per share-basic (0.21) 0.15 (0.12) (0.04)
Net income (loss) per share-diluted (0.21) 0.15 (0.12) (0.04)
73
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no disagreements with the independent auditors on any matters of
accounting principles or practices, financial statement disclosure, or auditing
scope or procedures.
ITEM 9A. CONTROLS AND PROCEDURES
The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and
15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term
refers to the controls and procedures of a company that are designed to ensure
that information required to be disclosed by a company in the reports that it
files or submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified by the Securities and Exchange
Commission. Our management, including our Chief Executive Officer and Chief
Financial Officer, has evaluated the effectiveness of our disclosure controls
and procedures as of the end of the period covered by this annual report. Based
upon that evaluation, our Chief Executive Officer and Chief Financial Officer
have concluded that our disclosure controls and procedures were effective as of
the end of the period covered by this annual report.
There were no changes to our internal control over financial reporting during
our last fiscal quarter that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
74
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
For information concerning Item 10, see the definitive proxy statement of Callon
Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
For information concerning Item 11, see the definitive proxy statement of Callon
Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.
For information concerning the security ownership of certain beneficial owners
and management, see the definitive proxy statement of Callon Petroleum Company
relating to the Annual Meeting of Stockholders on May 6, 2004 which will be
filed with the Securities and Exchange Commission and is incorporated herein by
reference.
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information as of December 31, 2003 regarding the
number of shares of Common Stock that may be issued under the Company's equity
compensation plans.
Plan Category Number of securities to be Weighted-average Number of securities
issued upon exercise of exercise price of remaining available for
outstanding options, outstanding options, future issuance under
warrants and rights warrants and rights equity compensation
plans (excluding
securities reflected
in column (a)
(A) (B) (C)
--- --- ---
Equity compensation
plans approved by
security holders(1) 2,264,667 $10.30 197,140
Equity compensation
plans not approved by
security holders (2) 186,200 $ 4.33 75,317
--------- ------ -------
Total 2,450,867 $ 9.84 272,457
========= ====== =======
(1) Represents the Callon Petroleum Company 1994 and the 1996 Stock
Incentive Plans which were approved by the shareholders in prior
years. Remaining shares available for future
75
issuance listed in column (c) does not include 56,000 shares of
restricted stock awarded in 2002 which have not yet vested.
(2) Represents the Callon Petroleum Company 2002 Stock Incentive Plan
adopted by the Company on February 14, 2002. The plan qualified as a
"broadly based" plan under the provisions of the New York Stock
Exchange rules and regulations and therefore did not require
shareholder approval. Remaining shares available for future issuance
listed in column (c) does not include 34,484 shares of restricted
stock awarded in 2002 which have not yet vested.
See Note 10 to the Consolidated Financial Statements for a description of the
material provisions of each equity compensation plan under which our equity
securities are authorized for issuance that was adopted without the approval of
shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information concerning Item 13, see the definitive proxy statement of Callon
Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
For information concerning Item 14, see the definitive proxy statement of Callon
Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
76
PART IV.
ITEM15. 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 37 through
63.
Report of Independent Auditors
Consolidated Balance Sheets as of the Years Ended December 31, 2003 and
2002
Consolidated Statements of Operations for the Three Years in the Period
Ended December 31, 2003
Consolidated Statements of Stockholders' Equity for the Three Years in the
Period Ended December 31, 2003
Consolidated Statements of Cash Flows for the Three Years in the Period
Ended December 31, 2003
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
3.2 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)
3.3 Certificate of Amendment to Certificate of Incorporation of
the Company
77
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 as corrected (included as part of Exhibit 3.1)
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 Indenture for the Company's 10.125% Senior Subordinated Notes
due 2002 dated as of July 31, 1997 (incorporated by reference
from Exhibit 4.1 of the Company's Registration Statement on
Form S-4, filed September 25, 1997, Reg. No. 333-36395)
4.6 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 14, 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 99.1 of the
Company's Registration Statement on Form 8-A, filed April 6,
2000, File No. 001-14039)
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, File No.
001-14039)
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, File No. 001-14039)
4.10 Warrant dated as of June 29, 2001 entitling Duke Capital
Partners, LLC to purchase common stock from the Company.
(incorporated by reference to Exhibit 4.11 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30,
2001, File No. 001-14039)
78
4.11 First Supplemental Indenture, dated June 26, 2002, to
Indenture between Callon Petroleum Company and American Stock
Transfer & Trust Company dated July 31, 1997. (incorporated by
reference to Exhibit 4.1 of the Company's Current Report on
Form 8-K dated June 26, 2002, File No. 001-14039)
4.12 Form of Warrant entitling certain holders of the Company's
10.125% Senior Subordinated Notes due 2002 to purchase common
stock from the Company (incorporated by reference to Exhibit
4.13 of the Company's Form 10-Q for the period ended June 30,
2002, File No. 001- 14039)
4.13 Second Supplemental Indenture, dated September 16, 2002, to
Indenture between Callon Petroleum Company and American Stock
Transfer & Trust Company dated July 31, 1997. (incorporated by
reference to Exhibit 4.1 of the Company's Current Report on
Form 8-K dated September 16, 2002, File No. 001-14039)
4.14 Form of Warrants dated December 8, 2003 and December 29, 2003
entitling lenders under the Company's $185 million amended and
restated senior unsecured credit agreement dated December 23,
2003 to purchase common stock from the Company
9. Voting trust agreement
None.
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between
the Company and NOCO Enterprises, L. P. (incorporated by
reference from Exhibit 10.2 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.2 Counterpart to Registration Rights Agreement by and between
the Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
reference from Exhibit 10.2 of the Company's Report on Form
10-K for the fiscal year ended December 31, 2000, File No.
001-14039)
10.3 Registration Rights Agreement dated September 16, 1994 between
the Company and Callon Stockholders (incorporated by reference
from Exhibit 10.3 of the Company's Registration Statement on
Form 8-B filed October 3, 1994)
10.4 Callon Petroleum Company 1994 Stock Incentive Plan
(incorporated by reference from Exhibit 10.5 of the Company's
Registration Statement on Form 8-B filed October 3, 1994)
10.5 Consulting Agreement between the Company and John S. Callon
dated June 19, 1996 (incorporated by reference from Exhibit
10.10 of the Company's Registration Statement on Form S-1,
filed November 5, 1996, Reg. No. 333-15501)
10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the
Post-Effective Amendment No. 1 to the Company's Registration
Statement on Form S-8, filed February 5, 1999, Reg. No.
333-29537)
79
10.7 Purchase and Sale Agreement between Callon Petroleum Operating
Company and Murphy Exploration Company, dated May 26, 1999
(incorporated by reference from Exhibit 10.11 on Form S-2,
filed June 14, 1999, Reg. No. 333-80579)
10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended
on May 9, 2000 (incorporated by reference from Appendix I of
the Company's Definitive Proxy Statement of Schedule 14A filed
March 28, 2000)
10.9 Credit Agreement dated as of October 30, 2000 between the
Company and First Union National Bank, as administrative agent
for the lenders (incorporated by reference from Exhibit 10.2
of the Company's Quarterly Report on Form 10-Q for the period
ended September 30, 2000, File No. 001-14039)
10.10 Credit Agreement dated as of June 29, 2001 between the Company
and Duke Capital Partners, LLC, as Administrative Agent
(incorporated by reference to Exhibit 10.01 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30,
2001, File No. 001-14039)
10.11 Second Amendment to Credit Agreement by and among the Company
and First Union National Bank, as Administrative Agent,
effective as of June 29, 2001 (incorporated by reference to
Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 2001, File No. 001-14039)
10.12 Conveyance of Overriding Royalty Interest from the Company to
Duke Capital Partners, LLC, dated June 29, 2001 (incorporated
by reference to Exhibit 10.03 of the Company's Quarterly
Report on Form 10-Q for the period ended June 30, 2001, File
No. 001-14039)
10.13 Callon Petroleum Company 2002 Stock Incentive Plan
(incorporated by reference to Exhibit 10.13 of the Company's
Annual Report on Form 10-K for the year ended December 31,
2001, File No. 001-14039)
10.14 Change of Control Severance Compensation Agreement by and
between Callon Petroleum and John S. Weatherly dated January
1, 2002 (incorporated by reference to Exhibit 10.14 of the
Company's Annual Report on Form 10-K for the year ended
December 31, 2001, File No. 001-14039)
10.15 Change of Control Severance Compensation Agreement by and
between Callon Petroleum Company and Fred L. Callon, dated
January 1, 2002 (incorporated by reference to Exhibit 10.15 of
the Company's Annual Report on Form 10-K for the year ended
December 31, 2001, File No. 001-14039)
10.16 Change of Control Severance Compensation Agreement by and
between Callon Petroleum Company and Dennis W. Christian,
dated January 1, 2002 (incorporated by reference to Exhibit
10.16 of the Company's Annual Report on Form 10-K for the year
ended December 31, 2001, File No. 001-14039)
80
10.17 First Amended and Restated Credit Agreement dated as of June
30, 2002, among Callon Petroleum Company, each of the lenders
that is a signatory thereto, Wachovia Bank National
Association, as administrative agent, and Union Bank of
California, N.A., as documentation agent (incorporated by
reference to Exhibit 10.1 of the Company's Form 10-Q for the
period ended June 30, 2002, File No. 001-14039)
10.18 Amended and Restated Credit Agreement Dated as of December 23,
2003, among Callon Petroleum Company, each of the lenders that
is signatory thereto or which becomes a signatory thereto; and
Wells Fargo Bank, National Association, a National Banking
Association, as administrative agent
10.19 Medusa Spar Agreement dated as of August 8, 2003, among Callon
Petroleum Operating Company, Murphy Exploration & Production
Company-USA and Oceaneering International, Inc.
10.20 Credit Agreement dated as of December 18, 2003 among Medusa
Spar LLC, The Bank of Nova Scotia, as Administrative Agent,
Bank One, N.A., Sun Trust Bank, as Syndication Agents and
other Lenders Party.
10.21 The Retirement Package and Release Agreement made, entered
into and effective March 9, 2004 between Callon Petroleum
Company and Dennis W. Christian.
10.22 The Retirement Package and Release Agreement made, entered
into and effective March 9, 2004 between Callon Petroleum
Company and Kathy G. Tilley.
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*
14. Code of Ethics
14.1 Code of Ethics for Chief Executives Officer and Senior
Financial Officers
16. Letter re change in certifying accountant*
81
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 Ernst & Young LLP
24. Power of attorney*
31. Rule 13a-14(a) Certifications
31.1 Certification of Chief Executive Officer pursuant to Rule
13(a)-14(a)
31.2 Certification of Chief Financial Officer pursuant to Rule
13(a)-14(a)
32. Section 1350 Certifications
32.1 Certification of Chief Executive Officer pursuant to Rule
13(a)-14(b)
32.2 Certification of Chief Financial Officer pursuant to Rule
13(a)-14(b)
99. Additional Exhibits*
- ----------
*Inapplicable to this filing.
(b) Reports on Form 8-K.
Current Report on Form 8-K dated November 11, 2003, reporting Item 12.
Results of Operations and Financial Condition
Current Report on Form 8-K dated December 1, 2003, reporting Item 9.
Regulation FD Disclosure
Current Report on Form 8-K dated December 8, 2003, reporting Item 9.
Regulation FD Disclosure
Current Report on Form 8-K dated January 23, 2004 reporting Item 5. Other
Events
82
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 15, 2004 /s/ Fred L. Callon
--------------------------------------
Fred L. Callon (principal executive
officer, director)
Date: March 15, 2004 /s/ John S. Weatherly
--------------------------------------
John S. Weatherly (principal
financial officer)
Date: March 15, 2004 /s/ Rodger W. Smith
--------------------------------------
Rodger W. Smith (principal
accounting officer)
Date: March 15, 2004 /s/ John S. Callon
--------------------------------------
John S. Callon (director)
Date: March 15, 2004 /s/ Leif Dons
--------------------------------------
Leif Dons (director)
Date: March 15, 2004 /s/ Robert A. Stanger
--------------------------------------
Robert A. Stanger (director)
Date: March 15, 2004 /s/ John C. Wallace
--------------------------------------
John C. Wallace (director)
Date: March 15, 2004 /s/ B. F. Weatherly
--------------------------------------
B. F. Weatherly (director)
Date: March 15, 2004 /s/ Richard O. Wilson
--------------------------------------
Richard O. Wilson (director)
83
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 15, 2004 By: /s/ John S. Weatherly
--------------------------------------
John S. Weatherly, Senior Vice
President and Chief Financial Officer
84
INDEX TO 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
3.2 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)
3.3 Certificate of Amendment to Certificate of Incorporation of
the Company
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 as corrected (included as part of Exhibit 3.1)
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 Indenture for the Company's 10.125% Senior Subordinated Notes
due 2002 dated as of July 31, 1997 (incorporated by reference
from Exhibit 4.1 of the Company's Registration Statement on
Form S-4, filed September 25, 1997, Reg. No. 333-36395)
4.6 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 14, 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 99.1 of the
Company's Registration Statement on Form 8-A, filed April 6,
2000, File No. 001-14039)
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, File No.
001-14039)
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, File No. 001-14039)
4.10 Warrant dated as of June 29, 2001 entitling Duke Capital
Partners, LLC to purchase common stock from the Company.
(incorporated by reference to Exhibit 4.11 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30,
2001, File No. 001-14039)
4.11 First Supplemental Indenture, dated June 26, 2002, to
Indenture between Callon Petroleum Company and American Stock
Transfer & Trust Company dated July 31, 1997. (incorporated by
reference to Exhibit 4.1 of the Company's Current Report on
Form 8-K dated June 26, 2002, File No. 001-14039)
4.12 Form of Warrant entitling certain holders of the Company's
10.125% Senior Subordinated Notes due 2002 to purchase common
stock from the Company (incorporated by reference to Exhibit
4.13 of the Company's Form 10-Q for the period ended June 30,
2002, File No. 001- 14039)
4.13 Second Supplemental Indenture, dated September 16, 2002, to
Indenture between Callon Petroleum Company and American Stock
Transfer & Trust Company dated July 31, 1997. (incorporated by
reference to Exhibit 4.1 of the Company's Current Report on
Form 8-K dated September 16, 2002, File No. 001-14039)
4.14 Form of Warrants dated December 8, 2003 and December 29, 2003
entitling lenders under the Company's $185 million amended and
restated senior unsecured credit agreement dated December 23,
2003 to purchase common stock from the Company
9. Voting trust agreement
None.
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between
the Company and NOCO Enterprises, L. P. (incorporated by
reference from Exhibit 10.2 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.2 Counterpart to Registration Rights Agreement by and between
the Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
reference from Exhibit 10.2 of the Company's Report on Form
10-K for the fiscal year ended December 31, 2000, File No.
001-14039)
10.3 Registration Rights Agreement dated September 16, 1994 between
the Company and Callon Stockholders (incorporated by reference
from Exhibit 10.3 of the Company's Registration Statement on
Form 8-B filed October 3, 1994)
10.4 Callon Petroleum Company 1994 Stock Incentive Plan
(incorporated by reference from Exhibit 10.5 of the Company's
Registration Statement on Form 8-B filed October 3, 1994)
10.5 Consulting Agreement between the Company and John S. Callon
dated June 19, 1996 (incorporated by reference from Exhibit
10.10 of the Company's Registration Statement on Form S-1,
filed November 5, 1996, Reg. No. 333-15501)
10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the
Post-Effective Amendment No. 1 to the Company's Registration
Statement on Form S-8, filed February 5, 1999, Reg. No.
333-29537)
10.7 Purchase and Sale Agreement between Callon Petroleum Operating
Company and Murphy Exploration Company, dated May 26, 1999
(incorporated by reference from Exhibit 10.11 on Form S-2,
filed June 14, 1999, Reg. No. 333-80579)
10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended
on May 9, 2000 (incorporated by reference from Appendix I of
the Company's Definitive Proxy Statement of Schedule 14A filed
March 28, 2000)
10.9 Credit Agreement dated as of October 30, 2000 between the
Company and First Union National Bank, as administrative agent
for the lenders (incorporated by reference from Exhibit 10.2
of the Company's Quarterly Report on Form 10-Q for the period
ended September 30, 2000, File No. 001-14039)
10.10 Credit Agreement dated as of June 29, 2001 between the Company
and Duke Capital Partners, LLC, as Administrative Agent
(incorporated by reference to Exhibit 10.01 of the Company's
Quarterly Report on Form 10-Q for the period ended June 30,
2001, File No. 001-14039)
10.11 Second Amendment to Credit Agreement by and among the Company
and First Union National Bank, as Administrative Agent,
effective as of June 29, 2001 (incorporated by reference to
Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 2001, File No. 001-14039)
10.12 Conveyance of Overriding Royalty Interest from the Company to
Duke Capital Partners, LLC, dated June 29, 2001 (incorporated
by reference to Exhibit 10.03 of the Company's Quarterly
Report on Form 10-Q for the period ended June 30, 2001, File
No. 001-14039)
10.13 Callon Petroleum Company 2002 Stock Incentive Plan
(incorporated by reference to Exhibit 10.13 of the Company's
Annual Report on Form 10-K for the year ended December 31,
2001, File No. 001-14039)
10.14 Change of Control Severance Compensation Agreement by and
between Callon Petroleum and John S. Weatherly dated January
1, 2002 (incorporated by reference to Exhibit 10.14 of the
Company's Annual Report on Form 10-K for the year ended
December 31, 2001, File No. 001-14039)
10.15 Change of Control Severance Compensation Agreement by and
between Callon Petroleum Company and Fred L. Callon, dated
January 1, 2002 (incorporated by reference to Exhibit 10.15 of
the Company's Annual Report on Form 10-K for the year ended
December 31, 2001, File No. 001-14039)
10.16 Change of Control Severance Compensation Agreement by and
between Callon Petroleum Company and Dennis W. Christian,
dated January 1, 2002 (incorporated by reference to Exhibit
10.16 of the Company's Annual Report on Form 10-K for the year
ended December 31, 2001, File No. 001-14039)
10.17 First Amended and Restated Credit Agreement dated as of June
30, 2002, among Callon Petroleum Company, each of the lenders
that is a signatory thereto, Wachovia Bank National
Association, as administrative agent, and Union Bank of
California, N.A., as documentation agent (incorporated by
reference to Exhibit 10.1 of the Company's Form 10-Q for the
period ended June 30, 2002, File No. 001-14039)
10.18 Amended and Restated Credit Agreement Dated as of December 23,
2003, among Callon Petroleum Company, each of the lenders that
is signatory thereto or which becomes a signatory thereto; and
Wells Fargo Bank, National Association, a National Banking
Association, as administrative agent
10.19 Medusa Spar Agreement dated as of August 8, 2003, among Callon
Petroleum Operating Company, Murphy Exploration & Production
Company-USA and Oceaneering International, Inc.
10.20 Credit Agreement dated as of December 18, 2003 among Medusa
Spar LLC, The Bank of Nova Scotia, as Administrative Agent,
Bank One, N.A., Sun Trust Bank, as Syndication Agents and
other Lenders Party.
10.21 The Retirement Package and Release Agreement made, entered
into and effective March 9, 2004 between Callon Petroleum
Company and Dennis W. Christian.
10.22 The Retirement Package and Release Agreement made, entered
into and effective March 9, 2004 between Callon Petroleum
Company and Kathy G. Tilley.
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*
14. Code of Ethics
14.1 Code of Ethics for Chief Executives Officer and Senior
Financial Officers
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 Ernst & Young LLP
24. Power of attorney*
31. Rule 13a-14(a) Certifications
31.1 Certification of Chief Executive Officer pursuant to Rule
13(a)-14(a)
31.2 Certification of Chief Financial Officer pursuant to Rule
13(a)-14(a)
32. Section 1350 Certifications
32.1 Certification of Chief Executive Officer pursuant to Rule
13(a)-14(b)
32.2 Certification of Chief Financial Officer pursuant to Rule
13(a)-14(b)
99. Additional Exhibits*
- ----------
*Inapplicable to this filing.